ML053560194

Response to NRC Round 2 Requests for Additional Information Related to Technical Specifications Change No. TS-431 - Request for Extended Power Uprate Operation

ML053560194
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 MC3812, TVA-BFN-TS-431
Download: ML053560194 (190)

Text

Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000 Brian O'Grady Vice President, Browns Ferry Nuclear Plant TVA-BFN-TS-431 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 No. 50-259 Tennessee Valley Authority )

BROWNS FERRY NUCLEAR PLANT (BFN) - UNIT I - RESPONSE TO NRC ROUND 2 REQUESTS FOR ADDITIONAL INFORMATION RELATED TO TECHNICAL SPECIFICATIONS (TS) CHANGE NO. TS-431 - REQUEST FOR EXTENDED POWER UPRATE OPERATION (TAC NO. MC3812)

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 Unit 1 Extended Power Uprate (EPU) license amendment application.

TVA submitted the BFN Unit 1 EPU application to the NRC by letter dated June 28, 2004 (Reference 2). TVA supplemented that application 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 Unit 1 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 complete its review of those subject areas. Specifically, NRC Request EMEB-B.6 requested 9C(3c:

Pfnt on Srecud paw

U.S. Nuclear Regulatory Commission Page 2 December 19, 2005 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.6 by February 1, 2006.

NRC Request SPSB-A.1 1 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.9 through EMEB-B-13 request detailed information concerning development of the acoustical analyses, BFN Steam Dryer loading definition, 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.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.

TVA is providing similar information regarding the Units 2 and 3 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.

U.S. Nuclear Regulatory Commission Page 3 December 19, 2005 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, M. H. Chernoff to TVA, "Browns Ferry Nuclear Plant, Unit 1 -

Request for Additional Information for Extended Power Uprate (TS-431)(TAC No. MC3812)," dated October 3, 2005.

2. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1

- Proposed Technical Specifications (TS) Change TS - 431- Request for License Amendment Extended Power Uprate (EPU) Operation," dated June 28, 2004.

3. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit I 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 No. MC3812)," dated February 23, 2005.

4. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1

- Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS-431- Request for Extended Power Uprate Operation (TAC No. MC3812)," dated April 25, 2005.

5. TVA letter, W. D. Crouch to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 - Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS - 431 - Request For License Amendment - Extended Power Uprate (EPU) Operation (TAC No.

MC3812)," 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 UNIT 1 DOCKET NO. 50-259 RESPONSE TO NRC ROUND 2 REQUEST FOR ADDITIONAL INFORMATION RELATED TO TECHNICAL SPECIFICATIONS (TS) CHANGE NO. TS - 431-REQUEST FOR EXTENDED POWER UPRATE OPERATION By letter dated June 28, 2004 (Reference 1), TVA submitted to the NRC a license amendment application requesting authorization for Extended Power Uprate (EPU) operation for Browns Ferry Nuclear Plant (BFN) Unit 1. TVA supplemented that application 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 Unit 1 EPU application. 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 Reply to EMCB-C.1 BFN Unit 1 is in a recovery effort following an extended shutdown period. As part of that effort, TVA is developing the Unit 1 Flow-Accelerated Corrosion (FAC) program.

The BFN Units 2 and 3 FAC program was developed following Unit 1 shutdown in 1985; therefore, previous information pertaining to predicted and measured wall thinning does not exist for Unit 1. However, the BFN Unit 1 program is being developed based on the BFN Units 2 and 3 programs and will be managed by the same BFN organization.

Therefore, the BFN Units 2 and 3 FAC program predictive capability is representative of the BFN Unit 1 program when fully developed and implemented. The following discussion provides the requested details from the current FAC program for BFN Units 2 and 3.

A sample list of components and measured versus predicted thickness for CHECWORKSTM modeled components at current thermal power operating conditions E-1

(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 (Tpreqa at the time of last inspection. Predicted thickness was calculated by CHECWORKS M 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 (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, "CHECWORKSTMSteam/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 (TprefTmeas 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"; 3CON11 B-13E Tnom=0.438" and Tinit=0.630; 3HDV4A4-5E Tnom=0.375" and Tinft=0.445").

Table EMCB-C.1-1 Predicted Versus Measured Wall Thickness at Current BFN Operating Conditions Tom TIM, T.m T.,, T.eas 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 2CON1 1A-3P 0.438 0.480 0.399 0.409 3%

2 5 Condensate: 4FWH to 3FWH 2CON1 1A-4E 0.438 0.630 0.535 0.374 -30%

2 6 Condensate: 4FWH to 3FWH 2CON11A-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%

E-2

Table EMCB-C.1-1 Predicted Versus Measured Wall Thickness at Current BFN Operating Conditions Tn.m T t, T., Tp..d T.e Unit Item System Component (in.) (in.) (in.) (in.) Variance 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%

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 1B-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 1C-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 1E 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 1FWH 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.

E-3

TVA Reply to EMCB-C.2 BFN Unit 1 is in the progress of a recovery effort following an extended shutdown period. As part of that effort, TVA is developing the Unit 1 Flow-Accelerated Corrosion (FAC) program. The BFN Units 2 and 3 FAC program was developed following Unit 1 shutdown in 1985; therefore, previous data does not exist for Unit 1. However, the predicted effects of EPU on BFN Units 2 and 3 flow-accelerated corrosion are representative of that expected for BFN Unit 1.

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.

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 Oxvyen: 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 Cycle 12 (NSS input to turbine cycle 3463 MWt) and post-EPU CHECWORKS predictions at Cycle 14 (NSS input to turbine cycle 3964.4 MWt).

E-4

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 1 Notes 2 1 Heater Drains: 19.4% This is due to an 11 OF temperature increase towards the 3FWH to 4FWH FAC peak (to 2620F) and a 20% increase in flow rate (to 4.1 Mlb/hr). The steam quality remained unchanged at 0%.

2 2 Condensate: 18.5% This is due to an 80 F 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 2050 F) 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 1OaF (to 3440 F); 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 262 0F) 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 7°F 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%.

3 3 Heater Drains: 10.1% This is due to an 11°F temperature increase towards the 4FWH to Flash FAC peak (to 2050 F) and a 19% increase in flow rate (to 4.9 Tank Mlb/hr). The steam quality remained unchanged at 0%.

E-5

Table EMCB-C.2-1 Piping Segments at EPU Conditions With Greatest Predicted Increase in Wear Avg Wear Rate Unit Item System Change' Notes 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 10F (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 130F (to 3570F); 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). The predicted effects of EPU on BFN Units 2 and 3 flow-accelerated corrosion are representative of that expected for BFN Unit 1.

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

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 Replv 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 Unit 1 containment. 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 Unit 1 containment.

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

E-6

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 BFN Unit is credited for providing to the grid.

TVA Reply to EEIB-B.11.b The unit manufacturer's reactive capability curves along with uprated MW ratings were provided to TVA's Transmission Planning Organization so that the unit can be properly modeled for use in their planning and stability studies. This study credits a post-event contribution of +360/-150 MVAR for Unit 1 uprated.

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 of +360/-150 MVAR for Unit 1 uprated.

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.

E-7

TVA Replv 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.

NRC Request EEIB-B.2 Page 6-1 of Enclosure 4 of the June 28, 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 1,2 and 3 licensing basis.

State whether BFN Unit 1 is consistent with GDC-1 7 or the Atomic Energy Commission Criterion 39.

TVA Reolv 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?

E-8

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.

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 Unit 1 Generator Ratings Parameter Current Uprated Generator Output (MWe) 1098 1280 Rated Voltage (kV) 22 22 Power Factor 0.93 0.962 Generator Output (MVA) 1280 1330

b. Isonhase Bus & Cooling 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:

E-9

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 (650 C) New rating (650C)

Unit 1 3 X 448 MVA FOA 3 X 500 MVA OFAF

d. Unit Auxiliary/Start-un 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 24/32/40 MVA ONFA/FOA lA No Change USST 1B 24/32 MVA OA/FA No Change CSST A 21.9/29.2/36.5 MVA ONFA/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 1 Brown Boveri Type: DR36V1750D Rated Max Voltage: 24 kV Rated Continuous Current: 36 kA Rated Continuous Current: 37 kA Rated S.C. Current: 165 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 Unit 1 Onsite AC Distribution System Loads Power Uprate FSystem/Component Pre-Uprate Condition I Requirements __l_Remarks Reactor Recirculation 6650 HP @100% core 8657 HP @ 105% core flow Note 1 Pumps flow @ 105% OLTP 120% OLTP 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. Pre-Uprate Condition based on BFN Units 2 and 3 data.

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

E-1 1

NRC Request EEIB-B.6 Provide the coping duration and recovery time expected from a station blackout (10 CFR 50.63). Discuss whether there is any change in the coping duration and recovery time for 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 Unit 1 is 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 28, 2004, submittal and Page 6-2 of Enclosure 5 of the June 28, 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 Unit 1.

TVA Reply 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 480V 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 480V shutdown boards, and five 480V RMOV boards. Both of these standby AC supply and distribution E-12

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, of Enclosure 4 of the June 28, 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/cm2 (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.

TVA Reply 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 E-13

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 CoePlate 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.

NRC Request EMEB-B.1 Discuss the plans to implement an Inservice Testing (IST) Program for restart of BFN Unit 1 that is consistent with the licensee's American Society of Mechanical Engineers (ASME) Code of record and incorporates 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 indicate any resulting adjustments to the IST Program resulting from that evaluation.

TVA Reliv 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).

E-14

The purpose of the ASME IST 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 operating pressure and temperature for EPU conditions will result in the following:

• Increase to MSRV setpoints due to a 30 psig increase in the maximum operating pressure in the RPV. The ASME IST Program test procedures will ensure that the MSRVs are tested to verify that they open within a percentage of the required setpoints and that corrective actions are implemented if they do not.

• Increase in the pressure that HPCI and RCIC must be able to operate against due to a 30 psig increase in the maximum operating pressure in the RPV. The ASME IST Program test procedures will ensure that the HPCI and RCIC turbines are tested to verify that they meet design and Technical Specification requirements at EPU conditions. Corrective actions will be implemented if they do not.

• Increase in the reference test pressure for the SLC pumps for the 24-month test due to a 30 psig increase in maximum operating pressure in the RPV. The ASME IST Program test procedures will ensure that the SLC pumps are tested to verify that they meet design and Technical Specification requirements at EPU conditions. Corrective actions will be implemented if they do not.

The scope of the BFN ASME IST Program will not be affected by EPU changes for Unit 1. There will be no new components added or existing components deleted within the boundaries of the existing ASME IST Program. Also, no changes to any test periodicities will be needed. Therefore, no changes (except for the implementing test procedures discussed above) are anticipated in the ASME IST Program as a result of EPU for Unit 1.

E-15

NRC Request EMEB-B.2 Section 3.7, Main Steam Isolation Valves, of Enclosure 4 of the June 28, 2004, submittal states that the 24-percent increase in steam-flow rate will result in a decrease in the stroke time for the main steam isolation valves (MSIVs) but that the stroke time will continue to satisfy the Technical Specifications. Describe the basis for this assumption using design, test, and operational experience of the MSIVs.

TVA Replv to EMEB-B.2 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 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 Unit 1 surveillance procedures will 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 will be 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.3 Section 4.1.3, Containment Isolation, of Enclosure 4 of the June 28, 2004, submittal states that parameters for air-operated valves (AOVs) and solenoid-operated valves E-16

(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.3 The Unit 1 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 Unit 1 AOV and SOV containment isolation valve capability included consideration of valve functional characteristics and potential changes to operating requirements. Valve capability was confirmed by comparing valve design pressures/

temperatures to calculated EPU accident conditions. Unit 1 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). The design temperatures and pressures of each Unit 1 AOV and SOV containment isolation valve were compared to the design requirements of the corresponding Units 2 and 3 valves and determined to be equivalent to, or bounded by the design requirements for the corresponding Units 2 and 3 valves. Through this comparison, the existing valve design was determined to be acceptable. 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 (Reference 1) and the response to EMEB-B.2 for further discussion concerning the MSIVs. The table below provides examples of the evaluation performed.

E-17

Table EMEB-B.4-1 Unit 1 Primary Containment AOV/SOV Evaluations1 Accident Accident temperature pressure Valve Valve (OF) (psig) Valve ID Description Current/EPU CurrentlEPU 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 335.8/335.4 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.

1. As discussed above, the BFN Unit 1 AOV/SOV evaluations were based on a comparison of BFN Unit 1 valve design requirements to the corresponding BFN Units 2 and 3 valve design requirements.

The information contained in this table was extracted from the BFN Units 2 and 3 AOV/SOV evaluations.

NRC Request EMEB-B.4 Section 4.1.4, Generic Letter (GL) 89-10 Program, of Enclosure 4 of the June 28, 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, the 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.4 Since BFN Unit 1 was in an extended shutdown when Generic Letter 89-10 was issued, TVA is performing its initial implementation of GL 89-10 as part of restart activities.

TVA described development of the BFN Unit 1 GL 89-10 program in a letter dated May 5, 2004 (Reference 7). Consistent with implementation of the BFN Units 2 and 3 GL 89-10 programs, many BFN Unit 1 GL 89-10 MOVs have been or are being modified to ensure valve operability. Since operation at EPU conditions was planned as part of Unit 1 restart activities, GL 89-10 calculations were performed at EPU conditions.

Therefore, BFN Unit 1 pre-EPU MOV capability data does not exist, quantitatively, to identify the specific impact on these valves due to the change associated with EPU.

E-18

The BFN MOV Program is established and prior to restart of BFN Unit 1, will be procedurally implemented. 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 Each MOV is the BFN GL 89-10 program has been evaluated at EPU conditions. The table below provides examples of the MOV evaluations performed, and represents evaluations performed on the valves, as-modified for Unit 1 restart as applicable.

Table EMEB-B.4-1 Examples of BFN Unit 1 Safety-Related MOV Evaluations Current Valve Valve description Safety function Parameter Affected Value EPU Value Line Pressure NA 102 psig RBCCW Primary Differential Pressure 102 psid FCV-70-47 Containment Outlet Close Accident Temperature 2400 F Valve Required thrust 6,568 Ibs Operator Capability 37,345 lbs Margin 469%

RHR Shutdown Supply Line Pressure Differential Pressure NA 133 psig 133 psid FCV-74-47 Cooling SupplyClose Accident Temperature 1280F FCC4-7outbarden Coe Required thrust 28,131 lbs Containment Operator Capability 50,074 lbs Isolation Valve Margin 78%

Line Pressure NA 495 psig RHR System Loop I Differential Pressure 495 psid FCV-74-53 Inboard Injeteioo Open Accident Temperature 1828 0F Ineto VC-43Ibarde pn Required thrust 181,062 lbs Valve Operator Capability 246,018 lbs Margin 36%

Line Pressure NA 407 psig Differential Pressure 377 psid FCV-75-50 Test Return Line Accident Temperature 120OF Isolation Required thrust 32,533 lbs Operator Capability 75,693 Ibs Margin 133%

E-19

Table EMEB-B.4-1 Examples of BFN Unit 1 Safety-Related MOV Evaluations Current Valve Valve description Safety function Parameter Affected Value EPU Value FCV-01 -55 Main Steam Drain Close Line Pressure NA 1169 psig Line Isolation valve Differential Pressure 1169 psid Accident Temperature 140OF Required thrust 8,696 lbs Operator Capability 15,051 lbs Margin 73%

FCV-73-03 HPCI Steam Line Close Line Pressure NA 1169 psig Primary Containment Differential Pressure 1169 psid Isolation Valve Accident Temperature 207.1 OF Required thrust 70,419 lbs Operator Capability 75,211 lbs Margin 7%

A similar evaluation was performed for all of the valves in the GL 89-10 program. All of the MOVs are capable of operation at EPU conditions after the necessary modifications are implemented. Fourteen design changes (DCNs) were prepared to upgrade/replace Unit 1 GL 89-10 MOVs. All of the modifications will be implemented before Unit 1 restart.

NRC Request EMEB-B.5 Section 4.1.6, GL 95-07, of Enclosure 4 of the June 28, 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. The licensee provided a response to GL 95-07, Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves, in a submittal dated May 11, 2004. 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.5 For the restart of Unit 1, a review of all of the safety related power operated valves was performed to determine which valves might be susceptible to pressure locking and thermal binding. The scope of the TVA Unit 1 GL 95-07 program, evaluations and evaluation results was provided to the NRC in the May 11, 2004 letter (Reference 8).

The review identified the following:

One High Pressure Coolant Injection System valve was susceptible to thermal binding. This valve will be replaced with a double disc valve prior to Unit 1 restart. Double disc gate valves are not susceptible to thermal binding.

E-20

Five safety related power operated gate valves will be modified prior to Unit 1 restart to preclude the potential for pressure locking. The reactor side disc face of these valves will be modified by drilling a hole in the disc face into the cavity between disc faces to avoid pressure locking.

These modifications will ensure that the pressure locking and thermal binding concerns described in GL 95-07 are resolved prior to Unit 1 restart.

The following example discusses valves that were modified for GL 95-07 and how EPU affects them. The Low Pressure Coolant Injection valves 1-FCV-74-53(67) are subject to pressure locking. These valves are a flex wedge design, are normally closed and have to open to perform their safety function. The reactor side is exposed to high pressure and temperature conditions while the reactor is in operation. This may cause potential pressure locking when the valve has to open. Therefore, the reactor side disc faces of these valves are being modified by drilling a 1/4" hole in the disc face into the cavity between the disc faces to avoid pressure locking. These valves are not subject to thermal binding. The modifications to these valves are being performed to support Unit 1 restart and are similar to the modifications performed for Units 2 and 3. The modifications were developed based on EPU design parameters (ambient temperature, operating pressure and temperature), and therefore, will support operation at EPU conditions.

NRC Request EMEB-B.6 Section 10.4.3, Main Steam Line, Feedwater and Reactor Recirculation Piping Flow Induced Vibration Testing, of Enclosure 4 of the June 28, 2004, submittal discusses the plans for vibration monitoring during initial plant operation for the new EPU operating conditions. Discuss in more detail, the procedures for avoiding adverse flow effects during power escalation and after achieving EPU conditions, including specific hold points and duration, inspections, plant walkdowns, vibration data collection methods and locations, planned data evaluation, and decision criteria for reducing plant power level or initiating plant shutdown.

TVA Reply to EMEB-B.6 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, E-21

• 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 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 E-22

previously shown to be acceptable until further evaluation of the data could be completed.

NRC Request EMEB-B.7 In the submittal dated February 23, 2005, the licensee lists modifications planned to support EPU operation on pages El -17 to 22. 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 Reply to EMEB-B.7 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.

NRC Request EMEB-B.8 In the submittal dated February 23, 2005, the licensee indicates on page E1-21 that the GL 89-10 MOVs will be modified to accommodate the 30 psi increased reactor operating pressure. The licensee states that MOV setup will be accomplished per MOVATS. Address its implementation of GL 89-10 and GL 96-05 for the safety-related MOVs.

TVA Replv to EMEB-B.8 By letter dated May 5, 2004 (Reference 7), TVA described implementation of GL 89-10 for BFN Unit 1. That letter identified the valves included within the scope of the program, which is consistent with the BFN Units 2 and 3 MOV program scope.

BFN Unit 1 is implementing the GL 89-10 program as part of plant restart activities. In conjunction with implementation of GL 89-10, TVA is engaged in design and modification activities to support the restart of Unit 1. Accordingly, the scope of design and modification activities associated with GL 89-10 MOVs include evaluations and changes necessary to support fulfillment of GL 89-10 program requirements, evaluations and changes necessary to support operation of Unit 1 at EPU conditions, and evaluation and modifications as necessary to support closure of any other restart commitments potentially affecting GL 89-10 program valves. GL 89-10 modifications implemented previously for BFN Units 2 and 3 were used as inputs to the BFN Unit 1 GL 89-10 MOV design process, in addition to evaluation of requirements to support operation at EPU conditions. Therefore, modifications and replacements were selected E-23

to address known issues identified during resolution of GL 89-10 for BFN Units 2 and 3, and ensure operability of GL 89-10 MOVs at EPU conditions.

Resolution of GL 89-10 for BFN Units 2 and 3 resulted in modification or replacement of many of the GL 89-10 program MOVs. Additionally, BFN Units 2 and 3 GL 89-10 program MOVs were evaluated during the 105% power uprate, to address changes in process conditions, and environmental temperature increases associated with that uprate effort, including the 30 psig increase in reactor operating pressure. As discussed above, these changes have been addressed in the design evaluation of BFN Unit 1 GL 89-10 program valves to support BFN Unit 1 restart and operation at EPU conditions.

A total of 14 design changes (DCNs) were prepared to upgrade/replace Unit 1 GL 89-10 MOVs to ensure that they can perform their design functions at EPU conditions and meet the requirements of GL 89-10, as well as GL 95-07, "Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves." 17 MOVs are being replaced; 34 MOVs are having their actuators replaced; and all GL 89-10 MOVs are receiving SMARTSTEMs to facilitate future testing. The new Limitorque operators are being furnished with long life grease. All valves modified will be tested as part of the post modification testing program before being declared operable. Diagnostic equipment to be utilized in the performance of static and differential pressure testing will be determined by the specific application. Testing equipment to be used may include, but is not limited to the MOVATS Torque Thrust Cells, Stem Strain Transducer, Stem Strain Ring, and MCC data analysis system. As discussed in Reference 7, BFN Unit 1 will implement the Joint Owners Group recommended Generic Letter 96-05 Motor Operated Valves Periodic Verification Program, as described in Topical Report NEDC 32719 (MPR Report 1807), and begin testing during the first refueling outage after restart.

NRC Request EMEB-B.9 In the submittal dated February 23, 2005, the licensee states on page El -26 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 discuss possible alternative methods to identify excitation sources.

TVA Reply to EMEB-B.9 Requests EMEB-B 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.

E-24

Initially, a steam dryer evaluation for EPU conditions was performed for BFN and the evaluation was provided as Enclosure 9 to the June 28, 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-1 39,

• 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,

• 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, E-25

• 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 9, 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 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 SRN (ERVs, SVs, SRNV 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 SRN design rather than an assortment of different designs.

Similar subscale tests will be conducted for BFN SR/Vs 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 10, 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 E-26

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.

NRC Request EMEB-B.10 In the submittal dated February 23, 2005, the licensee states on page El -27 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 its steam dryer at BFN Unit 1 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 E-27

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 -30, 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 Replv 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.

NRC Request EMEB-B.12 On page El -28 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 dryer 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.

E-28

NRC Request EMEB-B.13 On page El -30 of the submittal dated February 23, 2005, the licensee lists proposed modifications to the steam dryer based on lessons learned from recent BWR dryer modifications. Provide detailed descriptions and diagrams of the proposed modifications to the steam dryer. Also, describe the stress analysis performed for the modified steam dryer, and the resulting changes in predicted stress in comparison to the licensee's acceptance criteria at significant locations on the steam dryer.

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 -33 to 36 of the submittal dated February 23, 2005, the licensee discusses the potential impact of temperature changes from resulting from EPU operation on mechanical equipment environmental qualification. The discussion focuses on the 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 on the actuator thrust/torque output because some motors lose capability at elevated temperatures. For EPU, an evaluation (utilizing the same methodology that was used to create the "Operator Requirements and Capabilities" calculations) was performed to determine the required thrust and the motor capability of the MOV under EPU conditions. Examples of the temperature conditions and MOV capability are provided in the table below.

E-29

Table EMEB-B.14-1 Examples of Impact of Environmental Temperature on BFN Unit 1 Safety-Related MOVs1 Ambient Thrust Output Safety temperature in the safety Valve Function action EPU direction EPU Notes 1-FCV-01-55 Main Steam Drain Close 1400F 15,051 psi The motor has Line Isolation adequate margin to Valve close this valve under EPU conditions.

FCV-23-46 RHRSW Throttle Open 1700F 60,327 psi The motor has Valve to RHR B adequate margin to Heat Exchanger open this valve under EPU conditions.

FCV-70-47 RBCCW Primary Close 2400F 37,345 psi The motor has Containment adequate margin to Isolation Valve close this valve under EPU conditions.

FCV-71-25 RCIC Lube Oil Open 2470F 10,053 psi The motor has Cooling Water adequate margin to Supply Valve open this valve under IlI __I_ EPU conditions.

1. BFN Unit 1 has developed its GL 89-10 program as part of restart activities, and has evaluated MOV capability based on operation at EPU conditions. Therefore, BFN Unit 1 pre-EPU MOV capability data does not exist, quantitatively, to identify the specific impact on these valves due to the change associated with EPU.

Each MOV in the Unit 1 GL 89-10 program was evaluated assuming operation at EPU conditions. With the modifications being performed as part of the Unit 1 GL 89-10 program, 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.

NRC Request IPSB-B.1 Section 8.6, Normal Operations Off-Site Doses, of Enclosure 4 of the June 28, 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 E-30

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 Reply 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.

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 11). This can be compared to the limit of 100 E-31

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 28, 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 1 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-cooling 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 Unit 1?

TVA Replv 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 12).

AST for BFN Units 1, 2, and 3 was approved by the NRC in Reference 13. 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 12, the results of the revision of post-accident mission doses demonstrated that the previous calculated 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, submittal states that the increase in the activated corrosion product activity will be 3-percent higher than the original design basis activity. Provide the basis for this estimated increase. Since Unit 1 has been shutdown for 20 years, how was the quantity of loose corrosion products (i.e., available for transport into the reactor) estimated?

E-32

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.3-1 Activated Corrosion and Fission Products Design-Basis EPU Reactor Water Reactor Water Item (PCi/ml') (PCilg)

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 9 at 4 0C.

The determination of activated corrosion products in the reactor coolant was performed the same way for all three units. Although Unit 1 has been shutdown for 20 years, this is considered adequate based on several reasons. Unit 1 is currently undergoing reactor pressure vessel and system cleaning efforts. The Unit 1 reactor core will have at least 672 assemblies of new fuel with the balance of no more than 92 assemblies of once and twice burned, but ultrasonically cleaned, fuel. During normal operation and refueling outages, the fuel serves as a significant source of corrosion products for release to the water. Also, Unit 1 plans to use the same micron-rated condensate demineralizer filters as Units 2 and 3 so the corrosion product source from the feedwater system is expected to be consistent with Units 2 and 3. Unit 1 has also taken significant steps in the reduction of the cobalt source term. These steps include E-33

removing stellite (cobalt) from approximately 74 valves and using flame-hardened turbine blades in lieu of cobalt-faced blades.

Evaluation of the expected carryover rate for EPU conditions do not result in moisture carryover values above 0.13 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.9, 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 28, 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. Since Unit 1 has been shut down for 20 years, how were the pre-EPU crud levels determined? 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%). This approach is also applicable to Unit 1 since any differences in initial crud levels in the RCS associated with the extended shutdown will be addressed during the cycle operation prior to refueling activities. Therefore, it would be anticipated that the crud levels in the RCS at the end of cycle operation at EPU would be similar for all three units.

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 Describe the controls implemented throughout the extended shutdown of Unit 1 to minimize the corrosion of reactor water systems.

E-34

TVA Reply to IPSB-B.5 Detailed information concerning the BFN Unit 1 Plant Lay-up and Equipment Preservation Program (BFN Unit 1 Lay-up Program) was provided in several submittals to the NRC in support of the BFN Units 1, 2, and 3 license renewal applications. An overview of the program is provided below. Further information is available in the references identified.

Unit 1 systems and the Unit 1 portion of common systems not involved in the operation of Units 2 and 3 were placed in lay-up during the extended outage. Some of the BFN Unit 1 systems were maintained in the Plant Lay-up and Equipment Preservation Program (BFN Unit 1 Lay-up Program); other systems were maintained outside of this program. The Unit 1 systems were placed in one of the following four environments during lay-up:

• Components maintained under the BFN Unit 1 Lay-up Program in dry lay-up where the target environment was < 60 percent relative humidity;

• Components maintained under the BFN Unit 1 Lay-up Program in wet lay-up with an internal environment of flowing, air-saturated demineralized water;

• Components not maintained under the BFN Unit 1 Lay-up Program with an internal environment of moist air. For these components there were no moisture controls during lay-up; and

• Components not maintained under the BFN Unit 1 Lay-up Program with an internal environment of either treated or raw water for an extended period of time.

The reactor vessel and internals were maintained under the BFN Unit 1 Layup Program in wet layup. One Reactor Water Cleanup System filter demineralizer was in service at approximately 100 gpm to maintain reactor coolant water quality per TVA Procedure Cl-13.1 "Chemistry Program." The wet lay-up flow path was Reactor Water Cleanup System suction from the 'A' Recirculation Loop through a short section of Residual Heat Removal System piping with a small portion of Reactor Water Cleanup System suction flow coming from the Reactor Vessel bottom head drain line, through Reactor Water Cleanup System inlet piping to the Reactor Water Cleanup System filter demineralizer returning via the Reactor Water Cleanup System effluent piping which returns to the Reactor Pressure Vessel via the 'B' Feedwater line. A portion of the Reactor Water Cleanup System effluent flow was routed to provide flow through Control Rod Drive System components. Chemistry limits for the wet layup components for conductivity, chloride and sulfate were 1.5 pS/cm, 15 ppb, and 15 ppb respectively.

Further details are provided in the following references:

TVA letter dated February 19, 2004 (Reference 14) provides a detailed discussion of the BFN Unit 1 Layup Program, identifies the system layup condition maintained during E-35

the shutdown period, and compares the aging effects and aging management programs of the Unit 1 layup configuration to the Units 2 and 3 operating configurations.

TVA letter dated July 19, 2004 (Reference 15) clarified that the Unit 1 Spent Fuel Pool Cooling System remained in operation during the shutdown limit, subject to the chemistry limits in the BFN Unit 1 Technical Requirements Manual.

TVA letter dated October 8, 2004 (Reference 16) provided further details concerning BFN Unit 1 systems, including chemistry controls maintained during plant shutdown, and inspections planned to assess system material condition.

TVA letter dated January 31, 2005 (Reference 17) provided additional information concerning chemistry controls, and identified inspections, replacements, and refurbishments being performed to support BFN Unit 1 restart.

TVA letter dated May 18, 2005 (Reference 18) provided further information concerning chemistry controls and impacts on the systems in wet layup within the BFN Unit 1 Layup Program, and details concerning system piping examinations performed on BFN Unit 1 systems.

TVA letter dated May 27, 2005 (Reference 19) provided further information concerning potential corrosion mechanisms in BFN Unit 1 systems, and further details concerning inspections being performed prior to restart of the unit under the BWRVIP program, specifically in regard to crevice locations.

TVA letter dated June 6, 2005 (Reference 20) provided additional information concerning the BFN Unit 1 suppression pool layup during the plant shutdown period, and inspections and repairs made to suppression pool coatings.

NRC Request IPSB-B.6 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 Unit 1.

TVA RenIv to IPSB-B.6 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 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 E-36

EPU conditions. Since Unit 1 is restarting with relatively low levels of crud on the fuel (i.e. at least 672 new assemblies of the 764 total assemblies) and the feedwater crud source should be similar to Units 2 and 3 due to use of similar condensate demineralizer filters and the addition of a tenth condensate demineralizer vessel for all three units, crud bursts should not be a significant problem. 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.7 Section 6.3.3, Radiation Levels, of Enclosure 4 of the June 28, 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.7 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.

E-37

NRC Request IPSB-B.8 Section 8.5.1, Normal Operations, of Enclosure 4 of the June 28, 2004, submittal states that, due to the conservative shielding design, the increase in radiation levels resulting from EPU will not affect 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 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 Section 8.5.2, Normal Post-Operations, of Enclosure 4 of the June 28, 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 E-38

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.9 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.10 Enclosure 8, Table 2 of the June 28, 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. Considering that Unit 1 has been shut down for approximately 20 years, justify why the original full startup test STP 1 is not appropriate.

TVA Reply to IPSB-B.10 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.

For Unit 1, parts (b) & (c) of the original STP 1 (determination of adequacy for equipment, procedures, and techniques & evaluation of fuel, equipment, and instrument calibration) are not intended to be performed as part of EPU. These items were intended to ensure readiness for the initial plant startup and are not associated with E-39

EPU conditions. Appropriate startup test activities during Unit 1 startup from the extended shutdown up to CLTP will be performed as part of the restart testing program for Unit 1 (see Reference 21). The information provided in Reference 1 and Reference 3 is intended to identify those tests required for EPU conditions.

NRC Request IPSB-B.1 1 Enclosure 8, Table 2 of the June 28, 2004, submittal states that the objective of test STP 2, Radiation Measurements, is not applicable to EPU and is not required. The 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. Considering that Unit 1 has been shut down for approximately 20 years, and the uncertainties of predicting the activated corrosion source term, justify why the original full startup test STP 2 is not appropriate to provide a new baseline for dose data on activity buildup.

TVA Reply to IPSB-B.1 1 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 measured 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 N1 6 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, E-40

• 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.

For Unit 1, part (a) of the original STP 2 (demonstration of background radiation levels prior to operation) is not intended to be performed as part of EPU. The current radiation surveys which are maintained for Unit 1 establish the background radiation levels in the plant prior to Unit 1 operation. Additionally, appropriate radiation surveys during Unit 1 startup from the extended shutdown up to the Current License Thermal Power level will be performed as part of the restart testing program for Unit 1 (see Reference 21). The information provided in initial application (Reference 1) and revised in TVA's April 25, 2005 submittal (Reference 3) is intended to indicate those tests required for EPU conditions.

NRC Request IPSB-B.12 Summarize the major Unit 1 plant hardware or system modifications involved in the requested EPU and discuss the change in occupational doses associated plant operation with the modifications in place.

TVA Reply to IPSB-B.12 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.8 and IPSB-B.9.

NRC Request SPLB-A.1 Section 10.5.5 of the Updated Final Safety Analysis Report (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.

E-41

TVA Reply 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.

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. The ADHR is being modified as part of Unit 1 restart activities to provide this capability to Unit 1.

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 offload scenarios assuming a loss of offsite power and (for the batch off load 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.

E-42

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 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 off load) 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 off loaded in eight batches, discharged at 24-month intervals. Full core off loads assume the same as the batch off load 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 off loading 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 off load 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 E-43

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 1500 F 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 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 / Parameter Batch Offload Offload Configuration 1: One train each of FPCC and ADHR in Service Peak Heat Load (Mbtu/hr) 27.6 57.4 Configuration 2: One train each of FPCC and RHR supplemental fuel pool cooling mode In service Peak Heat Load (Mbtu/hr) F 23.7 44.0 1 See PUSAR Table 6-3 for applicable notes.

E-44

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 temperature / 100F RBCCW water temperature (single HX)

RHR HX Design Heat Removal Rate @ 1250 F and 5Mlb/hr on shell 44.0 side and 800F and 2.25 Mlb/hr on tube side)

ADHR HX Design Heat Removal Rate @ 1250F and 3420 gpm on 70.3 process fluid side and 75.40 F 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, 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 125 0 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.

E-45

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.

NRC Request SPLB-A.5 In Section 6.4.1.1, of Enclosure 4 of the June 28, 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 Reply 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 28, 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 E-46

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 Replv 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 RHR heat exchanger is unchanged. The RHRSW maximum inlet temperature corresponds to an ultimate heat sink temperature of 95 0F. 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 126.30F to 132.70F due to the suppression pool temperature increase. The maximum outlet temperature of 132.79F remains below the current design limit of 150°F 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 Reply 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 E-47

components to the ultimate heat sink. These systems were evaluated under EPU conditions and there are no changes to the flow rates of these systems, 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 remains within the existing design parameters.

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 of 3362 F. This value bounds the peak Unit 1 EPU drywell temperature of 335.40 F.

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.

The system that is potentially impacted for water hammer and two-phase flow is the RBCCW system. An evaluation of the RBCCW coolers was performed and determined that two phased flow and water hammer during a LOCA or MSLB with a concurrent loss of offsite power is not a concern for EPU.

All of the primary containment penetrations were evaluated for susceptibility to thermal overpressurization. Several penetrations were identified as being susceptible to overpressurization. These were evaluated on a case-by-case basis. Several modifications to valves and changes to procedures will be required to ensure that the penetrations will acceptable (for example the drywell floor and equipment drain sump discharge lines are susceptible to overpressurization). This condition will be alleviated by drilling holes in the respective valve discs for the implementation of the BFN GL 96-06 program). All modifications will be implemented before Unit 1 restart.

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 E-48

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 Reply 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.

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 28, 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 E-49

sufficient time is available for the operator to perform the necessary actions.

Upon reviewing Table 6-5, Browns Ferry 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 (peak clad temperature (PCT)), degrees F = 1428 (EPU)

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

• 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 3 [sic].

TVA Reply 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 4 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 28, 2004, submittal states that:

.[f]or this [bounding PCT] case, the time available to the operator to open three MSRVs [main steam relief valves] is reduced from 30 minutes to 25 minutes at the EPU conditions. This reduction in the time available does not have any effect because the current procedures require this action to be completed within 20 minutes. Although the analysis assumes the time available to perform this operator action is reduced by five minutes .. ., five minutes of margin remain compared to the present analysis.

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."

E-50

TVA Replv 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 part of the BFN Unit 1 restart effort, these Appendix R BFN Safe Shutdown Instructions, currently BFN Unit 2/Unit 3 procedures, are being revised to ensure safe shutdown capability with all three BFN units operating. 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 22), 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 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 6 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 Repiv 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 E-51

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 28, 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 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 ReIv 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 28, 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.

E-52

NRC Request SPLB-B.6 Enclosure 13 of the June 28, 2004, submittal states, 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 Replv 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.

E-53

TVA RePlv 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 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 PRA information provided in Section 10.5 of Enclosure 4 of the June 28, 2004, EPU submittal (Reference 1), and subsequently updated in References 23 and 24, reflects the Unit 1 operation at EPU operating conditions. The model was developed consistent with the guidance contained in ASME Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications (Reference 25), and considers the concurrent operation of BFN Units 1, 2, and 3 at EPU conditions. TVA's responses to the NRC Staff's Requests for Additional Information (RAls) regarding the Unit 1 PRA are based on the latest update, described in Reference 24. To facilitate the NRC Staff's review of the RAI responses by NRC, the PRA tables originally provided in Section 10.5 of of the June 28, 2004, submittal have been revised to reflect the latest Unit 1 PRA model results and are provided below.

Table 10-3 BFN Unit 1 Summary of CDF and LERF Updated PRA Values Latest PRA Values Initial Licensing Provided To NRC In Provided To NRC In Request For EPU August 2004 September 2005 Parameter (Reference 1) (Reference 23) (Reference 24)

Total CDF (yr-', mean value) 1.66E-6 1.86 E-6 1.77 E-6 LERF (yr-1, mean value) 2.93E-7 1.87 E-7 4.40 E-7 E-54

Table 10-4 Summary Of Initiator Contributions to CDF and LERF for Browns Ferry Unit 1 Mean frequency 1 1 Initiator Category (events per year) jCDF__ LERF Transient initiator categories Inadvertent Opening of One SRV 1.36E-2 3.70E-9 4.65E-1 0 Spurious Scram at Power 8.76E-2 2.85E-8 3.43E-9 Loss of 500kV Switchyard to Plant 1.02E-2 2.42E-8 6.43E-9 Loss of 500kV Switchyard to Unit 2.37E-2 5.18E-8 1.51 E-8 Loss of Instrumentation and Control Bus 1A 4.27E-3 9.76E-10 1.30E-10 Loss of Instrumentation and Control Bus 1 B 4.27E-3 3.06E-8 2.61 E-9 Total Loss of Condensate Flow 9.45E-3 3.88E-8 5.96E-9 Partial Loss of Condensate Flow 1.93E-2 5.71 E-9 7.11 E-10 MSIV Closure 5.52E-2 9.34E-8 3.57E-8 Turbine Bypass Unavailable 1.95E-3 3.08E-9 1.19E-9 Loss of Condenser Vacuum 9.70E-2 1.67E-7 6.41 E-8 Total Loss of Feedwater 2.58E-2 4.55E-8 1.67E-8 Partial Loss of Feedwater 2.47E-1 8.55E-8 1.01 E-8 Loss of Plant Control Air 1.20E-2 6.58E-8 7.44E-9 Loss of Offsite Power 7.87E-3 2.70E-7 5.03E-9 Loss of Raw Cooling Water 7.95E-3 1.18E-7 4.96E-9 Momentary Loss of Offsite Power 7.57E-3 1.90E-9 2.46E-10 Turbine Trip 5.50E-1 1.90E-7 1.70E-8 High Pressure Trip 4.29E-2 1.32E-8 1.63E-9 Excessive Feedwater Flow 2.78E-2 8.20E-9 1.02E-9 Other Transients 8.60E-2 2.79E-8 3.37E-9 ATWS Categories Turbine Trip ATWS 5.50E-1 5.58E-8 5.34E-8 LOSP ATWS 7.87E-3 1.32E-9 1.27E-9 Loss of Condenser Heat Sink ATWS 1.52E-1 6.27E-8 6.04E-8 Inadvertent Opening of SRV ATWS 1.36E-2 1.14E-9 1.07E-9 Loss of Feedwater ATWS 3.02E-1 1.OOE-7 9.64E-8 LOCA Initiator categories Breaks Outside Containment T6.67E-4 l3.12E-8 l6.97E-9 E-55

Table 10-4 Summary Of Initiator Contributions to CDF and LERF for Browns Ferry Unit 1 Mean frequency Initiator Category (events per year) CDF LERF Excessive LOCA (reactor vessel failure) 9.39E-9 9.09E-9 4.16E-1 1 Interfacing Systems LOCA 3.15E-5 5.OOE-8 5.20E-9 Large LOCA - Core Spray Line Break Loop I 1.68E-6 4.49E-9 l1.55E-10 Loop II 1.68E-6 4.49E-9 1.55E-10 Large LOCA - Recirculation Discharge Line Break Loop A 1.18E-5 1.38E-8 1.20E-9 Loop B 1.18E-5 1.38E-8 1.20E-9 Large LOCA - Recirculation Suction Line Break Loop A 8.39E-7 4.67E-9 8.11 E-1 1 Loop B 8.39E-7 4.67E-9 8.11 E-11 Other Large LOCA 8.39E-7 8.56E-10 7.30E-11 Medium LOCA Inside Containment 3.80E-5 2.02E-8 3.99E-9 Small LOCA Inside Containment 4.75E-4 9.05E-1 1 1.50E-1 1 Very Small LOCA Inside Containment 5.76E-3 1.38E-9 1.79E-1 0 Internal flooding initiator categories EECW Flood in Reactor Building - shutdown units 1.20E-3 7.38E-1 1 3.19E-1 1 EECW Flood in Reactor Building - operating unit 1.85E-6 1.19E-9 2.1 OE-1 2 Flood from the Condensate Storage Tank 1.22E-4 1.38E-9 3.63E-1 0 Flood from the Torus 1.22E-4 3.98E-8 2.89E-1 0 Large Turbine Building Flood 3.65E-3 5.52E-8 2.29E-9 Small Turbine Building Flood 1.65E-2 1.54E-8 1.50E-9 E-56

Table 10-5 Frequency-Weighted Fractional Importance to Core Damage of Operator Actions Used In Browns Ferry Unit 1 PRA Frequency-Weighted Database Fractional Importance to Variable Operator Action Description Core Damage HPRVD1 OPERATOR FAILS TO INITIATE DEPRESSURIZATION 2.8033E-1 HPWWV1 OPERATOR FAILS TO OPEN WETWELL VENT 2.4139E-1 HRSPC1 OPERATOR FAILS TO LOCALLY RECOVER SP COOLING 1.3564E-1 FAILURE HRRHRX OPERATOR FAILS TO ALIGN THE RHR UNIT 1/UNIT 2 4.0855E-2 CROSSTIE HPHPE1 OPERATOR FAILS TO CONTROL LEVEL WITH 2.4758E-2 HPCI/RCIC - THIS IS A NON ATWS SCENARIO HPHPR1 OPERATOR FAILS TO CONTROL LEVEL WITH 1.8028E-2 HPCI/RCIC FOLLOWING LEVEL 8 TRIP HOSV1 OPERATOR FAILS TO PREVENT MSIV CLOSURE 1.7257E-2 DURING ATWS HPTAF1 OPERATOR FAILS TO CONTOL LEVEL AT TAF DURING 1.4605E-2 ATWS - UNISOLATED VESSEL HOAL2 OPERATOR FAILS TO LOWER AND CONTROL LEVEL 1.2427E-2 DURING ATWS (ISOLATED VESSEL)

HPSPC1 OPERATOR FAILS TO ALIGN SUPPRESSION POOL 1.0432E-2 COOLING - THIS IS A NON ATWS SCENARIO ORVD2 OPERATOR FAILS TO INITIATE DEPRESSURIZATION 6.4582E-3 (Split GIVEN FAILURE TO CONTROL HIGH PRESSURE LEVEL fraction) CONTROL HODWS1 OPERATOR FAILS TO ALIGN FOR DRYWELL SPRAY. 5.5943E-3 THIS IS A NON ATWS SCENARIO.

HPTAF2 OPERATOR FAILS TO CONTOL LEVEL AT TAF DURING 4.8371 E-3 ATWS- ISOLATED VESSEL HREEC1 OPERATOR FAILS TO ALIGN SWING RHRSW PUMPS 3.7452E-3 FOR EECW (SCENARIO REQUIRES 2 PUMPS TO BE ALIGNED)

HOAL1 OPERATOR FAILS TO LOWER AND CONTROL LEVEL 3.6761 E-3 DURING ATWS (NON ISOLATED VESSEL)

HPSLC2 OPERATOR FAILS TO INITIATE STANDBY LIQUID 1.3186E-3 CONTROL - VESSEL IS ISOLATED FROM CONDENSER E-57

Table 10-5 Frequency-Weighted Fractional Importance to Core Damage of Operator Actions Used In Browns Ferry Unit 1 PRA Frequency-Weighted Database Fractional Importance to Variable Operator Action Description Core Damage HOREE2 OPERATOR FAILS TO ALIGN SWING RHRSW PUMPS 5.6522E-4 FOR EECW (SCENARIO REQUIRES 1 PUMP TO BE ALIGNED)

HPRTB1 OPERATOR FAILS TO PROVIDE BACKUP TRIP SIGNAL 5.1220E-4 HOSL1 OPERATOR FAILS TO INITIATE STANDBY LIQUID 4.1747E-3 CONTROL - VESSEL IS NOT ISOLATED FROM CONDENSER HOX2 OPERATOR FAILS TO CROSSTIE 4 KV SHUTDOWN 4.0820E-4 BOARD HOX1 OPERATOR FAILS TO ALIGN BATTERY CHARGER 2B 3.6289E-4 TO 250V DC BATTERY BOARD HPADS1 OPERATOR FAILS TO INHIBIT ADS (ISOLATED VESSEL) 3.4901 E-4 HPHPL1 OPERATOR FAILS TO CONTROL HPCI/RCIC LONG 2.3943E-4 TERM (6-24 HOURS)

HPADS2 OPERATOR FAILS TO INHIBIT ADS (NON ISOLATED 1.5692E-4

____ ____ VESSEL) _ _ _ _ _ _ _ _ _ _

HODSB1 OPERATOR FAILS TO ALIGN DIESEL BOARD FOR 8.6858E-5 DIESEL C HOR480 OPERATOR FAILS TO RECOVER 480 SHUTDOWN 5.8085E-5 BOARD HPLPC1 OPERATOR FAILS TO CONTROL LPCI/CS INJECTION 1.8690E-5 NRC Request SPSB-A.1 The second paragraph of Section 10.5 of Enclosure 4 of the June 28, 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, including the effect of each modification on the PRA model.

E-58

TVA Replv to SPSB-A.1 TVA reviewed the EPU Design Change Notice (DCN) packages to identify any effect on the PRA model. This review determined that the PRA model was 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 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 High Pressure Main Modeled implicitly as turbine trip. No basis for changing frequency.

Turbine Low Pressure 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.

E-59

Table SPSB-A.1-1 Modification PRA Review Results 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 is modeled 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 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, No changes to the systems that impact the capability to adequately perform Recirculation, PRA associated functions.

Feedwater, and Condensate Supports 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 it an 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.

E-60

Table SPSB-A.1-1 Modification PRA Review Results Main Steam Relief No affect on MSRV challenges and subsequent reseating.

Valves Motor Operated Valves The modifications do not adversely affect the reliability of the MOVs as modeled in the PRA.

High pressure Coolant System features modified are not modeled explicitly; will ultimately manifest in Injection System reliability statistics.

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.

TVA Reply to SPSB-A.2.a The data from Units 2 and 3 was used as plant-specific data for Unit 1. Note that during the time period used for data collection (January 1996 to March 2003) there were no loss of offsite power or loss of station power (LOOP or LOSP) events at BFN. BFN Units 1, 2 and 3 are a common facility with a common switchyard. Even though Unit 1 has been in a non-power production mode, several Unit 1 systems and components have remained operational both to support fuel pool cooling and Units 2 and 3 operation. At the time of restart, Unit 1 will be the same functionally as Units 2 and 3.

All three units will have the same Updated Final Safety Analysis Report and operators will be licensed on all three units. Therefore, it is appropriate to use Unit 2 and 3 LOOP data for Unit 1.

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 E-61

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 (IEs):

• 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 26). 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 161 kV 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 27) 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 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-1 032.

• INEEUEXT-97-00887 (Reference 28) 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 26) was published in November 1998 as the final version of INEEUEXT-97-00887.

E-62

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 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) Frequency 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.

E-63

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 P= 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/(N,+2N 2 ), where N1 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.

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 29) 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.

E-64

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 is estimated from NRC operating experience data and the BFN Scram Database (Reference 30). 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.

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 3.00E-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.

E-65

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 __

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 I 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-66

Table SPSB-A.2-3 Generic Prior Distributions Prior Distribution Gamma Mean (per Alpha Beta calendar(cica BFN IE Description year) (no units) 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 1.1E-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-A.2-4 BFN Unit I Initiating Event Plant-Specific Updates and Posterior Distributions for Losses of Offsite Power BFN Data Posterior Prior Mean (per Exposure Mean 5th %Ile 95th BFN IE Description calendar No. of Time (per Ae cal(endr (per year) Events (critical calendar Alpha (critical cal(epner years) year) years) ya)calendar ya) year)

Loss of Off site LOSPG Power - 2.85E-03 0 13.78 2.81 E-03 3.14 1062.08 7.96E-4 5.82E-3 Grid Related Loss of Offsite LOSPW Power - 4.93E-03 0 13.78 3.62E-03 0.197 51.71 2.98E-9 1.9E-2 Weather Related Loss of L500PA 500kV to 1.1 E-02 0 13.78 9.73E-03 1.84 179.68 1.55E-3 2.4E-2 Plant E-67

Table SPSB-A.2-4 BFN Unit I Initiating Event Plant-Specific Updates and Posterior Distributions for Losses of Offsite Power 7

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 Replv 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 Reply 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 E-68

from 1980-1996 caused by plant-centered losses, grid losses, or severe weather losses.

Earlier analyses (Reference 31) 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 26) 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 31), 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.

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 E-69

NRC Request SPSB-A.2.d Describe how the probability of consequential LOOP was determined.

TVA Reply 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 32). 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.

TVA Replv 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 1 being 1.5E-11.

NRC Request SPSB-A.3 Section 10.5.1 of Enclosure 4 of the June 28, 2004, submittal 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 necessary to adopt this approach for the Unit 1 PRA and describe (in terms of the PRA modeling) how the approach actually facilitates the tracing of success criteria.

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

E-70

TVA RepIv to SPSB-A.3 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 25).

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 25). 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.4 Identify the specific sources of the data used in the Unit 1 PRA (including initiating event frequencies, basic event failure probabilities, split fractions, and common cause data).

If any data based on the operating experience of Unit 1 has been used, justify its applicability to the post-EPU plant, considering that Unit 1 has been shut down for almost two decades. If any data based on the operating experience of Units 2 and 3 has been used, justify its applicability to Unit 1.

TVA Reply to SPSB-A.4 Initiating Events Data The sources of the data used in the Unit 1 PRA for initiating event frequencies are discussed below:

• The primary source of initiating event generic distributions is NUREG/CR-5750 (Reference 29). These generic distributions were updated using BFN experience from the beginning of 1996 through March, 2003.

• NUREG/CR-5496 (Reference 26) was used for LOSP related initiating events.

E-71

Unit 1 will be operated with the same or similar procedures. All three units are similar in design (with respect to initiating events) and Unit 1 will be operated with the same procedures and management philosophy as the other 2 units. Hence, Unit 2 and Unit 3 plant data used in the updating of the initiating event frequencies are applicable to Unit 1.

Basic Event Failure Probabilities and Split Fraction Data The sources of the data used in the Unit 1 PRA for component failure rates and maintenance unavailability's are discussed below:

• In general, data was obtained from Units 2 and 3. For the CRD and RHR pumps, Unit 1 data was also included. These Unit 1 components can be cross-tied to Unit 2 and were kept operable.

• The time period in the development of the database for Unit 2 and 3 PRA was from June 1994 through May 1999. For the Unit 1 PRA, the failure rate and maintenance unavailability for the major components were updated with additional experience through March 2003.

• For selected components, the failure rate and maintenance unavailability data sources are the data in support of either the Maintenance Rule (10 CFR 50.65) or EPIX (Reference 33). The priors used for updating the failure rates are from NUREG/CR-4639 (Reference 34) and EPRI NP-6780-L (Reference 35), and the priors used for updating the maintenance unavailability parameters are from PLG-0500 (Reference 32).

• For the other components, the generic failure rates are taken from PLG-0500 (Reference 32).

The Units 2 and 3 component failure rate and maintenance unavailability data was determined to be applicable to the Unit 1 PRA due to the following factors:

• The equipment has the same function,

• The equipment has same design, maintenance and operational practices,

• The system procedures for operation, maintenance and testing are or will be similar,

• The same staff/personnel will be used for testing and maintenance of equipment, and

• The plants have similar training and management approach.

Common Cause Data The sources of the data used in the Unit 1 PRA for common cause parameters are discussed below:

E-72

• The source of common cause data used for the development of the common cause failure parameters is NUREG/CR-6268 (Reference 36).

• The screening of the common cause events was done for applicability to Units 1, 2 and 3.

• Additionally, common cause was modeled for HPCI and RCIC pumps based on data from INEEL (Reference 37).

The basis for the screening of events for all the three units was that all three units are similar in design and all the units will be operated with the same or similar procedures and management philosophy.

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.

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.

E-73

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 3 frequencies. Explain and provide a basis for these differences.

TVA Replv to SPSB-A.5.b Each of the lEs 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.

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).

E-74

Larae 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 Unit 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.

TVA Reply 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 E-75

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 Reply 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 (IEs) and how each of these lEs is modeled.

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-E-76

Table SPSB-A.6-1 BFN Multi-Unit Initiating Events Initiating Event Probabilistic Failures Modeling 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 161 kV 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.

E-77

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.

E-78

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.

E-79

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.

E-80

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.

E-81

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.

E-82

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.

E-83

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.

E-84

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 1 and Unit Unit 1, Unit 2, Unit 2 and 3 Modeling Yes - Credit is 2 shared piping and Unit 3 shared piping approach is taken in the 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.

E-85

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 inthe 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. Include a discussion of how performance shaping factors were modified for the Unit 1 human reliability analysis to account for new procedures, lack of familiarity with Unit 1 equipment, the potential for "wrong unit' errors, and other factors unique to starting up a plant that has not operated in almost two decades.

TVA Reply to SPSB-A.7 Table SPSB-A.7-1 below lists the BFN Unit 1 actions with a Fussell-Vesely importance measure greater than 0.005 or a risk-achievement worth greater than 2.

The human failure events (HFEs) for Unit 1 actions were evaluated utilizing the Electric Power Research Institute (EPRI) HRA Calculator, whereas those for Units 2 and 3 had been evaluated using a combination of a failure likelihood index methodology and manual application of methodologies now incorporated into the EPRI HRA calculator.

The EPRI HRA calculator provides a structured means of recording and applying performance shaping factors. Therefore, it constitutes an improvement in the HRA task, E-86

and the Unit 2 and 3 performance shaping factors were not used as a basis for Unit 1 HFEs Performance shaping factors were not required to be modified for the Unit 1 human reliability analysis to address issues associated with the Unit 1 restart. The Unit 1 PRA is not a "startup" PRA. It is a PRA that estimates the annual average CDF and LERF just like the Unit 2 and 3 PRAs. The operators at BFN are not unit specific. They are trained and qualified on all three units. The operators for Unit 1 will be drawn from a pool experienced in operating Units 2 and 3. Only minor differences exist between the three units as reflected in a common Updated Final Safety Analysis Report (UFSAR) and similar Technical Specifications (TSs). The training emphasizes differences between the units. The procedures for Unit 1 are the same or similar to the Units 2 and 3 procedures. It is not necessary to modify the performance shaping factors for Unit 1 operation. The Human Reliability Analysis Sheets for these actions are provided in Appendix B of this response.

Table SPSB-A.7-1 BFN Unit 1 Significant Human Failure Events Basic Fussell- Risk Event Vesely Achievement Name Importance Worth Basic Event Description HPRVD1 2.97E-01 1462 OPERATOR FAILS TO INITIATE DEPRESSURIZATION HRWWV1 2.22E-01 6.31 OPERATOR FAILS TO ALIGN WETWELL VENT PATH HRSPC1 1.31 E-01 1793 OPERATOR LOCAL RECOVERY OF SP COOLING FAILURE HRRHRX 2.45E-02 <2 OPERATORS ALIGN THE RHR UNIT 1/UNIT 2 CROSSTIE OPERATOR FAILS TO CONTROL LEVEL WITH HPHPE1 2.05E-02 8.39 RCIC/HPCI (EARLY- 6 HOURS)

HPHPR 1.6E-025.58 OPERATORS FAIL TO RECOVER AND CONTROL HPHPR 1 1.65E-02 5.58 HPCI/RCIC AFTER L8 HPTAF1 1.40E-02 2.05 OPERATORS MAINTAIN LEVEL ABOVE TOP OF ACTIVE HPTA1 1.40E02 .05 FUEL (ATWS)

HPSIV1 1.00E-02 <2 OPERATORS DEFEAT MSIV INTERLOCK DURING HPSV 1.E-0 X <2.2 OETIATWS HPSPC 9.0E-032.23 OPERATOR FAILS TO ALIGN RHR FOR SUPPRESSION HPSPC 9.0E-032.23 POOL COOLING (NON-ATWS)

1. The HRA Calculator Report format was not used for this action. This is the local action to align suppression pool valves, given HPSPC1 succeeds (operators attempt to align), but the valve motor failure is recoverable. Screening Value = 0.1 was assigned to account for the fraction of valve failures that the operators will be unable to recover through local actions, either because the valve stem is broken or the valve is jammed, or the operators encounter physical difficulties they can not overcome in the time available. The action is not discussed explicitly in the HRA, since the success of HPSPC1 indicates the operators are trying to establish cooling and hours are available to manually align the required valves.

E-87

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 Reply 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 Hig h winds Progressive screening and plant walkdown 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.14 for additional information.

BFN uses the EPRI Fire Induced Vulnerability Evaluation (FIVE) process to evaluate internal fires. 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 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.

E-88

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.

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 E-89

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 June 28, 2004, submittal 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 Regulatory Guide (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 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.

E-90

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 Reply 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 Section 10.1.3 of Enclosure 4 of the June 28, 2004, submittal states that the mass release for reactor water cleanup breaks was calculated using the 30-psi reactor pressure increase, and that the safety-related equipment was evaluated for effects.

Was the PRA flooding study updated to reflect this flooding rate? Was the impact of the flood on non-safety related equipment credited in the PRA determined and factored into the risk assessment?

TVA Replv to SPSB-A.12 The RWCU system does not release sufficient inventory of fluid prior to automatic isolation to cause damage to equipment due to flooding. Therefore, the PRA does not model flooding from the RWCU. The PRA does include consideration of flooding from sources of large quantities of fluids from postulated pipe breaks from systems such as the EECW system and the CST piping inside the reactor building. This approach bounds the fluid loss from the RWCU system for flooding considerations. The EECW system and the CST piping inside the reactor building do not experience any flow rate or pressure changes as a result of EPU implementation.

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-91

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 Unit 1 that reflects the post-EPU plant configuration and uses an appropriate screening criterion.

TVA Reply to SPSB-A.13 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 1 FIVE analysis was transmitted to the NRC by letter dated January 14, 2005, (Reference 38) and was performed based on Unit 1 post-EPU 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 particular 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/zones 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 (Reference 38) identifying the CDF contributions for the screened fire area/zones.

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 24, 4kV tie board room has the highest CDF of 6.6E-7.

Upon further examination of the analysis performed for Fire Area/Zone 24, there is no Unit 1 related equipment in this fire area/zone. However, during review of the potential failure modes of the 4kV tie board, it was identified that a conceivable failure of shutdown buses 1 and 2 could occur, similar to a loss of offsite power, though offsite power would remain available to the balance of plant loads. For this level of analysis, all fires in this area are therefore conservatively modeled as a loss of all offsite power (initiating event LOSP). It can be argued that the "true" CDF associated with Fire Area/Zone 24 should be less than 6.6E-7. Hence, "screening" this fire area/zone from detailed analysis is justified.

E-92

Excerpt from Table 5-2 (Reference 38)

Fire Induced CDF Summary for Screened Fire Area/Zones Fire Area/Zone Description Fire Area CDF 6 480V Shutdown Board Room 1A (Unit 1 1.11 E-07 Reactor Building, 621' Elevation) 8 4kV Shutdown Board Room D (Unit 2 Reactor 5.83E-09 Building, 593' Elevation) 10 480V Shutdown Board Room 2A (Unit 2 1.07E-08 Reactor Building, 621' Elevation) 11 480V Shutdown Board Room 2B (Unit 2 4.39E-09 Reactor Building, 621' Elevation) 12 Shutdown Board Room F (Unit 3 Reactor 1.09E-08 12 _ Building, 593' Elevation) 13 Shutdown Board Room E (Unit 3 Reactor 5.41 E-09 Building, 621' Elevation) 14 480V Shutdown Board Room 3A (Unit 3 4.83E-09 Reactor Building, 621' Elevation) 15 480V Shutdown Board Room 3B (Unit 3 5.17E-09 Reactor Building, 621' Elevation) 17 Unit 1 Battery and Battery Board Room, 2.35E-07 Control Building 593' Elevation 18 Unit 2 Battery and Battery Board Room, 1.43E-08 Control Building 593' Elevation 19 Unit 3 Battery and Battery Board Room, 2.62E-08 Control Building 593' Elevation 20 Unit 1 and 2 Diesel Generator Building 4.56E-08 21 Unit 3 Diesel Generator Building 1.09E-07 4kV Shutdown Board Room 3EA and 3EB, 22 583' Elevation, Unit 3 Diesel Generator 7.01 E-09 Building 4kV Shutdown Board Room 3EC and 3ED, 23 583' Elevation, Unit 3 Diesel Generator 1.03E-08 Building 24 4kV Bus Tie Board Room, 565' Elevation, 6.60E-07 Unit 3 Diesel Generator Building E-93

NRC Request SPSB-A.14 Enclosure 7 of the June 28, 2004, submittal 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.

TVA Reply 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 Replv to SPSB-A.14.b A probabilistic containment failure analysis for Unit 1 was performed to determine the probability distribution function of containment strength used in the LERF analysis.

Proposed structural modifications to the torus and drywell structural steel have no impact on the dominant failure modes for this analysis, because these modifications are being performed to maintain sufficient design margin in these components at EPU conditions.

NRC Request SPSB-A.15 Explain why LERF is less than CDF for interfacing system LOCAs.

TVA Reply to to SPSB-A.15 The IE ISLOCA accident sequence analysis includes an end-state of "core damage with small bypass" of primary containment. Therefore, some of the CDF sequences go to the E-94

"core damage with small bypass' end-state and not the LERF end-state. This modeling approach is consistent with the guidance provided in the ASME Standard for PRA (Reference 24) and results in the situation where the CDF is greater than LERF.

NRC Request SPSB-A.16 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 Reply to SPSB-A. 16 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.

NRC Request SPSB-A.17 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.17 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.

E-95

Table SPSB-A.17-1 Operator Actions Considered In LERF Analysis Action Comment 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.18 Address the questions in the SRP, Chapter 19, Table 111-1 concerning low power and shutdown PRA.

TVA Repiv to SPSB-A.18 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 evaluation process assists with maintaining adequate defense-in-depth of safety functions when planning and conducting outages.

NRC Request SPSB-A.19 With respect to the technical adequacy of the Unit 1 PRA, the letter from T. E. Abney, TVA, to the U.S. Nuclear Regulatory Commission, "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," dated August 17, 2004, states:

Since the Unit 1 PSA was built from the Units 2 and 3 PSAs, which incorporate the resolution of the peer review comment, the Unit 1 PSA has incorporated the findings of the Units 2 and 3 PRAs Peer Review. Thus, the previously conducted Peer Review was effectively an administrative and technical Peer Review of the Unit 1 PSA. Similar models, processes, policies, approaches, reviews, and management oversight were utilized to develop the Unit 1 PSA.

E-96

RG 1.174, Section 2.2.3.3, states In the current context, technical acceptability will be understood as being determined by the adequacy of the actual modeling and the reasonableness of the assumptions and approximations.

In order to assess the "adequacy of the actual modeling" in the Unit 1 PRA, it is necessary to review the actual Unit 1 PRA model.

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 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.19 TVA has no immediate plans to perform a self-assessment of the BFN Unit 1 PRA. As discussed in Section 10.5.7 of Enclosure 4 (PUSAR) of the initial application (Reference 1), the BFN Unit 1 PSA was developed to be consistent with ASME RA-S-2002, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications." The BFN Unit 1 PRA was developed by an outside expert under the TVA Quality Assurance Program, and was independently reviewed by TVA. Accordingly, the BFN Unit 1 PRA was initially developed, and via its own internal review and approval process, already assessed against the requirements of the American Society of Mechanical Engineers (ASME) standard.

As further discussed in Section 10.5.7 of the PUSAR, and expanded upon in TVA's August 17, 2004, letter submitted to support closure of NRC Generic Letter 88-20 for BFN Unit 1 (Reference 39), the BFN Unit 1 PRA was built based on the BFN Units 2 and 3 PRAs, and modified as required to be consistent with the ASME standard. The BFN Units 2 and 3 PRAs were peer-reviewed to the BWROG peer review certification process, and the observations identified during that process resolved. The specific observations identified during that certification review were provided to the NRC in Reference 39. Accordingly, the development of the Unit 1 PRA based on the BFN Units 2 and 3 PRAs addressed and resolved at the outset, the results of the BFN Units 2 and 3 peer review process.

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 Unit 1 application was developed consistent with NRC-established positions as documented, largely, in the PUSAR accompanying that application. 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, performs on-going E-97

reviews, and revises the BFN PRA models. It was this process that led to TVA's update of BFN Unit 1 PRA by letters dated August 23, 2004 and September 15, 2005.

NRC Request SPSB-A.20 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 Repiv to SPSB-A.20 The following tables provide significant basic events by Fussell-Vesely (FV) importance and by Risk Achievement Worth (RAW), respectively. Note that the list for the RAW is significantly longer than for FV. The reason for this is the definition of RAW where a highly reliable basic event is assumed to fail with a probability of 1.0. Changing a probability by orders of magnitude can have a significant impact on the results.

BFN Unit 1 Significant Basic Events by Fussell-Vesely Importance Measure Fussell-Rank Basic Event Description Vesely Importance 1 HER HPRVD1 OPERATOR FAILS TO INITIATE DEPRESSURIZATION 2.9726E-001 2 HER_HPWWV1 OPERATOR FAILS TO ALIGN WETWELL VENT PATH 2.2165E-001 3 CONDENSER_2A2B2C MAIN CONDENSER UNAVAILABLE AFTER PLANT TRIP 1.4339E-001

[MOVFO1 FCV0230034 4 MOVFO1 FCV0230040 COMMON CAUSE FAILURE OF RHRSW RHR VALVES 1.3587E-001 MOVFO1 FCV0230052]

5 HER_HRSPC1 OPERATOR LOCAL RECOVERY OF SP COOLING FAILURE 1.3058E-001 6 PTSFS1 PMP0730054 HPCI PUMP FAILS TO START ON DEMAND 1.0241 E-001 7 PTSFR1 PMP71019_6 RCIC PUMP FAILS TO RUN 1.0143E-001 8 GELSOVCFPSOVS CCF 33% OR MORE HCU SCRAM PILOT SOVs OR BACKUP 8.5654E-002 SOVs FAILS 9 PTSFS1 PMP0710019 RCIC PUMP FAILS TO START ON DEMAND 7.5660E-002 10 PTSFR1PMP73054_6 HPCI PUMP FAILS DURING OPERATION 6.4956E-002 11 [DGFTS.LDG3A] DG 3A FAILS TO START; DG 3A FAILS TO RUN; DG 3A5.3E-0 11 [DGFTS_1-DG3A] BREAKER 1838 FAI 5.7396E-002 12 RHR1CCF FAILURE OF U2 RHR PUMPS AFTER ALL Ul PUMPS HAVE 5.6984E-002 FAILED 13 [DGFTS 1DGA] DG A FAILS TO START; DG A FAILS TO RUN; DG A BREAKER 4.8775E-002 1818 FAILS E-98

BFN Unit 1 Significant Basic Events by Fussell-Vesely Importance Measure Fussell-Rank Basic Event Description Vesely Importance

[MOVFO1 FCV0740057 14 MOVFO1 FCV0740059 COMMON CAUSE FAILURE RHR SP COOLING VALVES 4.8216E-002 MOVFO1 FCV0740071 MOVFO[ FCV0740073]

[DGFTS_1_DGA 15 DGFTS_1_DGB DGFTS_1_DGC COMMON CAUSE FAILURE OF UNIT 1/2 DGS 4.0526E-002 DGFTS_1_DGD]

16 [DGFTS_1_DGB] DG B FAILS TO START OR DG B FAILS TO RUN OR DG B 3.4340E-002 BREAKER 1822 FA 17 MOVFC1 FCV0710034 RCIC MINI-FLOW VALVE FAILS TO CLOSE ON DEMAND 3.0063E-002 18 [MOVFO1 FCV0710008] RCIC STEAM ADMISSION VALVE FAILS TO OPEN ON DEMAND 2.7629E-002 19 [MOVFO1 FCV0710039] RCIC DISCHARGE VALVE FAILS TO OPEN ON DEMAND 2.7629E-002 20 BEHOU11 OPERATORS ALIGN THE RHR UNIT 1/UNIT 2 CROSSTIE 2.4451 E-002 21 PTSFS1CCFRCIHPI RCIC AND HPCI PUMPS COMMON CASUE FAILURE TO START 2.4413E-002 22 [MOVFO1 FCV0740073] RHR SP VALVE FAILS TO OPEN 2.2049E-002 23 [MOVFO1 FCV0740071] RHR SP VALVE FAILS TO OPEN 2.2049E-002 24 MOVFO1 FCV0730036 HPCI TEST RETURN VALVE 2.0622E-002 25 HER HPHPE1 OPERATOR FAILS TO CONTROL LEVEL WITH RCIC/HPCI 2.0466E-002

_____________ (EARLY- 6 HOURS) 2.0466E-00 26 [MOVXC1 FCV0730036] HPCI TEST RETURN VALVE 1.8947E-002 27 MOVFO1 FCV0730027 SUCTION PATH FROM SUPPRESSION POOL FAILS 1.8374E-002 28 MOVFO1 FCV0730035 RETURN TEST LINE FOR HPCI FAILS 1.8374E-002 29 MOVFO1 FCV0730026 PATH FROM SP RING HEADER TO HPCI SUCTION FAILS 1.8374E-002 30 MOVFC1 FCV0730040 PATH FROM SP RING HEADER TO HPCI SUCTION FAILS 1.8374E-002 31 [DGFTS_1DGC] DG C FAILS TO START; DG C FAILS TO RUN; DG C BREAKER 1.8354E-002 1818 FAILS 32 PTSFR1CCFRCIHPI CCF TO RUN HPCI AND RCIC PUMPS 1.7286E-002 33 [MOVFO1 FCV0730016] HPCI STEAM SUPPLY FAILS 1.6880E-002 34 [MOVFO1FCV0730044] HPCI PUMP DISCHARGE PATH FAILURE 1.6880E-002 35 [MOVXC1 FCV0730035] HPCI RETURN LINE TO CST FAILED 1.6880E-002 36 [MOVFO1 FCV0710008 CCF TO OPEN FAILS RCIC AND HPCI STEAM SUPPLY 1.6796E-002 MOVF01 FCV073001 6] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

37 MOVFO1 FCV07300441 CCF TO OPEN CAUSES RCIC AND HPCI DISCHARGE FAILURE 1.6796E-002 38 HER HPHPR1 OPERATORS FAIL TO RECOVER AND CONTROL HPCI/RCIC 1.6467E-002 AFTER L8 39 PTSFR1 PM73054_18 RCIC TURBINE PUMP FAILS TO RUN 1.4238E-002

[DGFTS_1_DGA 40 DGFTS_1_DGB CCF TO START DGS A, B, AND C 1.4208E-002 DGFTS_1_DGC]

E-99

BFN Unit 1 Significant Basic Events by Fussell-Vesely Importance Measure Fussell-Rank Basic Event Description Vesely Importance 41 BEHPTAF1 OPERATORS MAINTAIN LEVEL ABOVE TOP OF ACTIVE FUEL 1.3959E-002 42___ [MOVFO1_________

FFOFO(ATWS) ___I1 3 42 [MOVFO1 FCV0740059] FAILURE TO OPEN 74-57 FOR RHR LOOP I SP COOLING 1.3183E-002 43 [MOVF01 FCV0740057] FAILURE TO OPEN 7474-57 FOR RHR LOOP I SP COOLING 1.31 83E-002

[MOVFO1 FCV0710034 44 MOVXC1 FCV0730035 MOV FAILURES RESULT IN FAIURE OF BOTH HPCI AND RCIC 1.3003E-002 MOVXC1 FCV07300365 45 GELRODCFCRD CCF 33% OR MORE RODS FAIL TO INSERT 1.2552E-002 46 [PMSFS1 PMP074001 B] RHR PUMP B FAILS TO START 1.2408E-002 47 PTSFR1PM71019_18 RCIC PUMP FAILS TO RUN FOR 18 HOURS 1.2330E-002 48 [MOVFO1 FCV0230034] RHR HX RHRSW VALVE 24 FAILS TO OPEN 1.0882E-002 49 BEHOAL2 LOWER & CONTROL LEVEL DURING ATWS (UNISOLATED RPV) 1.0872E-002 50 [MOVFO1 FCV0740059 CCF TO OPEN RHR SUPPRESSION POOL VALVES BOTH 1.0723E-002 MOVFO1 FCV0740071] LOOPS 51 [MOVFO1 FCV0740059 CCF TO OPEN RHR SUPPRESSION POOL VALVES BOTH 1.0723E-002 MOVFO1 FCV0740073] LOOPS 52 [MOVFO1 FCV0740057 CCF TO OPEN RHR SUPPRESSION POOL VALVES BOTH 1.0723E-002 MOVFO1 FCV0740071 ] LOOPS 53 [MOVFO1 FCV0740057 CCF TO OPEN RHR SUPPRESSION POOL VALVES BOTH 1.0723E-002 MOVFO1 FCV0740073] LOOPS 54 BEHOSV1 OPERATORS DEFEAT MSIV INTERLOCK DURING ATWS 1.0044E-002 55 HERHPSPC1 OPERATOR FAILS TO ALIGN RHR FOR SUPPRESSION POOL 9.0660E-003 COOLING (NON-AT 56 [DGFTS_1_DG3B] DG 3B FAILS TO START 8.7858E-003 57 TBSFDST TURBINE BYPASS SYSTEM UNAVAILABLE FOR SHORT TERM 7.2486E-003 TBSFDSTPRESSURE RELIEF 58 BEFRACT7 A MULTI UNIT INITIATOR AND U2 @ POWER 6.8678E-003 59 FLTPL1_032AFLT AFTER FILTER PLUGS IN PLANT CONTROL AIR 5.9284E-003 60 FLTPL1_032PRFLT PREFILTER PLUGS IN PLANT CONTROL AIR 5.9284E-003

[FN2FR1 ROOM74001A 61 FN2FR1 ROOM74001C CCF RHR ROOM COOLERS FOR PUMPS A, BBC, AND D 5.8996E-003 FN2FR1 ROOM74001 D]

62 GELACCCFHCU CCF 335 OR MORE HCU ACCUMULATORS FAIL 5.3768E-003 63 AOVFO1 FCV0640222 FCV 64-222 FAILS TO OPEN ON DEMAND (HWWV) 5.251 5E-003 64 AOVFO1 FCV0640221 FCV 64-221 FAILS TO OPEN ON DEMAND (HWWV) 5.2515E-003 E-100

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 1 GELSOVCFPSOVS CCF 33% or more HCU Scram Pilot SOVs or 4.7876E+004

____ ___ ___ ____ ___ ___ Backup SOVs Fail 2 GELACQCCFHCU CCF 335 or more HCU Accumulators Fail 4.7876E+004 3 GELAOVCFHCU CCF 33% or more HCU Scram Inlet/Outlet 4.7876E+004 GELO'LCHCUAOVS Fail to Open 4 GELRODCFCRD CCF 33% or more Rods Fail to Insert 4.7876E+004

[PMSFR1 PMP074001A 5 PMSFR1 PMP074001 B Common Cause: Group RHR Pumps Fail to 2.6055E+003 PMSFR1PMP074001C Run, 4/4 PMSFR1 PMP074001 D]

[FN2FR1 ROOM74001A FN2FR1 ROOM74001 B Common Cause: Group RHR Room Coolers FN2FR1ROOM74001C Fail to Run, 4/4 FN2FR1 ROOM74001 D]

[PMSFS1 PMP074001A 7 PMSFS1 PMP074001 B Common Cause: Group RHR Pumps Fail to 2.6054E+003 PMSFS1PMP074001C Start, 4/4 PMSFS1 PMP074001 D]

[FN2FS1 ROOM74001A 8 FN2FS1 ROOM74001 B Common Cause: Group RHR Pump Room 2 FN2FS1 ROOM74001 C Coolers Fail to Start, 4/4 .6053E+003 FN2FS1 ROOM74001 D]

9 HERHPSPC1 Operator Fails to Align RHR for Suppression 1.7931 E+003 HERHPSPC1 ~~Pool Cooling (NON-ATW~S)______

10 HERHPRVD1 Operator Fails to Initiate Depressurization 1.4622E+003

[RV2FO1 PCV001 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves RV2FO1 PCVW01 0031 RV2FO1 PCV001 003 Fail to Depressurize, 6/6

[RV2FO1 PCV001 00319 RV2F1701PCV001 00342 1RV2FO1 PCV001 0019 RV2FO1 PCV001 0022 Common Cause: Group Safety Relief Valves 1.2149E+003 12 RV2FO1 PCV001 0030 RV2FO1 PCV011 0031 Fail to Depressurize, 5/6 RV2FO1 PCV0010034] RV2FO1 PCV001002

[RV2FO1 PCV001 0005 RV2FO1 PCV001 0022 Common Cause: Group Safety Relief Valves 13 RV2FO1 PCV001 0030 RV2FO1 PCV011 0031 Fail to Depressurize, 5/6 1.2149E+003 RV2FO1 PCV0010034] RV2FO1 PCV0010019

[RV2FO1 PCV001 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves 14 RV2FO1 PCV001003 RV2FO1PCV 10031 Fail to Depressurize, 5/61.2149E+003 15 [RV2FO1 RV2FO1 PCV0010005R2F1PC0101

[RV2FO1 PCV00102 PCV001 0005 RVF1PV003 RV2FO1 PCV001 0019 Fail to Depressurize, Common Cause: Group 5/P6 Safety'1.49+0 Relief Valves 15 RV2FO1 PCV001 0022 RV2FO1 PCV001 0030 Fail to Depressurize, 5/6 1.2149E+003 RV2FO1 PCV00100311 RV2FO1 PCV0010019

[RV2FO1 PCV001 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves 16 RV2FO1 PCV001 0022 RV2FO1 PCV001 0030 Fail to Depressurize, 5/6 1.2149E+003 RV2FO1 PCV001 0034]

[RV2FO1 PCV001 0005 RV2FO1 PCV001 001 9 Common Cause: Group Safety Relief Valves 17 RV2FO1 PCV001 0022 RV2FO1 PCV001 0031 Fail to Depressurize, 5/6 1.2149E-,003 RV2FO1lPCV001 0034] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

E-101

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 18 [FN2FS1ROOM74001A Common Cause: Group RHR Pump Room 1.2004E+003 FN2FS1 R00M74001

[PMSNFS1 RPMP74001 C A Coolers Fail to Start, 3/4 .04+0 19 [PMSFS1PMP074001A Common Cause: Group RHR Pumps Fail to 1.1996E+003 PMSFS1 PMP074001 C]

P[FN2F1 POM P74001 C]SatA/

[FN2FR1ROOM74001A Common Cause: Group RHR Room Coolers FN2FR1 ROOM74001 C] Fail to Run, 3/4

[PMSFR1RPMP74001 A

[PMSFR1PMP074001A Common Cause: Group RHR Pumps Fail to 21 PMSFRl PMP074001 B Ru,41. I 985E-t003 PMSFR1PMP074001C] un,

[MOVFO1 FCV0230034 22 MOVFO1 FCV0230040 Common Cause: Group RHR Heat 9.4793E+002 MOVFO1 FCV0230046 Exchangers, 4/4 MOVFO1 FCV0230052]

23 SWCS CCF (Failure to Start) of all RHRSW Pumps 6.0770E+002 24 SWCR CCF (Failure to Run) of All RHRSW Trains 6.0770E+002 25 FCOFTODGABCD Motor Operated Vent. Dampers FTO or Fans 2.8000E+002

_______ ________ _______ Fail to Start (D iesels) _ _ _ _ _ _

26 [DGFTS 1_DGA DGFTS1DGB Common Cause: Group Diesel Generators, 2.8000E+002 DGFTSL1_DGC DGFTS_1_DGD] 4/4

[MOVFO1 FCV0740057 27 MOVFO1 FCV0740059 Common Cause: Group RHR Suppression 2.1026E+002 MOVFO1 FCV0740071 Pool Cooling Valves, 4/4 MOVFO1 FCV0740073]

28 [MOVFO1 FCV0740059 Common Cause: Group RHR Suppression 2.1026E+002 MOVFO1FCV0740071] Pool Cooling Valves, 2/4 29 [MOVFO1 FCV0740059 Common Cause: Group RHR Suppression MOVFO1 FCV0740073] Pool Cooling Valves, 2/4 2.1026E+002 30 [MOVFO1 FCV0740057 Common Cause: Group RHR Suppression 2.1026E+002 MOVFOlFCV0740071] Pool Cooling Valves, 2/4 31 [MOVFO1FCV0740057 Common Cause: Group RHR Suppression 2.1026E+002 MOVFO1 FCV0740073] Pool Cooling Valves, 2/4

[RL1FD1_0010K14 RL1FD1_0010K16 Common Cause: Group Relays for MSIV 32 RRL1FD1_00110K51 RL1FD1 001OK52] Closure, 4/4 1.3889E+002

[RL1 FD1_001OK16 RL1 FD1=O001OK51 Common Cause: Group Relays for MSIV 1.3889E+002 RL1FD1_001OK52] Closure, 3/4

[RL1 FD1 _001 OK14 RL1 FD1 001 OK16 Common Cause: Group Relays for MSIV RL1FD1__001OK51] Closure, 3/4 35 [RL1 F1_001 OK51 RL1 FD1_001 OK52] Common Cause: Group Relays for MSIV 1.3889E+002

[RL1DIO1OK5RL1D1 01 052] Closure, 2/4 36 [RL1FD1_001OK14 RL1FD1_0010K51 Common Cause: Group Relays for MSIV 1.3889E+002 RL1FD1_0010K52]

36 Closure, 3/4 37 [RL1FD1_0010K14 RL1 FD1_0010K16 Common Cause: Group Relays for MSIV 1.3889E+002 RL1 FD1001 0K52] Closure, 3t4 1.3889E 38 [RL1FD1_0010K14 RL1FD1_0010K16] Common Cause: Group Relays for MSIV 1.3889E+002

_ _ __ __ _ _ _ __ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ C losure, 2/4 _ _ _ _ _

E-102

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 39 [RL1 FD1_001OK14 RL1 FD1_001OK52] Common Cause: Group Relays for MSIV 1.3889E+002 Closure, 214 _ _ _ _ _ _

40 [AOVFC1 FCV001 0037 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV001 0038] 2/8 1.3889E+00 41 [AOVFC1 FCV001 0014 AOVFC1 FCV001 0015 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010052] 3/8 42 [AOVFC1 FCV001 0014 AOVFC1 FCVOO1 0015 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010051] 3/8 __1.389E+00 43 [AOVFC1 FCV001 0014 AOVFC1 FCV0010015 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010038] 3/8

[AOVFC1 FCV001 0014 AOVFC1 FCV001 0015 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010037] 3/8 45 [AOVFC1 FCV001 0014 AOVFC1 FCV001 0015 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010027] 3/8

[AOVFC1 FCVOO1 001 4 AOVFC1 FCV001 0015 46 AOVFC1 FCV001 0026 AOVFC1 FCV001 0027 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV001 0037 AOVFC1 FCV001 0038 8/8 AOVFC1 FCV0010051 AOVFC1 FCV0010052]

47 [AOVFC1 FCV0010051 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010052] 2/8 48 [AOVFC1 FCV0010037 AOVFC1 FCV0010038 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCVW010052] 3/8 49 [AOVFC1 FCV001 0037 AOVFC1 FCV001 0038 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010051] 3/8 ' 1.3889E+00 50 [AOVFC1 FCV001 0038 AOVFC1 FCVOO1 0051 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010052] 3/8 1.3889E+002 51 [AOVFC1 FCV001 0037 AOVFC1 FCV001 0051 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV001 0052] 3/8 ' 1.3889E+00 52 [AOVFC1 FCV001 0027 AOVFC1 FCV001 0051 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010052] 3/8 __1.3889E+00 53 [AOVFC1 FCV001 001 4 AOVFC1 FCV001 0051 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010052] 3/8 1.3889E+002 54 [AOVFC1 FCV001 0015 AOVFC1 FCV001 0026 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010027] 3/8 ' 1.3889E+00 55 [AOVFC1 FCV0010026 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010027] 2/8 1.3889E+00 56 [AOVFC1 FCV001 0014 AOVFC1 FCV001 0037 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010038] 3/8 1.3889E+002 57 [AOVFC1 FCV001 0027 AOVFC1 FCV001 0037 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCVOO1 0038] 3/8 1.3889E+002 58 [AOVFC1 FCV001 0026 AOVFC1 FCV001 0051 Common Cause: Group MSIVs Fail to Close, 1.3889E-002 AOVFC1 FCV0010052] 3/8 1.3889E+002 59 [AOVFC1 FCV001 0026 AOVFC1 FCV001 0027 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010052] 3/8 ' 1.389E+00 60 [AOVFC1 FCV001 0026 AOVFC1 FCV001 0037 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV00100381 3/8 1.3889E+002 61 [AOVFC1 FCVOO1 0015 AOVFC1 FCV001 0037 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010038] 3/8 E-103

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 62 [AOVFC1 FCV0010015 AOVFC1 FCV0010051 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010052] 3/8 63 [AOVFC1 FCV001 0026 AOVFC1 FCV001 0027 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010038] 3/8 64 [AOVFC1 FCV001 0026 AOVFC1 FCV001 0027 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010037] 3/8 65 [AOVFC1 FCV0010014 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010015] 2/8 66 [RL1FDlO01oK16 RL1FD1_0010K51] Common Cause: Group Relays for MSIV 1.3889E+002

_Closure, 24 67 [AOVFC1 FCV0010014 AOVFC1FCV0010015 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV001 0026] 3/8 68 [AOVFC1 FCVOO1 0014 AOVFC1 FCVOO1 0026 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010027] 3/8 69 [AOVFC1 FCV0010026 AOVFC1 FCV001 0027 Common Cause: Group MSIVs Fail to Close, 1.3889E+002 AOVFC1 FCV0010051] 3/8 70 [DGFTS_1_DGA DGFTS 1 DGB Common Cause: Group Unit 1/2 Diesel 1.1823E+002 DGFTS_1_DGC] Generators, 3/4 7MOVFO1 FCV0230034 Common Cause: Group RHR Heat 71 MOVF01 FCV0230040 EcagrMOs 41 .0097E+002 MOVF01 FCV0230046] Ecagr Os /

72 [PMSFR2_02300B1 PMSFR2 02300B2 Common Cause: Group South Service Water 8.9775E+001 PMSFR2 02300D1 PMSFR2 02300D2] Header RHRSW Pumps, 4/4

[PMSFS2_02300B1 PMSFS2_02300B2 Common Cause: Group South Service Water 8.9775E+001 PMSFS2_02300D1 PMSFS2 02300D2] Header RHRSW Pumps 4/4 . -

[FN2FS1ROOM74001A Common Cause: Group RHR Pump Room 74 FN2FS1 ROOM74001AC Fail to S,3/4 7s

.1926E+001 FN2FS1 ROOM74001 D]

[PMSFS1PMP074001A Common Cause: Group RHR Pumps Fail to 75 PMSFSl PMP074001 C Str,347.0732E+001 PMSFS1PMP074001D] Rt, 3/4

[FN2FR1 ROOM74001A Common Cause: Group RHR Room Coolers 6.9E+001

_ FN2FR1 ROOM74001 D] Fail to Run, 3/46

[PMSFR1PMP074001A Common Cause: Group RHR Pumps Fail to 6.8611E+001 77 PMSFRI PMP074001C Rn 1 .6 +0 PMSFR1 PMP074001 D] ru, 3/4

[FN2FS1 ROOM74001A Common Cause: Group RHR Pump Room 78 FN2FS1 ROOM74001 B CoBonFause: Grt, RHR 6.5393E+001 FN2FS1 R00M74001 D] CoesFi oSat /

[PMSFS1lPMP074001 A Common Cause: Group RHR Pumps Fail to 6.2E00 79 PMSFS1PMP074001B Sat 1 .22+0 PMSFS1lPMP0740010] Sat /

[FN2FS1 R00M74001 B Common Cause: Group RHR Pump Room 80 FN2FS1 R00M74001 C Coolers Fail to Start, 3/4 6.3836E-i001

[FN2FR1 ROOM74001A Common Cause: Group RHR Room Coolers 81 FN2FR1 R00M74001 B Falt u,346.3304E-,001 FN2FR1lR00M74001 Dl alt Rn E-1 04

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth

[PMSFS1 PMP074001 B Common Cause: Group RHR Pumps Fail to 82 PMSFSl PMP074001 C Str,346.2645E+001 PMSFS1 PMP074001 D] Start, 3/4

[PMSFR1PMP074001A Common Cause: Group RHR Pumps Fail to 6.2061E+001 83 PMSFRlPMP074001BRu,34621E01 PMSFR1 PMP074001 D] un,

[FN2FR1 ROOM74001 B Common Cause: Group RHR Room Coolers 84 FN2FR1 R00M74001 C Falt u,346.1 748E+001 FN2FR1 ROOM74001 DI Fail to Run, 3/4

[PMSFR1PMP074001B Common Cause: Group RHR Pumps Fail to 85 PMSFRl PMP074001 C Ru,346.0504E+001 PMSFR1PMP074001D] un, 3/4 86 [CB1 FOOBKRO571614 CB1 FOOBKRO571616 Common Cause: Group Unit 1/2 4kv SD 5.1145E+001 CB1FOOBKRO571718] Feeder Breakers FTO, 3/4 5.1145E+001 87 [CB1 FOOBKRO571614 CB1 FOOBKR0571616 Common Cause: Group Unit 1/2 4kv SD 5.1144E+001 CB1 FOOBKRO571718 CB1 FOOBKRO571724] Feeder Breakers FTO, 4/4 5.1144E+001 88 HOVXC1 HCV0740085 HCV-74-85 Transfers Closed 5.0915E+001 89 HOVXC1 HCV0670565 Valve 67-565 Transfers Closed 5.0915E+001 90 [FN2FS1ROOM74001A Common Cause: Group RHR Pump Room 4.9186E+001 FN2FS1 ROOM7400IC] Coolers Fail to Start, 2/4 _

91 MOVXC1 FCV0740007 FCV-74-7 Transfers Closed 4.861 OE+001 92 [PMSFS1PMP074001A Common Cause: Group RHR Pumps Fail to 4.8370E+001 PMSFS1PMP074001C] Start, 2/4 93 PTSFS1CCFRCIHPI RCIC PTSFSCCFRIH~iTo StartHPCI Pumps Common Cause Failure 4.8168E+001 24 [MOVFO1 FCV0710008 Common Cause: Group RCIC Steam Supply, 4.8168E+001 MOVFO1 FCV0730016] 2/2 95 [MOVFO1 FCV0710039 Common Cause: Group HPCI RCIC Pump 4.8168E+001 MOVFO1 FCV0730044] Discharge MOV failure, 2/2

[MOVF01 FCV0710034 Common Cause: Group HPCI RCIC Return 4.8168E+001 96 MOVXC1 FCV0730035 Lin Cause 3P4 4.8168E+001 MOVXC1lFCV0730036]LieMOs34

[HPCI RCIC Retumn Lines Common Cause: Group HPCI RCIC Return 97 MOVsl FCV071 0034 MOVXC1 FCV071 0038 Lines MOVs, 3/4 4.81 68E+001 MOVXC_FCV0730035]

[HPCI RCIC Return Lines 98 MOVs1 FCVo710034 MOVXC1 FCV0710038 Common Cause: Group HPCI RCIC Return 4.81 68E+001 MOVXC1 FCV0730035 Lines MOVs, 4/4 MOVXC1 FCV0730036]

99 [RL11RLY23A_K25 RL1FD1RLY071OK22] Common Cause: Group HPCVRCIC Relays, 4.8168E+001 214 100 [RLlFD123AK21 RL1FD1RLYA71OK22] Common Cause: Group HPCI/RCIC Relays, 4.8168E+001 2/4 101 [RL11 RLY23AK25 RL1 FD123AK21 Common Cause: Group HPCIURCIC Relays, 4.8168E+001 RL1 1RLY23A0125 RL1 D 23Aj(22 Common Cause: Group HPC/RCIC Relays, 4.8168E+001 RLD1RLY0710K22] 3/4 ______

E-105

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 103 [RL1FD123AK21 RL1FD123AK22 Common Cause: Group HPCI/RCIC Relays, 48168E+001 RL1 FD1 RLY071 OK22] 3/4 104 (RL1 1RLY23AK25 RL1 FD123AK21 Common Cause: Group HPCI/RCIC Relays, 48168E+001 RL1 FD1 23AK22 RL1 FD1 RLY071 OK22] 4/4 105 PTSFR1CCFRCIHPI RCIC HPCI Pumps Common cause Failure to 4.8168E+001 Run

[MOVFO1 FCV0710034 Common Cause: Group HPCI RCIC Return 106 MOVXC1 FCV0710038 Lines MOVs 314 4.8168E+001 MOVXC1 FCV0730036] LnsM~ /

107 [MOVFO1 FCV0710034 Common Cause: Group HPCI RCIC Return 4.81m68E+01 MOVXC1 FCV0730036] Lines MOVs 2/4 108 [RL1FD123A K22 RL1FD1RLY071OK22] Common Cause: Group HPCI/RCIC Relays, 4.8168E+001 2/4 109 ECCSSUPPLY TRAN Insufficient Flow to ECCS Suction Ring 3.732E+001 Header During Transient 110 ECCS-SUPPLY-LOST Insufficient Flow Available to Ring Header 3.7026E+001 110 ECCS _LOST_________________ During LOCA 111 PRESS~SPRESJLOST PSP to Quench Steam During LOCA 3.7026E+001 Blowdown 112 [PMSFR1PMP074001A Common Cause: Group RHR Pumps Fail to 3.6674E+001 PMSFR1PMP074001C] Run, 2/4 113 [FN2FR1ROOM74001A Common Cause: Group RHR Room Coolers 3.6667E+001 FN2FR1 ROOM74001 C] Fail to Run, 2/4

[MOVFO1 FCV0230034 Common Cause: Group RHR Heat 114 MOVFO1 FCV0230040 Chan Cause G p4 3.4779E+001 MOVFO1 FCV0230052] Exchangers MOVs, 3/4 115 [FN2FR1 FAN098601 FN2FRI FAN098602] Common Cause: Group FANRUN, 2/2 3.3789E+001 116 [FN2FS1ROOM74001A Common Cause: Group RHR Pump Room 3.0606E+001 FN2FS1 ROOM74001 B] Coolers Fail to Start, 2/4 3.0606E+001 117 [PMSFS1 PMPO74001 A Common Cause: Group RHR Pumps Fail to 3.0231 E+001 PMSFS1 PMP074001 B] Start, 2/4 3.0231_____

118 [FN2FR1ROOM74001A Common Cause: Group RHR Room Coolers 2.9643E+001 FN2FR1 ROOM74001 B] Fail to Run, 2/4 2.9643E+001 119 [PMSFR1 PMP074001A Common Cause: Group RHR Pumps Fail to 2.9639E+001 PMSFR1PMP074001B] Run, 2/4 2.9639E+001 120 [FN2FS1 ROOM74001 B Common Cause: Group FN2FS1 ROOM74001 C] Coolers Fail to Start, 2/4 RHR Pump Room 2.9050E+001 2.9050E+001 121 [PMSFS1 PMP074001 B Common PMSFS1 PMPo74001C] Start, 2/4 Cause: Group RHR Pumps Fail to 2.8671 E+001 2.8671_E+001 122 [FN2FR1 ROOM74001 B Common Cause: Group RHR Room Coolers 2.8087E+001 FN2FR1 ROOM74001 C] Fail to Run, 2/4 2.8087E+001 123 [PMSFR1 PMP074001 B Common Cause: Group RHR Pumps Fail to 2.8082E+001 PMSFR1PMPo74001C] Run, 2/4 2.8082E+001 124 [DGFTS_1_DGA DGFTS_1_DGB Common Cause: Group Diesel Generators, 2.6367E+001 DGFTS_1_DGD] 3/4 ' _2.367+00 125 [MOVFO1 FCV0230034 Common Cause: Group RHR Heat 2.6343E+001 MOVFO1 FCV0230040] Exchangers MOVs, 2/4 2.6343E+001 126 HOVXC1 HCV0740088 HCV-74-88 Transfers Closed 2.3682E+001 E-106

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 127 HOVXC1 HCV0670606 Valve 67-606 Transfers Closed 2.3217E+001 128 BUSFR1 BUS057_1 Battery BD. 1. 2.3200E+001 129 MOVXC1 FCV0740030 FCV-74-30 Transfers Closed 2.2678E+001 130 [FN2FS1ROOM74001B Common Cause: Group RHR Pump Room 2.2597E+001 FN2FS1 ROOM74001 D] Coolers Fali to Start, 214 131 [PMSFS1PMP074001B Common Cause: Group RHR Pumps Fail to 2.2218E+001 PMSFS1 PMP074001 D] Start, 2/4 132 [RL1 FD1_00358A2 RL1 FD1 00358B2 Common Cause: Group Low RX Level Output 2.1454E+001 RL1 FD1_00358C2 RL1 FD1_00358D2] Relays, 4/4 133 [RL1 FD1 14A0750K7A RL1 FD1 14A0750K7B] Common Cause: Group Low RX Level Logic 2.1454E+001

___ ____ ___ ___ ___ Relay (CSS), 2/4 134 [RL1 FD1 00358B2 RL1 FD1 00358C2 Common Cause: Group Low RX Level Output 2.1454E+001 RL1 FD1_00358D2] Relays, 3/4 135 [RL1 FD1-00358A2 RL1 FD1_00358C2 Common Cause: Group Low RX Level Output 2.1454E+001 RL1 FD1 00358D2] Relays, 314 136 [RL1 FD1_00358A2 RL1 FD1_00358C2] Common Cause: Group Low RX Level Output 2.1454E+001

____ ____ ___ ____ ___ R elays, 2/4 137 [RL1 FD1_00358B2 RL1 FD1100358D2] Common Cause: Group Low RX Level Output 2.1454E+001

___ ____ ___ ____ ___ R elays, 2/4 138 [RL1FD1_00358A2 RL1FD1_00358B2 Common Cause: Group Low RX Level Output 2.1454E+001 RL1 FD1_00358D2] Relays, 3/4 2.1454E+001 139 [RL1FD1_00358A2 RL1FD1_00358B2 Common Cause: Group Low RX Level Output 2.1454E+001 RL1FD1_00358C2] Relays, 3/4 2.1454E+001 140 [RLI FD 10A0740K7A RL1 FD1 10A0740K7B Common Cause: Group RELAY3, 4/4 2.1454E+001 RL1 FDl10A0740K8A RL1lFDl 1A0740K8B] __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _

141 [RL1FD1 10A074K36A RL1 FD1 10A074K36B] Common Cause: Group RELAY4, 2/2 2.1454E+001

[SWDFD1_LS003058A 142 SWDFDLLSO003058B SWDFD1_LS003058C Bistables, 4/4 2.1454E+001 SWDFD1_LS003058Ds 1 [SWDFD1_LS003058B Common Cause: Group Low RX Level 2.1454E+001 SWDFD1 LS003058D] Bistables, 3/4

[SWDFD1I_LS003058A]

[SWDFD1_LS003058A Common Cause: Group Low RX Level 144 SWDFD1 LS003058B Bistables, 3/4 2.1454E+001 SWDFD1 LS003058CA

[SWDFD1_LS003058A Common Cause: Group Low RX Level SWDFD1_LS003058D] Bistables, 3/4 .1454

[SWDFD1 _LS003058A]

[SWDFD1_LS003058A Common Cause: Group Low RX Level SWDFD1_LS003058D] Bistables, 3/4 2.1454E+001 147 [RL1 FD 10A0740K7A RL1FD1 10A0740K8A Common Cause: Group Low RX Level Logic 2.1454E+001 RL1 FD1 1OA0740K8B] Relay (RHR), 3/4 2.1454E+001 148 [RLI FD11 OA0740K7B RL1 FD11 OA0740K8A Common Cause: Group Low RX Level Logic 2.1454E+001 RL1 FD110A0740K8B] Relay (RHR), 3/4 149 [RL1 FD1 10A0740K7A RL1 FD1 10A0740K7B] Common Cause: Group Low RX Level Logic 2.1454E+001

_____ _____ _____ _____ Relay (RH R), 2/4 _ _ _ _ _ _

E-107

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 150 [RL1 FD11 OA0740K7A RL1 FD11 OA0740K7B Common Cause: Group Low RX Level Logic 2.1454E+001 RL1 FD11 0A0740K8A] Relay (RHR), 3/4 151 [RL1 FD1 1OA0740K7A RL1 FD1 1OA0740K7B Common Cause: Group Low RX Level Logic 2.1454E+001 RL1 FD11 0A0740K8B] Relay (RHR), 3/4 2.1454E+001 152 [RL1 FD1 10A0740K8A RL1FD10A0740K8B] Common Cause: Group Low RX Level Logic 2.1454E+001 1A7K8 Relay (RHR), 2/4 _ ____

1 [SWDFD1_LS003058B Common Cause: Group Low RX Level 2.1454E+001 SWDFD1_LS003058D] Bistables, 2/4 2.1454E+001 154 [SWDFD1_LS003058A Common Cause: Group Low RX Level 2.1454E+001 SWDFD1_LS003058C] Bistables, 2/4 2.1454E+001 155 [RL1 FD1 14A0750K7B RL1FD1 14A0750K8A Common Cause: Group Low RX Level Logic 2.1454E+001 RL1 FD114A0750K8B] Relay (CSS), 3/4 156 [RL1 FD1 14A0750K7A RL1 FD1 14A0750K7B Common Cause: Group Low RX Level Logic 2.1454E+001 RL1 FD1 14A0750K8A RL1 FD1 14A0750K8B] Relay (CSS), 4/4 2.1454E+001 157 [RL1 FD1 14A0750K8A RL1 FD1 14A0750K8B] Common Cause: Group Low RX Level Logic 2.1454E+001 BI Relay (CSS), 2/4

[RL1 FD1 14A0750K7A RL1 FD1 14A0750K7B Common Cause: Group Low RX Level Logic 2.1454E+001 158 RL1 FD114A0750K8A] Relay (CSS), 3/4

[RL1 FD1 14A0750K7A RL1 FD1 14A0750K7B Common Cause: Group Low RX Level Logic 2.1454E+001 159 RL1 FD114A0750K8B] Relay (CSS), 3/4 2.1454E+001

[RL1 FD1 14A0750K7A RL1 FD1 14A0750K8A Common Cause: Group Low RX Level Logic 2.1454E+001 160 RL1 FD114A0750K8B] Relay (CSS), 3/4 161 PMOFR3_027_CC Loss of All Unit 3 CCW Pumps 2.0481 E+001 162 HOVXC20240500 Unit 1 CCW Intake Valve 2-24-500 Transfers 2.0481 E+001 162 __ XC___ __ _ __ __ _ __ __ _ __ __ _ Closed 163 HOVXC1_0240504 Crosstie Valve 1-24-504 Transfers Closed 2.0481 E+001 Unit 1 CCW Intake Valve 1-24-500 Transfers 2.0481 E+001 164 HOVXC1_O24O500 Closed 208 +0 165 16 OC0451RCW HOVXC2_--0240521 Header Transfers Isolation Valve 2-24-521 Closed 2.0481 E+001 166 16 OX2 HOVXC2_0240524 0454RCW Header Transfers Isolation Valve 2-24-524 Closed 2.0481 E+001 2.0481_E+001

[PMOFR1_024001A PMOFR1_024001B 167 PMOFR2 024002A PMOFR2 __024002B Common Cause: Group Raw Cooling Water 2.0481 E+001 PMOFR2=024002C PMOFR3_024003A Pumps, 7/7 PMOFR3 024003B]

168 HOVXC3 0240500 Unit 3 CCW Intake Valve 3-24-500 Transfers 2.0481 E+001 Closed _ _ _ _ _ _

169 HOVXC2_0240594 RCW Header Isolation Valve 2-24-594 2.0481 E+001 Transfers Closed 170 HOVXC2_0240515 Crosstie Valve 2-24-515 Transfers Closed 2.0481 E+001 171 PMOFR1_027_CC Loss of All Unit 1 CCW Pumps 2.0481 E+001 172 PMOFR2_027__CC Loss of All Unit 2 CCW Pumps 2.0481 E+001 173 [CB1 FOOBKRO571614 CB1 FOOBKRO571616 Common Cause: Group Unit 1/2 4kv SD 1.8722E+001 CB1FOOBKRO571724] Feeder Breakers FTO, 3/4 174 [CB1 FOOBKR0571614 Common Cause: Group Unit 1/2 4kv SD 1.8722E+001 CB1 FOOBKRO571616] Feeder Breakers FTO, 2/4 1.8722E+001 E-108

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 175 [DGFTS_1_DGA DGFTS_1_DGC Common Cause: Group Diesel Generators, 1.8220E+001 DGFTS 1DGD] 3/4 _____

176 [PMSFRZ-02300B1 PMSFR2_02300B2 Common Cause: Group South Service Water 1.8125E+001 PMSFR2_02300D2] Header RHRSW Pumps, 3/4 177 [PMSFS2 02300B1 PMSFS2_02300B2 Common Cause: Group South Service Water 1.8103E+001 PMSFS2 02300D2] Header RHRSW Pumps 3/4 ___________

178 [DGFTS1-DGB DGFTSL1_DGC Common Cause: Group Diesel Generators, 1.7732E+001 DGFTSLDGD] 3/4 _____

179 DIMFR1_002CODM Insufficient Flow Thru Demin Flow Path 1.7651 E+001 180 COVLK1 0020558 Condensate Booster Pump B Discharge 1.7651 E+001 Check Valve 2-558 Gross Reverse Leakage

[PMOFR1CBPOO2002A Common Cause: Group Condensate Booster 181 PMOFRlCBPOO2002BPup,3 175E01 PMOFR1CBP002002C] Pumps, 3/3 182 MOVXC1 FCV0020041 Outlet Valve FCV 2-41 Transfers Closed 1.7651 E+001 183 COVFT1 0020558 Condensate Booster Pump B Discharge 1.7651 E+0011 Check Valve 2-558 Fails to Reseat 184 COVLK1 0020517 Condensate Pump B Discharge Check Valve 1.7651 E+0011 2-517 Gross reverse Leakage 185 COVFT1 0020517 Condensate Pump B Discharge Check Valve 1.7651 E+001 2-517 Fails to Reseat 186 [PMOFR1_CP002002A Common Cause: Group Condensate Pumps, 1.7651E+001 PMOFR1 _CP002002C] 3/3 187 MOVXC1 FCV0020036 Inlet Valve FCV2-36 Transfers Closed 1.7651 E+001 188 HXRPL1 0020FGA Excessive Leakage/Rupture Of Off-Gas 1.7651 E+001 Condenser ______

189 HXRPL1_002SJAE Excessive Leakage/Rupture (SJAE) 1.7651 E+001 190 HXRPL1 002EXHA Excessive Leakage/Rupture OF Steam 1.7651 E+001 Packing Exhauster 191 [DGFFS_1_DG3A DGFTS_1_DG3B Common Cause: Group Diesel Generators, 1.7495E+001 DGFTS_1_DG3C DGFTSlDG3D] 4/4 192 FCOFTO_1_DG3ABCD Motor Operated Vent Dampers Fail to Open or 1.7495E+001 Fans Fail to Start______

193 [DGFTS_1_DGA DGFTS_ 1_DGB] Common Cause: Group Diesel Generators, 1.6789E+001 194 [PMSFR2_02300B1 PMSFR2_02300B2 Common Cause: Group South Service Water 1.6274E+001 PMSFR2 02300D11] Header RHRSW Pumps, 3/4 1.6274E+001

[PMSFS2_02300B1 PMSFS2_02300B2 Common Cause: Group South Service Water 195 PMSFS2_02300D1] Header RHRSW Pumps 3/4 1.6259E+001 196 SWYARD Offsite Grid and Switchyard Failure 1.6168E+001 197 COVFT1 0020526 Condensate Pump C Discharge Check Valve 1.5599E+001 2-526 Fails to Reseat 1.5599E+001 198 COVFT1 0020550 Condensate Booster Pump C Discharge 1.5599E+001 Check Valve 2-550 Fails to Reseat 199 COVLK1L_0020550 Condensate Booster Pump C Discharge 1.5571 E+001 Check Valve 2-550 Gross reverse Leakage E-109

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 200 COVLK1 0020526 Condensate Pump C Discharge Check Valve 1.5571 E+001

______________ 2-526 Gross reverse Leakage 201 BUSFROShutDNBRDA Shutdown Board A Bus Fault 1.4722E+001 202 El VFD1 FCV0470067 Master Trip Valve FCV 47-67 Fails to Operate 1.4193E+001

__ __ _ __ _ _ On DemandF

[MOVFO1 FCV0230034 Common Cause: Group RHR Heat MOVFOIFCV0230052] Exchangers MOVs, 3/4 1.4158E+001 204 [DGFTSL1-DG3A DGFTS1_DG3B Common Cause: Group Diesel Generators, 1.2656E+001 DGFTS-1DG3C] 3/4 205 HOVXC1 HCV0740033 HCV-74-33 Transfers Closed 1.0932E+001 206 HOVXC11SV0670610 Valve 67-610 Transfers Closed 1.0932E+001 207 HOVXC1HCV0670603 Valve 67-603 Transfers Closed 1.0932E+001 208 HOVXC1 ISV0670609 Valve 67-609 Transfers Closed 1.0932E+001 209 HOVXC11SV0670602 Valve 67-602 Transfers Closed 1.0932E+001 210 HOVXC1 1SV0670605 Valve 67-605 Transfers Closed 1.0932E+001 211 HOVXC1 HCV0740089 HCV-74-89 Transfers Closed 1.0932E+001 212 [PMSFR2 02300B1 PMSFR2_02300B2] Common Cause: Group South Service Water 1.0764E+001 Header RHRSW Pumps, 2/4 213 [PMSFS2_02300B1 PMSFS2_02300B2] Common Cause: Group South Service Water 1.0763E+001

[M 1 Header RHRSW Pumps 2/4

[MOVFO1FCV0230040 Common Cause: Group RHR Heat MOVFO1 FCV0230052] Exchangers MOVs, 3/4 .0673E+001 215 MOVXC1 FCV0740024 FCV-74-24 Transfers Closed 1.0601 E+001 216 CKVFO1 CKV074559B Check Valve 74-559B Fails to Open On 1.0543E+001 Demand 217 CKVFO1CKV074560B Check Valve 74-560B Fails to Open On 1.0543E+001

___ ______ ____ ___ ___ ___ D em and 218 [FN2FS1ROOM74001B] Common Cause: Group RHR Pump Room 1.0490E+001 Coolers Fail to Start, 1/4 219 [PMSFR1PMP074001B] Common Cause: Group RHR Pumps Fail to 1.0405E+001 Run, 1/4 220 [PMSFS1 PMP074001 B] Common Cause: Group RHR Pumps Fail to 104301 Start, 1/4 221 [FN2FRlROOM74001B] Common Cause: Group RHR Room Coolers 1.0391E+001 Fail to Run, 1/4 222 HXRRPlSEAL67001B Seal Heat Exchanger1B Ruptures 1.0316E+001 223 HXRRPlHEX074901B Heat Exchanger l B Ruptures 1.0316E+001 224 HXRRPIHXR067001B Pump Room Cooler 1B (Heat Exchanger 1.0316E+001 HXRRP1 HXRO67001 BData) Ruptures ______

225 COVXC0_0240563 Check Valve 0-24-563 Manual Valve 0 9.4777E+000 26 CVC_0240577________________ 562 Transfer Shut _________

226 COVXC& 0240577 Check Valve 0-24-577 Manual Valve 0 9.477E+000

_ __ __ _ __ _ _ _ _ _ _ _ _ _ 578 Transfer Shut I _ _ __ _ _

E-110

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 227 HOVXCO 0240523 Manual Valve 0-24-523, -554 Transfer Shut 9.4777E+000 228 COVPL1-0322171 Check Valve 32-2171 PLUGS 9.4316E+000 229 HOVXC0_0240681 Manual Valve 0-24-681 Transfers Shut 9.4316E+000 230 HOVXC0_0241052 Manual Valve 0-24-1052 Transfers Shut 9.4316E+000 231 COVPL1 0320243 Check Valve 32-0243 Plugs 9.4316E+000 232 R2VPOO 0320556 Relief Valve 0-32-556 Premature Open 9.4316E+000 233 R2VPO000320551 Relief Valve 0-32-551 Premature Open 9.4316E+000 234 HOVXC1 _0320211 Manual Valve 32-211 Transfers Shut 9.4316E+000 235 HOVXC1 0322370 Manual Valve 32-2370 Transfer Shut 9.4316E+000 236 HOVXC1 0322373 Manual Valve 32-2373 Transfer Shut 9.4316E+000 237 R2VPOO_0320546 Relief Valve 0-32-546 Premature Open 9.4316E+000 238 HOVXC1l 0320975 Manual Valve 032-975 Transfers Closed 9.4316E+000 239 FLTPL1LO32AFLT After filter Plugs 9.4316E+000 240 RCVRPO 032RCVR1 Air Receiverl Rupture 9.4316E+000 241 RCVRP0_032RCVR2 Air Receiver2 Rupture 9.4316E+000 242 RCVRPO0_032RCVR3 Air Receiver3 Rupture 9.4316E+000 243 FLTPL1_032PRFLT Pre-filter Plugs 9.4316E+000 244 HOVXC0_0320549 Valve 545 OR 549 Transfers Shut Given 9.4316E+000

_____ __________ _____ _____ _____ Receivers 2 and 3 Path _ _ _ _ _ _

245 [DGFTS_1 DGA DGFTS_1_DGC] Common Cause: Group Diesel Generators, 8.6384E+000 246 HER_HPHPE1 Operator Fails to Control Level With 8.3947E+000 RCIC/HPCI (Early 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />) 8.3947E+000 247 [DGFrSL1tDGB DGFTS_1_DGC] Common Cause: Group Diesel Generators, 8.1505E+000 214 248 [MOVFO1 FCV0710008] Common Cause: Group RCIC Steam Supply, 7.9722E+000

_ __ __ _ _ _ __ _ __ _ _ _ _ _ __ _ _ _ _ __ _ _ 1 /2 _ _ _ _ _ _

249 [MOVF01 FCV071 00391 Common Cause: Group HPCI RCIC Pump 7.9722E+000 Discharge MOV failure, 1/2 250 MOVFC1 FCV0710034 Valve 1-FCV-71 -34 Fails to Close On 7.9647E+000

_ _ __ _ _ __ __ __ _ _ _ _ _ _ _ _ _ _ _ _ D em and _ _ _ _ _

251 [MOVFO1 FCV0710034 Common Cause: Group HPCI RCIC Return 7.9641 E+000 MOVXC1 FCV0710038] Lines MOVs 2/4

[MOVFO1 FCV0740053 252 MOVFO1 FCV0740067] Common Cause: LPCI Injection MOVs 2/2 7.5151 E+000 253 [MOVFO1 FCV0740071 Common Cause: Group RHR Suppression 74E+00 MOVFO1 FCV0740073] Pool Cooling Valves, 2/4 254 [MOVFO1 FCV0740073] Common Cause: Group RHR Suppression 7.4193E+000 255 ____[MOVFO1FCV0740071] __________ Pool Cooling Valves, 1/4 255 [MO VF01 FCV0740071] Common Cause: Group RHR Suppression 7.41 93E+000 I _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ Pool Cooling Valves, 1/4 E-111

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 256 [DGFTS_1_DG3A DGFTS_1_DG3B Common Cause: Group Diesel Generators, 7.2844E+000 DGFTS.JLDG3D] 3/4 257 [MOVFO1 FCV0710034 Common Cause: Group HPCI RCIC Return 70326E+00 5 MOVXC1 FCV0730035] Lines MOVs 2/4 258 [DGFTS_1_DG3A DGFTS_1 DG3B] Common Cause: Group Diesel Generators, 6.9881 E+000

_ _ _ __ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 2 /4 259 RPDRP1RP71011A_6 Inboard Rupture DISC 1-RPD-71-011A Failure 6.3543E+000 260 HERHPWWV1 Operator Fails to Align Wetwell Path 6.3063E+000 261 CKVFO1 CKV0710580 Check Valve 1-CKV-71 -580 Fails to Open On 6.2600E+000

___ ___ ___ ___ ___ ___ Dem and 262 CKVFO1 CKV0710499 Check Valve 1-CKV-71 -499 Fails to Open On 6.2600E+000

___ ___ ___ ___ ___ ___ D em and 263 CKVFO1CKV0030572 RFW Line B Injection Valve 1-CKV-3-572 6.2600E+000

____ ___ ___ ____ ___ ____ ___ Fails to Open On Demand 264 CKVFO1 FCV0710040 Check Valve 1-FCV-71 -40 Fails to Open On 6.2600E+000

________ ___ ___ ____ ___ ___ D em and 265 CKVFC1CKV0030568 Check Valve 1-CKV-3-568 Fails to CLOSE 6.2600E+000 On Demand ______

266 CKVLK1 CK030568_6 Check Valve 1-CKV-3-568 Gross Backleakage 6.2524E+000 267 [RL1FD1RLY071OK22] Common Cause: Group HPCI/RCIC Relays, 6.2499E+000 1/4 _ _ _ _ _ _

268 CSVFO1 HCV0710014 Stop Check Valve 1-HCV-71 -14 Fails to 6.2259E+000 2 Open On Demand -7rseCod60 269 MOVXC1 FCV71037_6 Valve 1-FCV-71 -37 Transfers Closed 6.2036E+000 270 MOVXC1lFCW1019._6 Valve 1-FCV-71-19 Transfers Closed 6.2036E--000 271 MOVXC1FCV7102_6 Valve 1-FCV-71-2 Transfers Closed 6.2036E+000 272 MOVXC1 FCV07103_6 Valve 1-FCV-71 -3 Transfers Closed 6.2036E+000 273 MOVX01 FCV71 038-6 Valve 1-FCV-71 -38 Transfers Open 6.2036E+000 274 SWLFD1_LS0710029 Level Switch 1-LS-71-29 Fails to Operate On 6.1845E+000 Demand 275 PTSFS1PMP0710019 RCIC Pump Fails to Start On Demand 6.1570E+000 276 PTSFR1PMP71019_6 RCIC Pump Fails to RUN 6.1079E+000 277 MOVXO1 FCV71034_6 Valve 1-FCV-71 -34 Transfers Open 5.9884E+000 278 MOVXC1 FCV07108_6 Valve 1-FCV-71-8 Transfers Closed 5.9884E+000 279 MOVXC1 FCV71039_6 Valve 1-FCV-71 -39 Transfers Closed 5.9884E+000 280 HOVXC1 HCV3066 6 RFW Line B Valve 1-HCV-3-66 Transfers 5.9691 E+000 281__________________________

MeClosed _

281 MOVXC1 FCV0740071 Valve FCV-74-71 Transfers Closed 5.7258E+000 282 MOVXCNa FCV0740073 Valve FCV-74-73 Transfers Closed 5.7258EO000 283 RHR Neat Exchangers MOVs Common Cause: Group HXMOV, 2/4 5.7228E+000 MOVF01 FCV0230046] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

284 [MOVXC1 FCV0730035 Common Cause: Group HPCI RCIC Return 5.6877E+000 MOVXC1 FCV0730036] Lines MOVs 2/4 5.6877E+000 E-112

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 285 [MOVXC1 FCV0710038 Common Cause: Group HPCI RCIC Return 5.6877E+000 MOVXC1 FCV0730036] Lines MOVs 2/4 286 [MOVXC1 FCV0710038 Common Cause: Group HPCI RCIC Return 5.6877E+000 MOVXC1 FCV0730035] Lines MOVs 2/4 287 [MOVXC1 FCV0730036] Common Cause: Group HPCI RCIC Return 5.6819E+000

____ ___ ___ ____ ___ ____ ___ Lines M OVs 1/4 288 MOVFO1 FCV0730036 MOV 1-FCV-73-36 Fails to Open On 5.6785E+000 Demand

[MOVXC1 FCV0710038 Common Cause: Group HPCI RCIC Return 289 MOVXCII FCV0730035LieMOs3567900 MOVXC1 FCV0730036] Lines MOVs 3/4 290 HERHPHPR1 Operators FAIL to Recover Control HPCVRCI 5.5781 E+000 After L8 Trip 291 CONDENSER_2A2B2C Main Condenser Unavailable After Plant Trip 5.5122E+000 292 HOVXCII1SV0640737 LO Manual Valve FCV-64-737 Transfers 5.364E+00 Closed During Operation 5.3644E+000 293 AOVFO1 FCV0640222 FCV 64-222 Fails to Open On Demand 5.3644E+000 294 AOVFO1 FCV0640221 FCV 64-221 Fails to Open On Demand 5.3644E+000 295 AOVXC1 FCV0640222 FCV 64-222 Transfers Closed During 5.3644E+000 Operation _ _ _ _ _ _

296 AOVXC1 FCV0640221 FCV 64-221 Transfers Closed During 5.3644E+000 297OVXC_032_3754 ManuaVale323754TranfersClosd.3Operation6_______

297 HOVXC1_032_3754 Manual Valve 32-3754 Transfers Closed 5.3644E+000 298 HOVXC1_032_2704 Manual Valve 32-2704 Transfers Closed 5.3644E+000 299 H-OVXC1 032 2703 Manual Valve 32-2703 Transfers Closed 5.3644E+000 300 [PMOFR1_CP002002A Common Cause: Group Condensate Pumps, 5.1829E+000 PMOFR1 CP002002B] 2/3 301 [MOVFO1FCVO730016] Common Cause: Group RCIC Steam Supply, 5.1630E+000 1/2 302 [MOVFO1 FCV0730044] Common Cause: Group HPCI RCIC Pump 5.1630E+000 Discharge MOV failure, 1/2 303 Cause:

Lines MOVs 1/4 Group HPCI RCIC Return MOXIFV703]Common 33 [MOVXC1FCV0730035] 5.1630E+000 304 MOVFO1 FCV0730027 MOV 1-FCV-73-27 Fails to Open On 5.1608E+000 Demand 305 MOVFO1 FCV0730035 MOV 1-FCV-73-35 Fails to Open On 5.1608E+000 306 MDem

_______________________________ and 306 MOVF01 FCV0730026 MOV I FCV-73-26 Fails to Open On 5.1608E+000

___ ___ ___ ___ ___ ___ D em and 307 MOVFC1FCV0730040 MOV 1-FCV-73-40 Fails to CLOSE On 5.1608E+000

___ ____ ___ ___ ___ D em and 308 RHR Neat Exchangers MOVs Common Cause: Group HXMOV, 2/4 5.0833E+000 MOVF01 FCV0230052] _________________

309 CKVFO1 CKV0730517 Check Valve 1-CKV-73-517 Fails to Open On 4.8865E+000 Demand E-1 13

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 310 RHRDSGRUP0750000 RHR Discharge Fails to Remain Intact/ 4.8830E+000 Rupture 311 [MOVFO1 FCV0230034] Common Cause: Group RHR Heat Exchanger 4.7769E+000 MOVs, 1/4 ___________

312 MOVXC1 FCV0020171 MOV 1-FCV-2-171 Transfers Closed During 4.7488E+000 Operation _ _ _ _ _ _

313 [PMSFR2 02300A1 PMSFR2_02300A2 Common Cause: Group South Service Water 47393E+000 PMSFR2_02300C1 PMSFR2Z02300C2] Header RHRSW Pumps, 4/4 ___________

314 [PMSFS2 02300A1 PMSFS2-02300A2 Common Cause: Group Condensate Pumps 47393E 000 PMSFS2o02300C1 PMSFS2..02300C2] 4/4 ___________

315 COVPL1t0760551 Check Valve 076-0551 Fails to Open, 47300E+00 Plugged, Transfers Closed ___________

316 COVPL1 0760552 Check Valve 076-0552 Fails to Open, 47300E+00 Plugged, Transfers Closed ___________

317 HOVXC1 0322515 Manual Valve S 32-2515,2520, 4011, 4009, 4.7300E-000 2529 Transfer Shut ___________

318 COVPL1 0322516 Check Valve S 32-2516, 2528, 2521 FAIL to 4.7300E+000 Open, Plugged, TRAN 4.7300E+000 319 FLTPL1_032CFLT Drywell Loads (C)Air Filter Plugged 4.7300E+000 320 3COVPL1_0760405 Check Valve

_Transfers 076-0405 Fails to Open, Plugs, Closed 4.7300E+000 321 HOVXC1 0322253 Manual Valve S 32-2253,2160, 4010, 4008, 4.7300E+000 1736, Transfer Shut 4.7300E+000 322 COVPL1 _0322163 Check Valve S 32-2163 336 FAIL to Open, 4.7300E+000 Plugged, Transfer Closed 323 FLTPL1_032BFLT Drywell Loads (B)Air Filter Plugged 4.7300E+000 324 HOVXC1_0760538 Manual Valve 076-0538 Transfers Closed 4.7300E+000 325 HOVXC1 0760310 Manual Valve 076-0310 Transfers Closed 4.7300E+000 326 CSVFO1 HCV0730023 Fails to P Check Valve 1-HCV-73-23 Fails to 4.6911 E+000 Open On Demand 4.6911_E+00 327 TBSFDST Turbine Bypass System Unavailable for Short 4.6891 E+000 Term Pressure Relief 328 HOVXC1 HCV0230031 Valve HCV-23-31 Transfers Closed 4.6424E+000 329 CKVFO1 CKV0230510 Check Valve CKV-23-51 0 Fails to Open On 4.6358E Demand 330 HXRPL1 HEX074900A Heat Exchanger 1A Plugs 4.6319E+000 331 [SWL1_LS073056A SWL1_LS073056B] Common Cause: Group SWTCH, 2/2 4.6311 E+000 332 CKVXC1 CKV0230510 Check Valve CKV-23-51 0 Transfers Closed 4.6302E+000 333 MOVXC1 FCV0230034 Valve FCV-23-34 Transfers Closed 4.6283E+000 334 XR2FR1 _C_1 BTS11B Transformer TS11B Fails During Operation 4.5971 E+000 335 BUSFR1_480VBRD1 B 480V Shutdown Bus 1B Fails 4.5971 E+000 336 CB1XO04KVBDC20 Input Breaker 20 Transfers Open 4.5971 E+000 337 CB1XO148OBD1 B_1C Output Breaker 1C Transfers Open 4.5971 E+000 E-1 14

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 338 MOVXC1 FCV73040C6 MOV 1-FCV-73-40 Transfers Closed During 45943E+000

______________ Operation 4.5943E+000 339 MOVXC1 FCV73003 6 MOV 1-FCV-73-3 Transfers Closed During 45943E00

_ _ __ __ _ __ _ _ __ Operation 340 MOVXC1 FCV73002_6 MOV 1-FCV-73-2 Transfers Closed During 4.5943E+000 Operation 341 CKVFO1 CKV0030558 RFW Check Valve 1-CKV-3-558 Fails to 4.5918E+000 Open On Demand 342 CKVFC1 CKV0030554 Feedwater Check Valve 1-CKV-3-554 Fails to 4.5918E+000 Close On Demand 343 CKVFO1CKV0730603 Check Valve 1-CKV-73-603 Fails to Open On 4.5918E+000 Demand 344 CKVFO1 FCV0730045 Testable Check Valve 1-FCV-73-45 Fails to 4.5918E+000 Open On Demand 345 CKVFO1 CKV0730505 Check Valve 1 -CKV-73-505 Fails to Open On 4.5918E+000 Demand 346 CKVFO1CKV0730566 Check Valve 1-CKV-73-566 Fails to Open 4.5918E+000 347 [RL1FD123AK21] Common Cause: Group HPCI/RCIC Relays, 4.5425E+000 8 [RL1FD123AK22] 1/4 348 [RL1FD123AK22] Common Cause: Group HPCI/RCIC Relays, 4.5425E+000 1/4 [ CR K G F _C P C s5 349 [RL11RLY23AK25] Common Cause: Group HPCI/RCIC Relays, 4.5425E+000

_ __ __ _ __ _ __ __ _ __ _ _ __ _ _ _ _ _ _ _ __ _ 1 /4 _ _ _ _ _ _

350 [RL1 1RLY23AK25 RL1 FD1 23AK21 Common Cause: Group HPCI/RCIC Relays, 4.5350E+000 351 [RLlFD123AjK21 RL1FD123AK22D] Common Cause: Group HPCI/RCIC Relays, 4.5350E+000 352 [RL1 1RLY23AK25 RL1 FD1 23AK22] ComnCus:Gop4PVCC eas .5350E+000 353 FCV04 Feedwater Check Valve 1-CKV-3-554 4.5286E+000 35356 PTSFS1

[MVOCV705CMP0730054 Gross reverse HPCIPumaDevelops Common Cause: Leakage Group RHPRCSuCprelasion 4 351 [PMSFR2_02300132 PMSFR2_02300D1 Common Cause: Group South Service Water 4.4790E+000 PMSFR2 02300D2] Header RHRSW Pumps, 3/4 4.4539E+000 355 [MOVFO1 FCV0740057 Common Cause: Group RHR Suppression 4.4750E+000 MOVF01 FCV0740059J Pool Cooling Valves, 21/4 4.4539E+00 356 PTSFS1 PMP0730054 HPCI Pump Fails to START On Demand 4.4627E+000 357 [PMFS202300B2 PMSFSZO2300D1 Common Cause: Group South Service Water 4.4539E+000 PMSFS2._02300D2] Header RHRSW Pumps 3/4 _ ____

358 [MO VF01 FCV0740059] Common Cause: Group RHR Suppression 4.459E400 Pool Coaling Valves, 1/4 ______

359 MOF1CV705]Common Cause: Group RHR Suppression 4.4539E+000

[MOVFO1 FCV0740057]Pool Cooling Valves, 1/4 ______

360 PTSFR1 PMP73054_6 HPCI Pump During Operation 4.4301 E÷000 361 MOVXC1 FCV73044_6 MOV 1-FCV-73-44 Transfers Closed During 4.4113E+000 Operation 4.4113E+000 362 MOVXCl FCV73027 6 MOV 1-FCV-73-27 Transfers Closed During 4.411 3E+000 I _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ Operation _ _ _ _ _ _

E-115

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 363 MOVXC1 FCV73026 6 MOV 1-FCV-73-26 Transfers Closed During 4.411 3E+000

____ ____ ____ ____ ____ ____ ____ O peration_ _ _ _ _ _ _

364 MOVX01 FCV73040_6 MOV 1-FCV-73-40 Transfers Open AFTER 4.411 3E+000 MOVXC1 FCV73016_6 365 TasesldSWITCHOVER 365 MOVXC1 FCV7301646 MOV 1-FCV-73-16 Transfers Closed During 4.411 3E+000

____ ____ _____ ____ ____ ____ Operation _ _ _ _ _ _

366 MOVXC1 FCV73034-6 MOV 1-FCV-73-34 Transfers Closed During 4.411 3E+000 Operation _ _ _ _ _ _

367 HOVXC1 HCV73025 6 Manuai Vaive 1-HV-73-25 Transfers Closed 4.3679E+000

____ ___ ___ ___ ___ During Operation 368 HOVXC1 HC30067_6 RFW Valve 1-HCV-3-67 Transfers Closed 4.3679E+000 369 [CBI1 FO3BKRO571334 CB1 F03BKR0571336 Common Cause: Group Unit 3 4kV Shutdown 4.3508E+000 CB1 FO3BKR0571338] Boards feeder Breakers FTO, 3/4 4.3508E+000 370 [CB1 FO3BKRO571334 CB1 FO3BKRO571336 Common Cause: Group Unit 3 4kV Shutdown 4.3508E+000 CBI1 F03BKR0571338 CB1 F03BKR0571342] Boards feeder Breakers FTO, 4/4 371 [RL11RLY23A_K25 RL1FD123AK21 Common Cause: Group HPCI/RCIC Relays, 4.3466E+000 RL1 FD1 23AK221 3/4 ' _4.3466E+000 372 RPDRP1 RP73020 6 Inboard Rupture Disc1 -RPD-073- 020 4.3372E+000

__ Ruptures Causing HPCI Isolation 373 BUSFR1_UNITBRD1A 4KV Unit Board 1A 4.0393E+000 374 [PMSFR2_02300A1 PMSFR2_02300A2 Common Cause: Group North Service Water 4.0278E+000 PMSFR2 02300C2] Header Pumps, 3/4 375 [PMSFS2_02300A1 PMSFS2_02300A2 Common Cause: Group North Service Water 40277E+00 PMSFS2_02300C2] Header RHRSW Pumps 3/4 376 CSDSCGRUP0740000 Core Spray Discharge Fails to Remain 4.0240E+000 Intact/Ruptures ______

377 CVCC3526RFW Line B Injection Valve 1-CKV-3-572 3.9845E+00 377 CKVXC1CK30572_6 Transfers Closed 3.9845E+000 378 CKVXC1 CK710580_6 Check Valve 1-CKV-71-580 Transfers Closed 3.9845E+000 379 CKVXC1 FCV71040-6 Check Valve 1-FCV-71-40 Transfers Closed 3.9845E+000 380 CKVXC1 CK710499 6 Check Valve 1-CKV-71-499 Transfers Closed 3.9845E+000 381 CSVXC1 HCV71014_6 Stop Check Valve 1-HCV-71-14 Transfers 3.9706E+000

__ _ __ __ _ _ _ __ _ __ _ _ _ _ _ _ _ _ __ _ _ __ _ _ __ C losed _ _ _ _ _ _

382 CB1 XO1 480SD1 B_3B Feeder Breaker 3B Transfers Open During 3.9668E+000

_____ ____ ____ ____ ____ Operation. _ _ _ _ _ _ _

383 BUS DuringFeeder Breaker 2D Transfers Open CWRMV 1B2 3.9668E+O000 CB1XO1 RMOV_l B_2D 363 Operation. 3.9668E+000 384 BUSFR1 480VRMOVl B 480V RMOV BD 1B BUS 3.9668E+000 385 [PMSFR2_02300A1 PMSFR2_02300A2 Common Cause: Group North Service Water PMSFR2_02300C1] Pumps, 3/4 3.8951E+000 386 [PMSFS2_02300A1 PMSFS2_02300A2 Common Cause: Group North Service Water 3.8949E+00 PMSFS2_02300C1] Header RHRSW Pumps 3/4 3.8949E+000 387 CKVXC1CK730603_6 Check Valve 1-CKV-73-603 Transfers Ciosed 3.8252E+000 38_ KVC CK730505____6_____________ _ During Operation 3.8252E+000 388 CKVXC1 CK730505 6 Check Valve 1-CKV-73-505 Transfers Closed 3.8252E+000

_____ __________ _____ _____ _____ During Operation _ _ _ _ _ _

E-116

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 389 CKVXC1 FCV73045_6 Testable Check Valve 1-FCV-73-45 Transfers 3.8252E+000 Closed__ _ _ _ _

390 CKVXC1 CK030558 6 RFW Check Valve 1-CKV-3-558 Transfers 3.8252E+000

____ ______ ____ ___ ____ ___ C losed 391 CKVXC1 CKV0730566 Check Valve 1-CKV-73-566 Transfers Closed 3.8252E+000

____ ______ ____ ___ ____ ___ During Operation 392 CKVXC1 CK730517_6 Check Valve 1-CKV-73-517 Transfers Closed 3.8252E+000 39 _B1O48B2_1C_____________________ O Operation BDuring 393 CBlXO248OBD2A-lC Output Breaker i C Transfers Open 3.8207E+000 394 CB1XO04KV_BD_B_5 Input Breaker 5 Transfers Open 3.8207E+000 395 BUSFR2_480VBRD2A 480V Shutdown Bus 2A 3.8197E+000 396 XR2FR2_B_2ATS2A Transformer TS2A During Operation 3.8195E+000 397 CSVX1 HV7303_6Stop Check Valve 1-HCV-73-23 Transfers 3.8123E+000 37 CSVXCI HCV73023-6 Closed381E00 398 [PMSFR2_02300A1 PMSFR2._02300A2] Common Cause: Group North Service Water 3.7793E+000

___ ____ ___ ___ ___ Header RHRSW Pumps 214 399 [PSS_020A__ S2 030A CommonRHRSW Cause: Pumps Group North 2/4 Service Water 3.7792E+000

[PMSFS2_02300A1 PMSFS2_02300A2]

39 Header 400 [SWDFD1PIS003204B Common Cause: Group High RX Pressure 3.6982E+000 SWDFD1 PIS003204C] Signal Bistables, 2/4 3.698 E+000 401 [SWDFD1PIS003204B Common Cause: Group High RX Pressure 3.6982E+000 SWDFDlPIS003204D] Signal Bistables, 2/4 .6 8E+000 402 [SWDFD1 PIS003204A Common Cause: Group High RX Pressure 3.6982E+000 SWDFD1 PIS003204C] Signal Bistables, 2/4 3.698 +000 403 [SWDFD1PIS003204A Common Cause: Group High RX Pressure 3.6982E+000 SWDFD1 PIS003204D] Signal Bistables, 2/4 3.698_E+000 404 [R1D__ 30A ~ F1 0024] Common Cause: Group High RX Pressure 3.6982E+000

[RL1 FD1_003204A RL1 FD1_003204C]

404 Signal Output Relays, 2/4 3.6982E+000 405 [RL1 FD1-003204A RL1 FD1_003204D] Common Cause: Group High RX Pressure 3.6982E+000

_____ _____ _____ _____ Signal Output Relays, 2/4 _ _ _ _ _ _

406 [RL1 FD1_003204B RL1 FD1 003204C] Common Cause: Group High RX Pressure 3.6982E+000

_____ _____ _____ _____ Signal Output Relays, 2/4 _ _ _ _ _ _

407 [RL1 FD1_003204B RL1 FD1 003204D] Common Cause: Group High RX Pressure 3.6982E+000

___ ____ ___ ____ ___ Signal Output Relays, 2/4 408 [RL1 FD1_003204A RL1 FD1_003204B Common Cause: Group High RX Pressure 3.6982E+000 RL1 FD1_003204C] Signal Output Relays, 3/4 409 [RL1 FD1_003204A RL1 FD1 003204B Common Cause: Group High RX Pressure 3.6982E+000 RL1 FD1_003204D] Signal Output Relays, 3/4 410 [RL1 FDl_003204A RL1 FD1_003204C Common Cause: Group High RX Pressure 3.6982E+000 RL1 FD1_003204D] Signal Output Relays, 3/4 411 [RL1 FD1_003204B RL1 FD1_003204C Common Cause: Group High RX Pressure 3.6982E+000 RL1 FD1_003204D] Signal Output Relays, 3/4 412 [SWDFD1 PIS003204B SWDFD1 PIS003204C Common Cause: Group High RX Pressure 3.6982E+000 SWDFDlPIS003204D] Signal Bistables, 3/4 413 [SWDFD1PIS003204A SWDFD1PIS003204B Common Cause: Group High RX Pressure 3.6982E+000 SWDFD1 PIS003204C SWDFD1 PIS003204D] Signal Bistables, 4/4 E-117

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 414 [SWDFD1PIS003204A SWDFD1PIS003204B Common Cause: Group High RX Pressure 3.6982E+00o SWDFD1 PIS003204C] Signal Bistables, 3/4 .

415 [SWDFD1 PIS003204A SWDFD1 PIS003204B Common Cause: Group High RX Pressure 3.6982E+000 SWDFD1PIS003204D] Signal Bistables, 3/4 416 [SWDFD1 PIS003204A SWDFD1 PIS003204C Common Cause: Group High RX Pressure 3.6982E+00o SWDFD1 PIS003204D1 Signal Bistables, 3/4 417 [RL1FD1_00358C4 RL1 FD1_00358C5] Common Cause: Group RELAY2, 2/2 3.6982E+000 418 [RL1 FD1_003204A RL1 FD1_003204B Common Cause: Group High RX Pressure 3.6982E+000 RL1FD1_003204C RL1FD1_003204D] Signal Output Relays, 4/4 419 [CB1 F03BKRO571334 CB1 F03BKRO571336 Common Cause: Group Unit 3 4kV Shutdown 3.6103E+000 CB1 F03BKRO571342] Boards feeder Breakers FTO, 3/4 420 [CB1 FO3BKRO571334 Common Cause: Group Unit 3 4kV Shutdown 3.6103E+000 CB1 FO3BKRO571336] Boards feeder Breakers FTO, 2/4 421 BATFDIBAT057-SBA Battery SB-A Fails on Demand 3.4235E+000 422 BUSFR1BUS057-SBA SB-A BUS 3.4235E+000 423 [PMSFR2_02300B1 PMSFR2_02300D1 Common Cause: Group South Service Water 3.4170E+000 PMSFR2_02300D2] Header RHRSW Pumps, 3/4 424 [MGSFR1 RPSMGSETA Common Cause: Group Motor Generator Sets 3.4140E+000 MGSFR1RPSMGSETB] Fail, 2/2 425 [PMSFS2 02300B1 PMSFS2_02300D1 Common Cause: Group Condensate Pumps 3.3993E+000 PMSFS2_02300D2] 3/4 426 [RV2FO1 PCV001 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FO1 PCV0010031 RV2F01 PCV0010034] Fail to Depressurize, 4/6 3.3 +000 427 [RV2FO1 PCV001 0019 RV2FO1 PCV001 0022 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FO1 PCV0010031 RV2FO1 PCV0010034] Fail to Depressurize, 4/6 428 0030

[RV2FO1 PCVOO1 0019 RV2FO1 PCV0010034] Common Cause: Group Safety Relief Valves 33685E+0 RV2FO1 PCV001 0031 RV2FO1 PCV001 Fail to Depressurize, 4/6 429 [RV2FO1 PCVOO1 0019 RV2FO1 PCV001 0022 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FO1 PCVOO1 0030 RV2FO1 PCV001 0034] Fail to Depressurize, 4/6 430 [RV2FO1 PCV001 0005 RV2FO1 PCVo01 0022 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FO1 PCV0010031 RV2FO1 PCV0010034] Fail to Depressurize, 4/6 431 [RV2FO1 PCVOO1 0005 RV2FO1 PCVOO1 0030 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FOI PCV0010031 RV2FO1 PCV0010034] Fail to Depressurize, 4/6 432 [RV2FOI PCV001 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FO1 PCVOO1 0030 RV2FO1 PCV001 0034] Fail to Depressurize, 4/6 433 [RV2FO1 PCVOO1 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FO1 PCV001 0022 RV2FO1 PCVOO1 0034] Fail to Depressurize, 4/6 434 [RV2FO1 PCV001 0022 RV2FO1 PCV001 0030 Common Cause: Group Safety Relief Valves 3.3685E+000 RV2FO1 PCV001 0031 RV2FO1 PCVOOI 0034] Fail to Depressurize, 4/6

[RV2FO1 PCV001 0005 RV2FO1 PCVOO1 0022 Common Cause: Group Safety Relief Valves 33685E+OOO 435 RV2FO1 PCV001 0030 RV2FO1 PCV001 0034] Fail to Depressurize, 4/6 436 [RV2FO1 PCV001 0019 RV2FO1 PCVOOI 0022 Common Cause: Group Safety Relief Valves 3.3679E+000 RV2FOI PCV001 0030 RV2FO1 PCV001 0031] Fail to Depressurize, 4/6 437 [RV2FO1 PCV001 0005 RV2FO1 PCVOO1 0019 Common Cause: Group Safety Relief Valves 3.3679E+000 RV2FO1 PCV001 0030 RV2FO1 PCV001 0031] Fail to Depressurize, 4/6 438 [RV2FO1 PCV001 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves 3.3679E+000 RV2FOI PCV001 0022 RV2FO1 PCV001 0031] Fail to Depressurize, 4/6 E-118

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth

[RV2FO1 PCV001 0005 RV2FO1 PCV001 0019 Common Cause: Group Safety Relief Valves 3.3679E+000 RV2FO1 PCV001 0022 RV2FO1 PCV001 00301 Fail to Depressurize, 4/6 .36

[RV2FO1 PCV001 0005 RV2FO1 PCV001 0022 Common Cause: Group Safety Relief Valves 3.3679E+000

___ RV2FO1 PCV001 0030 RV2FO1 PCV001 0031] Fail to Depressurize, 4/6

[DGFTS_1_DG3A DGFTS_1_DG3C Common Cause: Group Diesel Generators, 33159E+000 441 DGFTS_1_DG3D] 3/4 442 [DGFTS_1_DGA DGFTS_1_DGD] Common Cause: Group Diesel Generators, 3.1903E+000 2/4 443 [MGSFR1RPSMGSETA] Common Cause: Group Motor generator Sets 3.0742E+000

__ I __ Fail, 1/2 444 BATFDIBAT057_SBC Battery SB-C On Demand. 3.0735E+000 445 BUSFR1BUS057_SBC SB-C BUS 3.0735E+000 446 BKRXO1 RPSBUSA902 Distribution Panel Feeder Breaker 902 3.0731 E+000

_____ ______ _____ Transfers Open_ _ _ _ _ _

447 CTRXO1RPSBUSA1A1 Protection Contactor lAl Transfers Open 3.0731 E+000 448 CTRXO1 RPSBUSA1 A2 Protection Contactor 1A2 Transfers Open 3.0731 E+000 449 BUSFR1 RPSBUS001 A RPS BUS A Fails During Operation 3.0731 E+000 450 BKRXO1 RMOV1 AO13A 480V RMOV BD 1A Breaker 13A Transfers 3.0731 E+000

__ __ _ _ __ __ __ _ _ _ _ _ _ _ _ _ _ _ _ O pen _ _ _ _ _

451 FSWFR1 MB057_XC Charger Output Fuse Switch Transfers Open. 3.0269E+000 452 CB1FOlMB05717B1 Charger Input Breaker 17B1 Open. 3.0269E+000 453 CHGFR1 MB057_SBC Charger SB-C During Operation 3.0269E+000 454 [DGFTS_1_DG3A DGFTS_1_DG3C] Common Cause: Group Diesel Generators, 3.0194E+000 455 ___FR

[PMSFR2_0230081 455 020B PMSFR2_...02300D1]

MF: 20D]Common Cause: Pumps, Header RHRSW Group South 2/4 Service Water 2.8902E+000 456 [PMSFS2_02300B1 PMSFS2___SFSHeader 02300D1] CommonRHRSWCause: Pumps Group South 2/4 Service Water 2.8895E+000 457 [PMSFR_ [PMSR202300B2 23002 PMSFR2_02300D2]

PSFR2...0230D2] Common Cause: Pumps, Header RHRSW Group South 2/4 Service Water 2.8475E+000 458 [PMSFS2_ 02300B2 PMSFS2_02300D2] Common Cause: Group South Service Water 2.8446E+000

____________ ___ ____ ____ ___ Header RHRSW Pumps 214 459 DCAFLD Line Break in Drywell Control Air 2.8222E+000 460 PCAFLD Line Break in Plant Control Air 2.8222E+000 461 461 RADMONITOR RADMONITOR Spurious Resulting Operation of Radiation Monitor in MSIV Closure 282 2.8221 E+000 +0 462 BUSFR3SHTDBRD3EA Shutdown BD 3EA Bus Fault 2.8144E+000 463 [PMSFS1PMP074001A Common Cause: Group RHR Pumps Fail to 2.8130E+000 463 PMSFS1PMP074001D] Start, 2/4 2.8130E+000 464 [FN2FS1ROOM74001A Common Cause: Group RHR Pump Room 2.7997E+000 FN2FS1 ROOM74001 D] Coolers Fail to Start, 2/4 2.7997E+000 465 BUSFRICAB3PNL9_9 I&C Bus B Panel 9-9 CAB 3 Unit 1 Failure. 2.7809E+000 4s6 [FN2FS1 ROOM74001A] Common Cause: Group RHR Pump Room 2.7733E+000

______ ______ ______ Coolers Fail to Start, 1/4 _ _ _ _ _ _

E-119

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 467 [PMSFR2O02300B1 PMSFR2_02300D2] Common Cause: Group South Service Water 2.7656E+000 Header RlHRSW Pumps, 2/4 _____

468 [PMSFS2 02300B1 PMSFS2 02300D2] Common Cause: Group South Service Water 2.7641 E+000

_Header RHRSW Pumps 2/4 469 [RL1FD1RLY1OAK58A Common Cause: Group RLY, 2/2 2.7618E+000 RL0D1FTRLY1AK58B] ___________

470 MOVXC1 FCV0740057 Valve FCV-74-57 Transfers Closed 2.7604E+000 471 MOVXC1 FCV0740059 Valve FCV-74-59 Transfers Closed 2.7604E+000 472 [PMSFS1 PMP074001A] Common Cause: Group RHR Pumps Fail to 2.7417E+000

_ __ __ __ _ __ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ S tart, 1/4 473 ___R203 473 [PMSFR2 02300B2 B PMSFR2_02300D1]

MFR _200I]Common Header RHRSWCause: Pumps, Group South 2/4 Service Water 2.7242E+000 474 CKVF01CKV074560A Check Valve 74-560A Fails to Open On 2.7224E+000 CKVFO1 CKV074560ADemand______

475 CKVF01CKV074559A CKVFO1 Check Valve 74-559A Fails to Open On 2.7224E+000 CKV074559ADemand______

476 [PMSFS2_02300B2 PMSFS2_02300D1] Common Cause: Group South Service Water 2.7222E+000 Header RHRSW Pumps 2/4 477 FSWFR1 MB057__XA Charger Output Fuse Switch Transfers Open 2.7141 E+000 478 CB1FOIMB05716C1 Charger Input Breaker 16C1 Open. 2.7141 E+000 479 CHGFRI MB057_SBA Charger SB-A During Operation 2.7141 E+000 480 [PMSFR2 02300Bl] Common Cause: Group South Service Water 2.71 39E+000 480__ [PSR_02300B1]_____________ _ Header RHRSW Pumps, 1/4 481 [PMSFS2_0230061] Common Cause: Group South Service Water 2.7132E+000

___ ____ ___ ___ ___ Header RHRSW Pumps 1/4 482 COVFO2_0230522 Check Valve 0-23-522 Fails to Open On 2.7111 E+000

___ ____ ___ ___ ___ Dem and 483 HOVXC2_0230523 Manual Valve 0-23-523 Transfers Closed 2.7099E+000 484 HOVXC2_0230524 Manual Valve 0-23-524 Transfers Closed 2.7099E+000 485 COVXC2_0230522 Check Valve 0-23-522 Transfers Closed 2.7079E+000 486 CB1XO248OSD2A_3A Feeder Breaker 3A Transfers Open During 2.7037E+000

_Operation.

487 CBlXO2RMOV_2A_3D BUS Feeder Breaker 3D Transfers Open 2.7037E+000 DDuring Operation.

488 BUSFR2480VRMOV2A 480V RMOV BD 2A Bus 2.7037E+000 489 [PMSFR1PMP074001A] Common Cause: Group RHR Pumps Fail to 2.7025E+000 490 _[DGFTS __1_DGBDGFTS_1_DGD] C 1/42.7025E+000 C r erRun, 490 [DGFTS_1_DGB DGFTS_1_DGD] Common Cause: Group Diesel Generators, 2.7025E+000

_ ~~~2/4 _ _ _ _ _

491 [DGFTS_1_DG3A DGFTS_1_DG3D] Common Cause: Group Diesel Generators, 2.69782+000

_ _ 2/4 492 [FN2FR1ROOM74001A] Common Cause: Group RHR Room Coolers 2.6942E+000 493 __MOVXC1_FCV0740001 _FCV-74-1_TFail to Run, 1/4 2.6791 E+00 493 MOVXCI FCV0740001 FCV-74-1 Transfers Closed 2.6791 E+000 E-120

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 494 [DGFTS_1-DG3A]

[DGFTSDG3AI1/4 Common Cause: Group Diesel Generators, 2.6693E+000 495 HOVXC1HCV0740010 HCV-74-10 Transfers Closed 2.6513E+000 496 HOVXC1 1SV0670567 Valve 67-567 Transfers Closed 2.6512E+000 497 HOVXC1 1SV0670571 Valve 67-571 Transfers Closed 2.6512E+000 498 HOVXC1 HCV0740086 HCV-74-86 Transfers Closed 2.6512E+000 499 HOVXC1 1SV0670570 Valve 67-570 Transfers Closed 2.6512E+000 500 HOVXC1 ISV0670574 Valve 67-574 Transfers Closed 2.6512E+000 501 HOVXC1 HCV0670572 Valve 67-572 Transfers Closed 2.6512E+000 502 [FCOFO_1_FCO_230C Common Cause: Group Unit 3 DG Dampers, 2.6416E+000 FCOFO&1-FCC 231C] 2/2 503 [FN2FTSLDG3A FANA Common Cause: Group Unit 3 DG Fans, 2/2 2.6404E+000 FN2FTSLDG3AFANB]

504 HXRRP1 HEX074901 A Heat Exchanger 1A Ruptures 2.6384E+000 505 HXRRP1SEAL74001A Seal Heat Exchanger 1A Ruptures 2.6384E+000 506 HXRRP1 HXR074001 A Pump Room Coolers A (Heat Exchanger 2.6384E+000 Data) Ruptures 507 BUSFR1CAB2PNL9_9 I&C Bus A Panel 9-9 AB 2 Unit 1 Failure. 2.6360E+000 508 FRDXCDG3A_1035 Fire Dampers 1035, 1031 Transfer Closed 2.6333E+000 509 CHARG-DG3ACHG3A2 Charger '3A', In/Out Fuses Fail. Charger 2.631 1E+000 5CADG3ACHG3A2_________________ Input, Output Breaker Transfer Open 510 BUSFDDG3ABUS3A 125V DC BUS OR Battery OR Fused Switch 2.6290E+000

______ _____ _____ to DG CONT Transfer_ _ _ _ _ _

511 HOVXCDG3A_862 Manual Valve S 862,699 TRANS. Closed OR 2.6289E+000

____ _____ ____ ____ EXPANSION JOINT LEAK._ _ _ _ _ _

512 C51XODG3A_1838 DG 3A Breaker 1838 TRANS. Open OR 2.6244E+000 Breaker 1334 TRANS. Closed OR 513 [CB1FOOBKRO571614 Common Cause: Group Unit 1/2 4kV 2.6140E+00 CB1FOOBKR0571718] Shutdown Board Feeder Breakers FTO, 2/4 2.6140E+000 514 [CB1 FOOBKRO571614 CB1 FOOBKRO571718 Common Cause: Group Unit 1/2 4kV 2.6138E+000 CB1 FOOBKRO571724] Shutdown Board Feeder Breakers FTO, 3/4 2.6138E+000 515 [PMSFR2 02300B2] Common Cause: Group South Service Water 2.6008E+000

_ __ ___ Header RHRSW Pumps, 1/4 . 0 516 [PMSFS2_02300B2] Common Cause: Group South Service Water 2.5992E+000 Header RHRSW Pumps 1/4 ______

517 HOVXC2_0230527 Manual Valve 0-23-527 Transfers Closed 2.5989E+000 518 COVFO2_0230526 Check Valve 0-23-526 Fails to Open On 2.5975E+000 Demand______

519 COVXC2_0230526 Check Valve 0-23-526 Transfers Closed 2.5937E+000 520 [PMSFR1PMP074001A Common Cause: Group RHR Pumps Fail Fails 2.5788E+000 PMSFR1 PMP074001 D] to Run, 2/4 2.5788E+000 521 [FN2FR1ROOM74001A Common Cause: Group RHR Room Coolers 2.5782E+000 FN2FR1 ROOM74001 D] Fail to Run, 2/4 2.5782E+000 E-121

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 522 [CBlFOOBKR0571614] Common Cause: Group Unit 1/2 4kV 2.5600E-000 Shutdown Board Feeder Breakers FTO, 1/4 2.5600E+000 523 [CBI1FO0BKR0571614 Common Cause: Group Unit 1/2 4kV 2.5599E+000 CBIFOOBKRO571724] Shutdown Board Feeder Breakers FTO, 2/4 524 [MOVFC1 FCV0740053 Common Cause: Group LPGI Injection MOVs, MOVFC1 FCV0740067] 2/2 525 CB1XCOBKR0571614 Breaker 1614 Transfers Closed 2.5441 E+000 526 CKVXCiCKV074560A Check Valve 74-560A Transfers Closed 2.5254E+000 527 CKVXC1 CKV074559A Check Valve 74-559A Transfers Closed 2.5254E+000 528 [DGFTS_1_DGA] Common Cause: Group Diesel Generators, 2.4895E+000 528 1/4 29 [PMSFR2_02300A1 PMSFR2O02300C1 Common Cause: Group South Service Water 2.4684E+000 PMSFR2 02300C2] Header RHRSW Pumps, 3/4 ___________

530 [PMSFS2_02300A1 PMSFS2_02300C1 Cause: Group Common Pumps, Service Water Header 2.4682E+000 PMSFS2 02300C2] RHRSW 3/4 531 [PMSFR2_02300A1 PMSFR2_02300C1] Common Cause: Group Service Water Header 2.4624E+000 F1HRSW Pumps, 214 532 [PMSFS2_02300A1 PMSFS2__02300C1] Common Cause: Group Service Water Header 2.4624E+000 51RHRSW Pumps, 2/4 533 [PMSFR2 02300A1 PMSFR2 02300C2] Common Cause: Group Service Water Header 2.4051 E+000 5 RHRSW Pumps, 2/4 534 [PMSFS2_02300A1 PMSFS 023C Common Cause: Group Service Water Header 2.4050E+000

--- 0C1RHRSW Pumps, 2/4 _ ____

535 [PMSFR2 02300A1] Common Cause: Group Service Water Header 2.4033E+000 RHRSW Pumps, 1/4 _ ____

536 [PMSFS2L 02300A1] Common Cause: Group Service Water Header 2.4033E+000 RHRSW Pumps, 1/4 537 COF __03002Check Valve 0-23-502 Fails to Open On 2.4033E+000 CHOVXC2_0230502 Demand 538 HOVXC2_0230503 Manual Valve 0-23-503 Transfers Closed 2.4032E+000 539 HOVXC2_0230504 Manual Valve 0-23-504 Transfers Closed 2.4032EO00 540 COVXC2_0230502 Check Valve 0-23-502 Transfers Closed 2.4031 E+000 541 [FCOFO_1_FCO_64C FCOFOL1_FCO_65C] Common Cause: Group DG Dampers, 2/2 2.3395E+000 542 (PMSFR2_02300A2 PMSFR2_02300C1 Common Cause: Group Service Water Header PMSFR2_02300C2] RHRSW Pumps, 3/4 2.3334E+000 543 [PMSFS2_02300A2 PMSFS2_02300C1 Common Cause: Group Service Water Header PMSFS2_02300C2] RHRSW Pumps, 3/4 2.3332E+000 544 [FN2FTSDGAFANA FN2FTSDGAFANB] Common Cause: Group DG A Fans, 2/2 2.3318E+000 545 [PMSFR2_02300A2 PMSFR2_02300C2] Common Cause: Group Service Water Header 2.3172E+000 020C1RHRSW Pumps, 2/4______

546 PMSS2_03002 PSFS2 023OC2 Common Group Service Water Header Cause: 2/4 2.3171 E+000 2.3171E+000 546 [PMSFS2_02300A2 PMIFS202300C2] RHRSW Pumps, 547 CHARG DGACHGA2 Charger 'A', In/Out Fuses Fail Charger Input 2.2760E+000

_C Output Breaker Transfers Open ._7_+000 E-122

BFN Unit 1 Significant Basic Events By Risk Achievement Worth I Risk Rank Basic Event Description Achievement Worth 548 HOVXCDGA_532 Manual Valve S 532, 861 TRANS. Closed or 2.2721 E+000

_____ _____ ____ ____ Expansion Joint Leak_ _ _ _ _ _ _

Tran or Battery or Fused Switch 549 BUFDDG BS 1 to25V DG DC BD. BUS Control 2.2672E+000 9BUSFD_DGA_BUSA 550 CB1XO_DGA_1818 _ DG A Breaker 1818 TRANS. Open or Breaker 2.2613E+000 1614 Transfers Closed _____

551 FRDXCDGA_1023 FIRE DAMPERS 1023,1019 Transfer Closed 2.2594E+000 552 [MOVFO1 FCV0230040 Common Cause: Group RHR Heat 2.2374E+000 MOVFO1 FCV0230046] Exchangers MOVs, 2/4 553 XR2FR1_A_lA_TS1A Transformer TS1A During Operation 2.2321 E+000 554 BUSFR1_480VBRD1A 480V Shutdown Bus 1A 2.2321 E+000 555 CB1 XO04KVBD_A_5 Input Breaker 5 Transfers Open 2.2321 E+000 556 CB1XO1480BD1A_1C Output Breaker 1C Transfers Open 2.2321E+000 557 HERHRSPC1 Operator Local recovery of SP Cooling Failure 2.2311 E+000 558 [RL1 FD1 RL68118A3A RL1 FD1 RL68118A3B Common Cause: Group Relays for Breaker 2.2290E+000 RL1 FD1 RL68118B3A RL1 FD1 RL68118B3B] trip Coils for Recirc Pump Trip, 4/4 559 [RL1 FD1 RL68118A3B RL1 FD1 RL68118B3A Common Cause: Group Relays for Breaker 2.2290E+000 RL1 FD1 RL681 1 8B3B] trip Coils for Recirc Pump Trip, 3/4 560 [RL1 FD1 RL68118A3A RL1 FD1 RL68118B3A Common Cause: Group Relays for Breaker 2.2290E+000 RL1 FD1 RL68118B3B] trip Coils for Recirc Pump Trip, 3/4 561 [RL1FD1RL68118A3A RLIFD1RL68118B3AI Common Cause: Group Relays for Breaker 2.2290E+000 trip Coils for Recirc Pump Trip, 2/4 562 [RL1 FD1 RL68118A3A RL1 FD1 RL68118A3B Common Cause: Group Relays for Breaker 2.2290E+000 RL1 FD1 RL68118B3B] trip Coils for Recirc Pump Trip, 3/4 563 [RL1 FD1 RL68118A3A RL1 FD1 RL68118A3B Common Cause: Group Relays for Breaker 2.2290E+000 RL1 FD1 RL68118B3A] trip Coils for Recirc Pump Trip, 3/4 564 [RL1 FD1 RL68118A3B RLI FD1 RL681118B3B1] Common Cause: Group Relays for Breaker 2.2290E+000 trip Coils for Recirc Pump Trip. 2/4 (CB1 FO1 BKRO681440 CB1 F01 BKRO681450 Common Cause: Group Recirc Pump Trip CB1 F01 BKRO681540 CB1 F01 BKRO681550] Breakers, 4/4

[CB1 FO1 BKRO681450 CB1 FO1 BKRO681540 Common Cause: Group Recirc Pump Trip 566 CB1 FO BKR0681550] Breakers, 3/422290E+000 57 [C81 FO1 BKR0681440 CB1 FO1 BKR0681 540 Common Cause: Group Recirc Pump Trip 2.2290E+000 CB1 F01 BKRO681550] Breakers, 3/4

[CB1 FO1 BKR0681440 CB1 FO1 BKR0681450 Common Cause: Group Recirc Pump Trip CB1 F01 BKRO681550] Breakers, 3/4

[CB1 F01 BKRO681440 CB1 FO1 BKRO681450 Common Cause: Group Recirc Pump Trip CB1 FO1 BKRO681540] Breakers, 3/4 570 [CB1FO1BKR0681540 Common Cause: Group Recirc Pump Trip CB1 FO1 BKRO681550] Breakers, 2T4r 2.2290E+000 571 [CB1 FO1BKR0681440 Common Cause: Group Recirc Pump Trip CB1 FO1 BKRO681450] Breakers, 2/4 T 2.2290E+000 572 [DGFTS_1_DGC DGFTSIDGD] Common Cause: Group Unit 1?2 DGs FTS, 2.1871 E+000 573 [PMSFR20230A2

[PMSFR2 PMSFR2_02300C1]

02300A2PMSFR2O300C1] Common Pumps, 2/4 Cause: Group North Service Water 2.1342E+000 E-123

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 574 [PMSFS2_02300A2 PMSFS__0230 Cl] Common Cause: Group North Service Water 2.1341 E+000

[PMSFS2 02300A2 575 2/4 Common0230C1]

CsGu oh rcaPumps, 575 [PMSFR2_02300A2j Common Cause: Group North Service Water 2.1316E+000

[PMSFRZ.02300A2] Pumps, 1/4 ______

576 [PMSFS:2~-0230OA2] Common Cause: Group North Service Water 2.1315E+O00 Pumps 1/4 ______

577 COVF02Z0230506 Check Valve 0-23-506 Fails to Open On 2.1315E+000 DemandVv-- TaeC d___

578 HOVXC2_0230507 Manual Valve 0-23-507 Transfers Closed 2.1314E+000 579 COVXC2L-0230506 Check Valve 0-23-506 Transfers Closed 2.131 3E+000 580 [CB1 F03BKR0571334 CB1 FO3BKRO571338 Common Cause: Group Unit 3 4kV Shutdown 2.1304E+000 CB1 F03BKR0571342] Boards feeder Breakers FTO, 3/4 581 [CBI1 FO3BKRO571334 Common Cause: Group Unit 3 4kV Shutdown 2.1303E+000 CB1 FO3BKRO571338] Boards feeder Breakers FTO, 2/4 2.1303E+000 582 [CB1 F03BKR0571334] Common Cause: Group Unit 3 4kV Shutdown 2.1293E+000 Boards feeder Breakers FF0, 1/4 ______

583 [CB1FO3BKR0571334 Common Cause: Group Unit 3 4kV Shutdown 2.1292E+000 CB1 FO3BKRO571342] Boards feeder Breakers FFO, 2/4 584 [MOVFO1 FCV0710034] Common Cause: Group HPCI RCIC Retum 2.1186E+000 Lines MOVs 114 ______

585 BEHPTAF1 Operators Fails to Lower Level to TAF and 2.0514E+000 terminate Most Injection Flow 586 HOVXC1HCV0630012 Manual Valve 63-12 Transfers Closed 2.0471 E+000 587 COVFO1_0630525 Check Valve 63-525 Fails to Open 2.0471 E+000 588 COVF01_0630526 Check Valve 63-526 Fails to Open 2.0471 E+000 589 HOVXC1_0630524 Manual Valve 63-524 Transfers Closed 2.0471 E+000 590 COVPL10630525 Check Valve 63-525 Transfers Closed / Plugs 2.0471 E+000 591 COVPL1_0630526 Check Valve 63-526 Transfers Closed / Plugs 2.0471 E+000

[MOVFC1 FCV0690001 592 MOVFC1 FCV0690002 Common Cause: Group D, 3/3 2.0471 E+000 MOVFC1 FCV0690012]

93 HOVXO1_063001Manual Valve 63-13 to DRAIN TANK 2.0471E+000 H0VX0L0630013 ~Transfers Open ______

594 [PMSFS1_063001A PMSFS1_063001B] Common Cause: Group SLC Pumps, 2/2 2.0471E+000 595 TK2RP1_0630001 Standby Liquid Control Storage Tank 2.0471 E+000 TK2RLO63001Ruptures 596 [PMSFR1_063001A PMSFR1_063001 B] Common Cause: Group SLC Pumps, 2/2 2.0471 E+000 597 [EOVFD1_063008A EOVFD1 Common Cause: Group SLC Explosive 2.0471 E+000 598 HOVXC1_.0630500 Manual Valve 63-500 Transfers Closed 2.0471 E+000 599 FSWFR2MB057__XB Charger Output FUSE SWITCH-X Open. 2.0278E+000 600 CHGFR2MB057-SBB Charger SB-B During Operation 2.0278E+000 601 CB1 F02MB057_5A2 Charger Input Breaker 5A2 Open. 2.0278E+000 E-124

BFN Unit 1 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Worth 602 HOVXC1 0840703 Manual Valve 703 Transfers Closed 2.0261 E+000 603 HOVXC1_0840707 Manual Valve 707 Transfers Closed 2.0261 E+000 604 CKVXC1l 0840709 Check Valve 709 Transfers Closed 2.0261 E+000 605 PCVFD1 PCV0840706 PCV 84-706 On Demand 2.0261 E+000 606 TK1 RPOTKO8400A Nitrogen Tank A Rupture 2.0261 E+000 607 [DGFTSLlDGB] Common Cause: Group Unit 1/2 DGs, 1/4 2.0017E+000 NRC Request SPSB-A.21 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. 21 The following are the key sources of uncertainty and key assumptions as defined in RG 1.200.

One SRV The thermal-hydraulic analyses for Unit 1 indicated that a single stuck open safety relief valve (SRV) as an IE would depressurize the vessel such that low-pressure injection systems would be effective in mitigating core damage. This depressurization may not be applicable generically and is regarded as a key source of uncertainty. A key assumption is that a single stuck open SRV as an IE would depressurize the vessel such that low-pressure injection systems would be effective in mitigating core damage.

CRD for Vessel Protection The thermal-hydraulic analyses for Unit 1 also indicated that CRD injection operated in the enhanced mode, in some circumstances, would prevent vessel melt-through. As this is not generally modeled, this is a key source of uncertainty. The key assumption made with respect to enhanced CRD injection is that no credit was taken for this in the BFN Unit 1 model.

Common Cause Failures for RHRSW Pumos 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 E-125

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.

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.

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 (EOIs) and Abnormal Operating Instructions (AOIs). The EOls for Browns Ferry are symptom based. Changes in the EOls and the AOIs required for EPU implementation consist of revisions to previously defined numerical values (e.g., rated reactor thermal power, heat capacity temperature 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 AOls have been created as a result of the proposed EPU for these events. Although AOIs also include actions outside of transient, accident and special events, no significant AOI revision to operator actions are expected. AOls will E-126

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 A01s. 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 Reply to IROB-B-3 Changes to the control room controls, displays, and alarms are being implemented as a part of the Unit 1 recovery effort. These changes are being made similar to the changes previously incorporated in the Units 2 and 3 control room design efforts. Changes associated with EPU are being implemented concurrently with this recovery effort.

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 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.

E-127

• 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 Replv to IROB-B-4 The Safety Parameter Display System (SPDS) is being installed as part of the modifications required for Unit 1 restart following the extended shutdown. This system was not in place prior to the extended shutdown. The SPDS on Unit 1 will be similar to the SPDS on Units 2 and 3 and will reflect conditions associated with EPU such as rated core thermal power, reactor pressure, and changes to EOI Limit graphs. The design and intent of the SPDS remain unchanged from Units 2 and 3. The information presented on the SPDS display (top level display) and the method of presentation remain the same as before EPU on Units 2 and 3. These changes will not affect EOI execution and will be included in operator simulator training utilizing the SPDS.

E-128

REFERENCES:

1. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 -

Proposed Technical Specifications (TS) Change TS - 431- Request for License Amendment - Extended Power Uprate (EPU) Operation," dated June 28, 2004.

2. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 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 No. MC3812)" dated February 23, 2005.

3. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 -

Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS-431- Request for Extended Power Uprate Operation (TAC No. MC3812)," dated April 25, 2005.

4. TVA letter, W. D. Crouch to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 -

Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS - 431 - Request For License Amendment -

Extended Power Uprate (EPU) Operation (TAC No. MC3812)," dated June 6, 2005.

5. NRC letter, M. H. Chernoff to TVA, "Browns Ferry Nuclear Plant, Unit 1 - Request for Additional Information for Extended power Uprate (TS-431)(TAC No. MC3812),"

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. TVA Letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) Unit 1 -

Generic Letter 89-10 and Supplements 1 to 7, Safety-Related Motor-Operated Valve (MOV) Testing And Surveillance," dated May 5, 2004.

8. TVA Letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) Unit 1 -

Generic Letter 95-07, Pressure Locking And Thermal Binding of Safety Related Power-Operated Gate Valves," dated May 11, 2004.

9. GE Engineering Report for Quad Cities Unit 1 Scale Model Testing, GENE-0000-0032-2219-01, April 2005.

10. 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.

E-129

11. TVA Letter, BFN 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.

12. 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.

13. NRC letter to TVA, "Browns Ferry Nuclear Plant, Units 1, 2, and 3 - Issuance of Amendments Regarding Full-Scope Implementation of Alternative Source Term (TAC Nos. MB5733, MB5734, MB5735, MC0156, MC0157 and MC0158) (TS-405)," dated September 27, 2004.

14. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2 and 3 - January 28, 2004 Meeting Follow-Up - Additional Information," dated February 19, 2004 (ML040510241).

15. TVA letter, M. Burzynski to NRC, "Browns Ferry Nuclear Plant (BFN), Units 1, 2 and 3 (TAC Nos. MC1768, MC1769, and MC1770) License Renewal Application:

Response to Request for Additional Information (RAI) Regarding Lay-Up Effects of Unit 1 Structures and Component Supports," dated July 19, 2004.

16. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal Application - Response to NRC Request for Additional Information (RAI) Related to Aging of Mechanical Systems During the Extended Outage of Browns Ferry Nuclear Plant Unit 1 (TAC Nos. MC1704, MC1705, and MC1 706)," dated October 8, 2004.

17. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 License Renewal Application (LRA) - Relating to Section 3.0 Unit 1 Lay Up Questions - Response to Aging of Mechanical Systems During the Extended Outage of Browns Ferry Nuclear Plant Unit 1 - NRC Request for Additional Information (RAI) (TAC Nos. MC1704, MC1705, and MC1706)," dated January 31, 2005.

18. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - License Renewal Application (LRA) - Response to NRC Request for Additional Information Concerning the Unit 1 Layup Program (TAC Nos. MC1704, MC1705, and MC1706)," dated May 18, 2005.

19. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - License Renewal Application (LRA) - Response to NRC Request for Additional Information Concerning the Unit 1 Layup Program (TAC Nos. MC1704, MC1 705, and MC1 706), dated May 27, 2005.

E-130

20. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 -

Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS - 431 - Request for License Amendment -

Extended Power Uprate (EPU) Operation (TAC No. MC3812)," dated June 6, 2005.

21. TVA letter to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 - Response to NRC Request for Additional Information Regarding the Restart Testing Program (TAC NO. MC7208)," dated August 15, 2005.

22. 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.

23. TVA Letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1-Proposed Technical Specifications (TS) Change TS - 431 - Request for License Amendment - Extended Power Uprate (EPU) Operation Probabilistic Safety Assessment (PSA) Update," dated August 23, 2004.

24. TVA Letter to NRC, "Browns Ferry Nuclear Plant (BFN) Unit 1 - Update to the Probabilistic Safety Assessment (PSA)," dated September 15, 2005.

25. Standard For Probabilistic Risk Assessment For Nuclear Power Plant Applications, ASME RA-S-2002, April 5, 2002.

26. NUREG/CR-5496, "Evaluation of Loss of Offsite Power Events at Nuclear Power Plants: 1980-1996," U.S. Nuclear Regulatory Commission, November 1998.

27 NUREG-1 032, "Evaluation of Station Blackout Accidents At Nuclear Power Plants,"

U.S. Nuclear Regulatory Commission, June 1988.

28. INEEUEXT-97-00887, Draft Version of NUREG/CR-5496, Idaho National Engineering and Environmental Laboratories.

29. NUREG/CR-5750, "Rates of Initiating Events at Nuclear Power Plants: 1987-1995," U.S. Nuclear Power Plants, February 1999.

30. Tennessee Valley Authority, "Browns Ferry Nuclear Plant Scram Database" Updated as of March 31, 2003.

31. 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.

E-131

32. Database For Probabilistic Risk Assessment Of Light Water Nuclear Power Plants, PLG-0500.

33. Institute of Nuclear Power Operations (INPO) Equipment Performance and Information Exchange (EPIX).

34. Nuclear Computerized Library for Assessing Reactor Reliability (NUCLARR),

NUREG/CR-4639, Volume 5, Part 3, Hardware Component Failure Data, Revision 4, September 1994.

35. EPRI NP-6780-L, "Advanced Light Water Reactor Evolutionary Plant Utility Requirements Document - PRA Key Assumptions and Groundrules," Volume 2, Chapter 1, Appendix A, Electric Power Research Institute, 1990.

36. NUREG/CR-6268, "Common-Cause Failure Database and Analysis System," U.S.

Nuclear Regulatory Commission, (Vols. 1, 2, 3, and 4), June 1998.

37. INEEL Common Cause Failure Database and Analysis System, NUREG/CR-6268.

38. Letter to the NRC, "Browns Ferry Nuclear Plant Unit 1 - Response to NRC Generic Letter (GL) 88-20, Supplement 4 - Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - Submittal of Browns Ferry Nuclear Plant Unit 1 Seismic and Internal Fires IPEEE Reports," dated January 14, 2005.

39. 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-132

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

APPENDIX B HUMAN RELIABILITY ANALYSIS CALCULATION SHEETS FOR OPERATOR ACTIONS WITH A FUSSELL-VESELY IMPORTANCE MEASURE GREATER THAN 0.005 OR A RISK-ACHIEVEMENT WORTH GREATER THAN 2.

HPRVD1 EMERGENCY DEPRESSURIZATION, GIVEN HP INJECTION LOST Basic Event Summary t nalst: -- Dykes, AA ev. ate:04/22/04 HCR/ORE/THERP Table 1: HPRVD1

SUMMARY

without Recovery with Recovery

',ff<j-;tN/A 1.0e-07 Of l,,lll nrX .i ae §~$ a a gn@1 .9e-04 A,

At'~~~~~~~~ i°.fi i9E3-....'=&5t;r'"" "'l~->}t'X . -'I1.17'

- "'IS?'~

`-:.:.' "'lit;

`-' 1-.; I' -

5V90000**X .+A, Lighting Heat/Humidity X - Normal X - Normal

- Emergency - Hot/Humid

- Portable - Cold Radiation Atmosphere X - Background X - Normal

- Green - Steam

- Yellow - Smoke

- Red - Respirator required onEuipmn Accessiibe brt Say: I Location Accessibility X - Control Room Front Panels Accessible

- Control Room Back Panels

- Hot Shutdown Panels

- Auxiliary Building

- Electrical Building

- Containment

- Pump house

- Switchyard l stress I1

- Optimum (Low)

X - Moderate

- Extreme (High)

B-3

Cognitive HPRVD1 Cue:

RPV level lower than -45" (or -122" if initially unisolated) and decreasing. Attempts to initiate HP injection have failed and MSIVs are closed. Suppression pool temperature is rising as steam is discharged through MSRVs.

TSW 10 T 1 2 delay I T1/2 TM Irreversible Cue DamageState I -- _ I -__

two Unit: Minutes Reference for System Time: MAAP CASEOI, loss of all injection into RPV. The time relates to the window available once the RPV level reaches TAF. The available to recognize the need for the action and align low pressure systems before the RPV level reaches TAF is approx 40 min.

Reference for Manirulation Time: Simulator observations indicate all six MSIVs can be opened within seconds.

Duration of time window available for action (TW): 7.00 Minutes e Tr Skill vs. Rule Procedures Training Stress Skill X Yes X Yes Yes X Rule No No X No Sigma: 4.0e-01 HEP: 1.0e-07 B-4

Execution Unrecovered HPRVD1 Table 2: HPRVD1 EXECUTION UNRECOVERED v......

Actions: Line up, start pumps, and raise injection systems to the max Comments:

C1-8 I 1.3E-3 l 20-7 l 1 M 2 I I I I l 2.6e-03 Actions: Verify alignment and pumps running while waiting for RPV to reach TAF. Comments:

C2-7 I 1.3E-3 20-7 1 E 5 1 1 1 6.5e-03 Actions: Open 6 ADS valves Comments:

C2-8 through 13 l 1.3E-3 20-7 1 E 5 6.5e-03 Actions: SRO Verify SRVs opened and depressurization Comments:

C1-13 and 14 l 1.3E-3 l 20-7 1 E 5 1 6.5e-03 Actions: Verify Maximum injection into RPV and refill Comments:

B-5

Execution Recovery HPRVD1 Table 3: HPRVD1 EXECUTION RECOVERY ecover;, op = i~o KE (rtKP(e)De.Ch E TtL C1-4 Line up, start pumps, and raise Injection systems to the max 2.6e-03 1.4e-04

.C1-8 Verify alignment and pumps running while waiting for RPV to reach 2.6e-03 LD 5.2e-02 TAF.

C2-7 Open 6 ADS valves 6.5e-03 5.4e-05 C2-8 through 13 SRO Verify SRVs opened and depressurization 6.5e-03 LD 5.6e-02 C1-13 and 14 Verify Maximum injection into RPV and refill 6.5e-03 MD 1.5e-01 m = m ,4 B-6

HRWWV1 ALIGN HARDENED WETWELL VENT FOR SP COOLING Basic Event Summary

[Analyst:-

Rev~

>Dykes, ate;05/12/04 AA CDBTM/THERP Table 1: HRWWV1

SUMMARY

Atak Rtesults: without Recovery with Recovery 3.8e-03 3.8e-03 3.8e-02 3.8e-02 Ttal HEP 4.2e-02 HFE Scenario

Description:

This action is challenged when no suppression pool cooling is available and the containment pressure can not be maintained below 55 psig by other means. At the point this action is required, multiple systems will have failed.

Failure to accomplish this action is assumed to lead to loss of containment pressure control and breach.

Related Human Interactions:

As this action is not questioned unless multiple failures have occurred, the operating crew will be heavily involved in recovery actions. In addition, it is assumed that additional personnel will be arriving to support the crew.

Performance Shaping Factors:

As many systems will have failed at this point, the crew will be under high stress.

Procedure and step governing HI:

EOi-2, PC/P-13 to P-17 E0I App 13

- None X - Classroom Frequency: 1 X - Simulator Frequency: 1 B-7

P0 TM 5 Irreversible Cue DamageState t=o Unit Minutes Reference for System Time: Not time sensitive. Gradual buildup of PC pressure Reference for Manipulation Time: Simulator walk-through Duration of time window available for action (TW): 45.00 Minutes Table 2: HRWWV1 COGNITIVE UNRECOVERED Pct .alr

,-echanism Branh; i"XeAdd HEPAd; Pca: Availability of Information Pcb: Failure of Attention I 7.5e-04 Pcc: Misread/miscommunicate data Pcd: Information misleading b 3.0e-03 Pce: Skip a step in procedure Pcf: Misinterpret instruction Pcg: Misinterpret decision logic Pch: Deliberate violation Sum of Pc. through PCh = Initial Pc = 3.8e-03 B-10

Cognitive Recovery HRWWV1 Table 3: HRWWV1 COGNITIVE RECOVERY Initia HEPc 0 ELina U:a) c co0 r0 L Value

- NC 1.0 P 7.5e-04 NC 1.0 7.5e-04

- NC 1.0 PO 3.0e-03 NC 1.0 3.0e-03

-5 -NC 1.0 NC 1.0 P NC 1.0 Pc - _ _ NC 1.0

.Mti'tr o uiiafo= 3.8e-03 Recovery Factors identified:

B-11

Execution Unrecovered HRWWV1 Table 4: HRWWV1 EXECUTION UNRECOVERED App 13,2b to 2d 3.8E-3 20-7 2 E 5 1 1 1 1 I 1 Actions: Place keylock switch in Open HS-64-222B and open FCV-64-222. Comments:

App 13, 2e to 2g I 3.8E-3 l 20-7 l 2 l E 5 1.9e-02 Actions: Place keylock switch in Open HS-64-221 B and open FCV-64-221. Comments:

I I I I I B-12

Execution Recovery HRWWV1 Table 5: HRWWV1 EXECUTION RECOVERY App 13,2b to 2d Place keylock switch in Open HS-64-222B and open FCV 1.9e-02 App 13, 2e to 2g Place keylock switch in Open HS-64-221 B and open FCV 1.9e-02

=nX= T2a B-13

HRRHRX RECOVER RHR VIA CROSSTIE FROM UNIT 2 Basic Event Summary Analyt: X . Dykes, AA Rege 10/05/05 HCR/ORE/THERP Table 1: HRRHRX

SUMMARY

'nys eu without Recovery with Recovery N/A 3.0e-03 1.2e-01 6.1e-02 Total

.... E6.4e-02 Error actor HFE Scenario

Description:

Following successful shutdown and initiation of some form of injection has enabled the RPV level to be recovered.

At some later time the injection systems fail and the operators determine that the RPV level cannot be maintained above +2" with the preferred systems listed in EOI-1, Step RC/L-4. At this point, they transition to step RC/L-8 and determine it is necessary to crosstie RHR to another unit in order to maintain RPV level above -162".

Failure to initiate the crosstie when no other injection systems are available will result in core damage. If no other alternate means of RPV and SP cooling can be implemented, the SP will gradually heat up, resulting in over pressurization and loss of containment.

Related Human Interactions:

On going actions attempting to recover Unit 1 systems.

Performance Shaping Factors:

At the point this action is needed, multiple other systems will be unavailable and actions will be underway to recover primary systems. This action requires actions in multiple locations, including local actions in the auxiliary instrument room involving lifting and booting breaker contacts. It also requires coordinating actions between the three units. Therefore, the model can take credit for this action only if RPV injection has initially succeeded to the extent that they will get adequate time to successfully accomplish all the required actions.

Procedure and step governing HI:

EOI-1, RC/L-8, App 70 B-14

r n *i

- None X - Classroom Frequency: 1 X - Simulator Frequency: 1

_. re of Cl. .&n..io

- Very Good X - Average

- Poor

$ua- hcientiae X - Control Room Panels X - Local Control Panels X - Local Equipment Tools Parts Clothing X Required X Required Required Adequate Adequate X Adequate Available Available Available T.... e i. ...e

- Skills X - Rule

- Knowledge CrnP lox o <H~>/-

jf oi"ni'.zse-fle Cognitive Execution X - Complex X - Complex

- Simple - Simple B-1 5

Lighting Heat/Humidity X - Normal X - Normal

- Emergency - Hot/ Humid

- Portable - Cold Radiation Atmosphere X - Background X - Normal

- Green - Steam

- Yellow - Smoke

- Red - Respirator required Location Accessibility X - Control Room Front Panels Accessible

- Control Room Back Panels

- Hot Shutdown Panels X - Auxiliary Building Accessible

- Electrical Building

- Containment

- Pump house

- Switchyard Stress:2FSN /' iS%bHS .. - dl

- Optimum (Low)

X - Moderate

- Extreme (High)

B-16

Cognitive HRRHRX Cue:

RPV level declining and cannot be maintained above +2". Indications of failures of a variety of cooling systems.

T 60 SW Tdelay l 1 02 'TM 30>

Irreversible Cue DamageState t=O Unit: Minutes Reference for System Time: System time of 60 minutes is assumed to be bounding, as thermal hydraulic CASE01 calculates over 60 minutes to core melt with no RPV injection following trip.

Reference for Manipulation Time: Time for local action estimated to be 30 minutes based on conversations with licensed operators.

Duration of time window available for action (TW): 20.00 Minutes Sigma Dec ision "Tr Skill vs. Rule Procedures Training Stress Skill X Yes X Yes Yes X Rule No No X No Sigma: 4.0e-01 HEP: 3.0e-03 B-17

Execution Unrecovered HRRHRX Table 2: HRRHRX EXECUTION UNRECOVERED lb. 3.8E-3 20-7 2 E 5 3.8E-3 20-13 2 E 5 .076 7.6e-02 Actions: In Aux. lnstr. Rm., lift and boot relay contacts to defeat RHR Pump suction Comments: First action: requires acting carefully under pressure. Two boots Vlv interlocks must be installed. Double error rate.

1b.3) 3.8E-3 l 20-7 2 M 2 1 7.6e-03 Actions: Notify RO that action completed (verify by communication) Comments:

Ic 3.8E-3 l 20-7 l 2 M 2 7.6e-03 Actions: Locally close 2 breakers to RHR crosstie valves Comments:

1d. I 3.8E-3 l 20-7 l 2 l M l 2 1 7.6e-03 Actions: Unit 2 RO lines up RHR for crosstie Comments:

1e-h I 3.8E-3 l 20-7 l 2 M 2 1 7.6e-03 Actions: Ul RO steps to inhibit Ul LPCI to prepare for crosstie Comments: Includes inhibit min flow paths and closing injection valves. 2 actions.

1i 3.8E-3 20-7 2 M 2 7.6e-03 Actions: Locally Rack Out U1 2 RHR Pump breakers Comments: Dispatch from control room to two separate compartments lj. I 3.8E-3 l 20-7 2 M 2 1 1 1 1 T 7.6e-03 Actions: U1 RO open 3 crosstie valves to U1 RHR Comments:

1k. I 3.8E-3 l 20-7 2 M 2 I I I 7.6e-03 Actions: Verify Ul discharge press > 45 psig Comments:

1I.-o. I 3.8E-3 l 20-7l 2 M 2 7.6e-03 B-18

Actions: U2 RO open injection valve and adjust flow to control injection <5000 gpm Comments:

I end I 3.8E-3 l 20-7 l 2 l M l 2 l l I I I I 7.6e-03 Actions: Verify RPV recovers level Comments:

II I I 1 , I I I I I I I B-19

Execution Recovery HRRHRX Table 3: HRRHRX EXECUTION RECOVERY lb. In Aux. Instr. Rm., lift and boot relay contacts to defeat RHR 7.6e-02 3.8"2 Pump suction Viv interlocks .

1b.3) Notify RO that action completed (verify by communication) 7.6e-03 HD 5.0e-01 ic Locally close 2 breakers to RHR crosstle valves 7.6e-03 3.8"-03 1k. Verify U1 discharge press > 45 psig 7.6e-03 HD 5.0e-01 1d. Unit 2 RO lines up RHR for crosstle 7.6e-03 3.8e-03 1k. Verify U1 discharge press > 45 psig 7.6e-03 HD 5.0e-01 1e-h U1 RO steps to Inhibit Ul LPCI to prepare for crosstie 7.6e-03 3.8e"03 1k. Verify Ul discharge press >45 psig 7.6e-03 HD 5.0e-01 I Locally Rack Out Ul 2 RHR Pump breakers 7.6e-03 3.8e-03 1k. Verify Ul discharge press > 45 psig 7.6e-03 HD 5.0e-01 ii. Ul RO open 3 crosstle valves to Ul RHR 7.6e-03 3.8e-03 1k. Verify Ul discharge press > 45 psig 7.6e-03 HD 5.0e-01 11.-o. U2 RO open Injection valve and adjust flow to control Injection 7.6e-03 3.8e-03

<5000 gpm 1end Verify RPV recovers level 7.6e-03 HD 5.0e-01

. 2@

" ,, $;' : . ..(. :,i. . ,. V-_-i .t

. .i7:. , C.

B-20

HPHPE1 CONTROL HPCI/RCIC INJECTION TO COOL DOWN RPV, FIRST 6 HOURS Basic Event Summary

[ Date:,

1t Dykes, AA 07/08/04 HCR/ORE/THERP Table 1: HPHPE1

SUMMARY

aly srs. r without Recovery with Recovery N/A 5.4e-04 2.6e-03 2.6e-03 Total iiEP 3.1 e-03 erro Paetojx 5 HFE Scenario

Description:

Transient with loss of feedwater. Successful scram and initiation of HPCI/RCIC.

The HPCI/RCIC have flow controllers that allow the operators to adjust injection. Because of its high capacity, HPCI flow must be brought under control rapidly. Once the RPV level has been stabilized, the operator must adjust HPCI pump flow against a lowering pressure due to cool down and a gradual reduction in decay heat. If left alone the HPCI pump would gradually provide more water than required and the RPV level will rise. These effects will occur over the period of a few minutes.

Trip at +51 " will place a demand on the HPCI/RCIC to restart, presenting the additional possibility of a demand related failure.

Related Human Interactions:

This action includes actions to depressurize, since HPCI may be used in test flow to provide heat removal. However, operators may also cycle selected SRVs to assist in cool down.

Performance Shaping Factors:

HPCI controller is straightforward, and the operators are well trained in its use.

Procedure and step governing HI:

EO1-1 RC/L & RC/P

- None X - Classroom Frequency: 1 X - Simulator Frequency: 4 B-21

rEe wof- C X - Very Good

- Average

- Poor X - Control Room Panels

- Local Control Panels

- Local Equipment Tools Parts Clothing Required Required Required Adequate Adequate Adequate Available Available Available

- Skills X - Rule

- Knowledge Cognitive Execution

- Complex - Complex X - Simple X - Simple EU=-ron-If;.

Lighting Heat/Humidity X - Normal X - Normal

- Emergency - Hot/Humid

- Portable - Cold Radiation Atmosphere X - Background X - Normal

- Green - Steam

- Yellow - Smoke

- Red - Respirator required B-22

auimen A~cesbifltv; vdI~ -I Location Accessibility X - Control Room Front Panels Accessible

- Control Room Back Panels

- Hot Shutdown Panels

- Auxiliary Building

- Electrical Building

- Containment

- Pump house

- Switchyard

$trs

- Optimum (Low)

X - Moderate

- Extreme (High)

B-23

Cognitive HPHPE1 Cue:

RPV level trending out of acceptable band. High level alarm at +39", Low level alarms at +2", -45" and

-122".

TS !5 Tdelay 1.5

-1T 1/2

-I -1 1TM 1 'I1

-I Irreversible Cue DamageS tate

-I t=0 IUnit: Minutes Reference for System Time: Time estimated based on mismatch of HPCI flow and boiling rate based on simulator runs during walk through with operators.

Reference for Manipulation Time: Simulator Observations Duration of time window available for action (TW): 2.50 Minutes Skill vs. Rule Procedures Training Stress Skill X Yes X Yes X Yes X Rule No No No Sigma: 3.0e-01 HEP: 5.4e-04 B-24

Execution Unrecovered HPHPE1 Table 2: HPHPE1 EXECUTION UNRECOVERED B-25

Execution Recovery HPHPE1 Table 3: HPHPE1 EXECUTION RECOVERY B-26

HPHPR1 RESTART, CONTROL RPV LVL W HPCI/RCIC, GIVEN HIGH LVL TRIP Basic Event Summary

[

ADykes, Rev. iDate: 10/17/05 AA C ii,MHCR/ORE/THERP Table 1: HPHPR1

SUMMARY

Anlysiss Results 2 without Recovery with Recovery N/A 2.6e-04 x5.2e03 1.7e-03 ToalHP 1.9e-03 Error actor5 HFE Scenario

Description:

This action is questioned after the HPCI has tripped on high level due to lack of proper adjustment of injection flow during the initial recovery of level, when flow can be maximum and operator work load is high.

Following that trip the level gradually lowers giving time for operators to restart HPCI and establish a balance of flow with decay heat boil off. If the HPCI restarts, the required actions needed to maintain control are the same as HPHPE1.

Failure to manually recover HPI is assumed to result in RPV level continuing to lower, requiring that the RPV be depressurized and low pressure injection systems be initiated. The simplifying assumption is made that the HPCI/RCIC will not start following a second trip.

Related Human Interactions:

Action HPHPE1 has failed.

Depending on how long after shutdown the trip occurred, the RPV level will gradually decline to -

45" where HPCI will reinitiate. A simulator run indicates that sufficient time (tens of minutes) are required for this occur. It is judged that these time is sufficient to significantly reduce any dependence between this action and the previous failure.

Failure to manually recover HPI is assumed to result in RPV level continuing to lower, requiring that the RPV be depressurized and low pressure injection systems be initiated. The simplifying assumption is made that the HPCI/RCIC will not start following a second trip.

Performance Shaping Factors:

If they have not caught it earlier, the HPCI/RCIC trip at +51 in will alert the operators that the HPCI/RCIC turbine controller is faulty. A faulty controller could make subsequent attempts to control RPV level manually difficult. This will cause then to focus on controlling HPCI.

Procedure and step governing HI:

EOI-RC/L-4 B-27

- None X - Classroom Frequency: 1 X - Simulator Frequency: 6 X - Very Good

- Average

- Poor Hurnn-Mach Interface: .. vfW% v/WS4vyg e X - Control Room Panels

- Local Control Panels

- Local Equipment Tools Parts Clothing Required Required Required Adequate Adequate Adequate Available Available Available I OR

- Skills X - Rule

- Knowledge Cognitive Execution

- Complex - Complex X - Simple X - Simple Lighting Heat/Humidity X - Normal X - Normal

- Emergency - Hot/Humid

- Portable - Cold Radiation Atmosphere X - Background X - Normal

- Green - Steam

- Yellow - Smoke

- Red - Respirator required B-28

Location Accessibility X - Control Room Front Panels Accessible

- Control Room Back Panels

- Hot Shutdown Panels

- Auxiliary Building

- Electrical Building

- Containment

- Pump house

- Switchyard

- Optimum (Low)

X - Moderate

- Extreme (High)

B-29

Cognitive HPHPRI Cue:

RPV level trending either high or low TSW Tdelay 0 T1/2 1 :J TM 1 Irteveible Cue DamageState t=0 Unit: Minutes Reference for System Time: Simulator run, 11/20/03, 40 minutes from high level trip to automatic restart. Operators also control to prevent high level trip Reference for ManiDulation Time: Simulator Observations Duration of time window available for action (TW): 3.00 Minutes Sim Poslo a. Zen t , zZ oI 'yChsA .- f..

Skill vs. Rule Procedures Training Stress Skill X Yes X Yes Yes X Rule No No X No Sigma: 4.0e-01 HEP: 2.6e-04 B-30

Execution Unrecovered HPHPR1 Table 2: HPHPR1 EXECUTION UNRECOVERED 1

SeN.L l 1.3E-3 LVat 20-7 1 J 1 M 2 Table I Item Rf.Vlu IStress -Stress1w vrT'I>e

'dRf.

2.6e-03 Actions: Restart HPCI/RCIC Comments:

2 1 1.3E-3 20-7 l 1 M 2 1 2.6e-03 Actions: Respond to low low RPV level and restart HPCI/RCIC Comments:

3 1 1.3E-3 l 20-7 l 1 M 2 T 2.6e-03 Actions: Adjust flow as needed to keep within acceptable level Comments:

4 1.3E-3 l 20-7 1 M 2l 2.6e-03 Actions: Respond to high/low RPV level alarm Comments:

B-31

Execution Recovery HPHPR1 Table 3: HPHPR1 EXECUTION RECOVERY

_ii~ _~e INo if, ct~ ~ , , ,-,.,,-, ,,,,;;..-.S "y,', tr ~ ~e

, .- ..- ,.;. r , ":' .,\- .- , p,

,- I-- l ,\-,7 -oe -. '- -;Fi :)Id Uwepo 1 Restart HPCIRCIC 2.6e-03 1.3e-03 2 Respond to low low RPV level and restart HPCI/RCIC 2.6e-03 HD 5.0e-01 3 Adjust flow as needed to keep within acceptable level 2.6e-03 3.8e-04 4 Respond to high/low RPV level alarm 2.6e-03 MD 1.e-01

`'I B-32

HPTAF1 CONTROL RPV LEVEL AT TAF, GIVEN ATWS WITH UNISOLATED RPV Basic Event Summary Ado yst: ' Dykes, AA

te;.

. . 07/06/04 HCR/ORE/THERP I

Table 1: HPTAF1

SUMMARY

ny$ e s without Recovery with Recovery D N/A 2.6e-04 1.3e-02 1 .3e-02 Total IEP.X 1 .3e-02 Error ;:etor 25 HFE Scenario

Description:

ATWS has occurred without isolation. Feedwater is still operating and operators are attempting to insert rods and start SLC. This action is questioned when level control is needed to reduce power level.

Failure to accomplish this action is assumed to lead to core damage.

Related Human Interactions:

Operators are injecting SLC into the core and observed RPV power level.

Performance Shaping Factors:

ATWS situation will present significant stress, but operators have trained extensively on these scenarios.

Procedure and step governing HI:

C5-8 through 13

- None X - Classroom Frequency: 1 X - Simulator Frequency: 12 Chia P ree7of

& ofCues D$,$Ahtons:l

- Very Good

- Average X - Poor B-33

tlumn nt

~ Aee ce:

X - Control Room Panels

- Local Control Panels

- Local Equipment

$ AcI ,Xi, e nfs a

Tools Parts Clothing Required Required Required Adequate Adequate Adequate Available Available Available

- Skills X - Rule

- Knowledge Cognitive Execution X - Complex X - Complex

- Simple - Simple

,,nv"'.ir t:

Lighting Heat/Humidity X - Normal X - Normal

- Emergency - Hot/ Humid

- Portable - .Cold Radiation Atmosphere X - Background X - Normal

- Green - Steam

- Yellow - Smoke

- Red - Respirator required B-34

men AQesNo ez Location Accessibility X - Control Room Front Panels

- Control Room Back Panels

- Hot Shutdown Panels

- Auxiliary Building

- Electrical Building

- Containment

- Pump house

- Switchyard 1- -l- 1--1111-',',-""',-

", I'll, "I "I 1111-1-- -l"..... ............ 1111-1 -V'116#*W-,' I I - I- I II 11 11II I I I II I I11 .

A,

- Optimum (Low)

- Moderate X - Extreme (High)

B-35

Cognitive HPTAF1 Cue:

RPV Level indications, reactor power level remaining above 4%

t=O lUnit: Minutes Reference for System Time: Calculation based on power level at TAF and 95 gal/in water within active core. (See HRA Notebook, Table 4-4). Additional one minute allowed to account for less heat deposited to SP, which delays need for level control.

Reference for Manipulation Time:

Simulator observations. Operator responsible for level control tracks level and power to determine first acceptable time to reinitiate injection after termination.

Duration of time window available for action (TW): 3.00 Minutes Skill vs. Rule Procedures Training Stress Skill X Yes X Yes Yes X Rule No No X No Sigma: 4.0e-01 HEP: 2.6e-04 B-36

Execution Unrecovered HPTAF1 Table 2: HPTAF1 EXECUTION UNRECOVERED Stiep .o, ' 4seL EJMsO Value .~P .

... Ref. .et IE/MO. V.

C5-10 1.3E-3 20-7 1 E 5 6.5e-03 Actions: Terminate injection except for SLC and CRD when suppression pool> Comments:

110OF C5-13 1.3E-3 l 20-7 l 1 E 5 6.5e-03 Actions: Initiate FW as level reaches -162" and maintain above -185- Comments:

I I I I l lll B-37

Execution Recovery HPTAF1 Table 3: HPTAF1 EXECUTION RECOVERY Cs-10 Terminate injection except for SLC and CRD when 6.5e-03 suppression pool > 1r1c0 F-1 CS-13 Initiate F-W as level reaches -1 62" and maintain above -185" 6.5e-03 B-38

HPSIV1 DEFEAT MSIV CLOSURE LOGIC, GIVEN ATWS WITH TURBINE TRIP Basic Event Summary i Analyst:Dykes, AA

~0V.flat ' 10/21/03 HCR/OREJrHERP Table 1: HPSIV1

SUMMARY

IiAnalyis R without Recovery with Recovery I

N/A 2.4e-01 I

-- .... 3.2e-02 3.2e-02

~t6. -

T$P', . 2.7e-01 HFE Scenario

Description:

Initiating event requiring reactor trip occurred, but reactor power has not declined to decay heat levels. Reactor has not yet isolated and the operators have recognized the ATWS, initiated RPV level reduction and SLC injection into the RPV.

Related Human Interactions:

Operators are accomplishing a variety of actions related to responding to the ATWS and transient alarms.

Alternate control rod insertion underway (PSA takes no credit taken for its success)

SLC being initiated (HPSLC1=S)

If this action is not done before Performance Shaping Factors:

Procedure and step governing HI:

EOI-1 RC/P-9, Appendix 8A C5-4, Appendix 8A

- None X - Classroom Frequency: 1 X - Simulator Frequency: 8 Deg ee Oa*CJof C u s & l d at o ;

X - Very Good

- Average

- Poor B-39

- Control Room Panels X - Local Control Panels

- Local Equipment Tools Parts Clothing Required X Required Required Adequate Adequate Adequate Available Available Available

- Skills X - Rule

- Knowledge Corn teExt Q Rsn Cognitive Execution X - Complex X - Complex

- Simple - Simple Lighting Heat/Humidity X - Normal X - Normal

- Emergency - Hot/ Humid

- Portable - Cold Radiation Atmosphere X - Background X - Normal

- Green - Steam

- Yellow - Smoke

- Red - Respirator required Location Accessibility

- Control Room Front Panels

- Control Room Back Panels

- Hot Shutdown Panels X - Auxiliary Building With Difficulty

- Electrical Building

- Containment

- Pump house

- Switchyard

- Optimum (Low)

- Moderate X - Extreme (High)

B-40

Cognitive HPSIV1 Cue:

RPV level is declining towards -122" Power level remains above shutdown MSIVs cycling to maintain RPV pressure at 1,050 psig TSW Tdelay 0 T1/2 TM 4 Irreversible Cue DamageState

=Unit: Minutes Reference for System Time: 3 to 5 min available to avoid level/ power control requirement. SP reached 170 F in 20 minutes Reference for Manipulation Time: Simulator observations Duration of time window available for action (TW): 1.00 Minutes Sigm De o T Skill vs. Rule Procedures Training Stress Skill X Yes X Yes Yes X Rule No No X No Sigma: 4.0e-01 HEP: 2.4e-01 B-41

Execution Unrecovered HPSIV1 Table 2: HPSIV1 EXECUTION UNRECOVERED

__ _ __ __ __ _ Tal te Srs ISr

,Ste NL ______ p e al'ue HE Ref. et EM Value, Rw St; 0 1.3E-3 j 20-7 1 E 5 6.5e-03 Actions: Obtain four banana jack jumpers from EOI Equipment Storage Box Comments:

1 I 1.3E-3 20-7 r 1 E I 5 I 6.5e-03 Actions: Install jumper in Panel 9-15 Comments:

2 l 1.3E-3 20-7 1 E l 5 1 6.5e-03 Actions: Install second jumper in Panel 9-15 Comments:

3 1 1.3E-3 20-7 1 E 5 1 6.5e-03 Actions: Install jumper in Panel 9-17 Comments:

4 1 1.3E-3 20-7 l 1 E 5 1 6.5e-03 Actions: Install second jumper in Panel 9-17 Comments:

B-42

Execution Recovery HPSIV1 Table 3: HPSIV1 EXECUTION RECOVERY itoan 0 Obtain four banana lack jumpers from EOI Equipment Storage 6.5e-03 1 Install jumper in Panel 9-15 6.5e-03 2 Install second Jumper in Panel 9-15 6.5e-03 3 Install Jumper in Panel 9-17 6.5e-03 4 Install second lumper in Panel 9-17 6.5e-03

=. r B-43

HPSPC1 ALIGN RHR FOR SUPPRESSION POOL COOLING Basic Event Summary r Gil;~r: - -Dykes, AA e t05/12/04 Con od CDBTM/THERP Table 1: HPSPC1

SUMMARY

X without Recovery with Recovery 1.2e-03 3.3e-06 2.6e-03 2.8e-06 Ttl~i $E, 6.1e-06 10 HFE Scenario

Description:

This action may be required during a transient with successful scram. The suppression pool provides the heat sink for pressure relief and the HPCI/RCIC pumps. If the RPV is isolated, or one or more the SRVs stick open during an unisolated transient, the suppression pool will gradually heat up.

Failure to accomplish this action will result in gradual heat up of the suppression pool over the course of hours, leading to eventual loss of RCIC/HPCI injection and over pressurization of the containment. If the operators fail to accomplish this action, it is assumed that they will also fail to align the wetwell vent.

HRWWV1 is credited only for recovering from hardware failures leading to loss of suppression pool cooling.

Related Human Interactions:

Response activities associated with EOls and AOI-100-1 Performance Shaping Factors:

This action is accomplished during normal cool down activities following isolation. Operators are well trained on the importance of the suppression pool as a heat sink and the necessity of removing heat from suppression pool to maintain this capacity.

Procedure and step governing HI:

EOI-2 SP/T-1, App 17A

- None X - Classroom Frequency: 1 X - Simulator Frequency: 12 B-44

X - Very Good

- Average

- Poor I . : ,. ' ,. '

X - Control Room Panels

- Local Control Panels

- Local Equipment Re ~nt a. .. .lmn Tools Parts Clothing Required Required Required Adequate Adequate Adequate Available Available Available

- Skills X - Rule

- Knowledge Cognitive Execution

- Complex - Complex X - Simple X - Simple ivi i '.onn~fent<<

Lighting Heat/Humidity X - Normal X - Normal

- Emergency - Hot/ Humid

- Portable - Cold Radiation Atmosphere X - Background X - Normal

- Green - Steam

- Yellow - Smoke

- Red - Respirator required B-45

..... >2r.s" -.....-..--..-.. - -7r. V-- InIII AIz.Qq---11I.. - -III§! -II:A. - IsII I-t I. I.........a,,n:,.

l Z~~rmtqqa>~~.rrsgess8 t equipment Accessibility: A Location Accessibility X - Control Room Front Panels Accessible

- Control Room Back Panels

- Hot Shutdown Panels

- Auxiliary Building

- Electrical Building

- Containment

- Pump house

- Switchyard VFJStress: I X - Optimum (Low)

- Moderate

- Extreme (High)

B-46

Cognitive Unrecovered HPSPC1 Cue:

Suppression pool temperature high temp alarm at +95 F. If SP continues to heat up, high temperature alarms at 110 F and again at 120 F. As SP temp rises, PC pressure also rises.

TSW 120 10 TM 2 Tdelay T1/2

-r -O -I Irreversible Cue DamageState

-4 t=O I Unit: Minutes Reference for System Time: Not time sensitive - can be done over the course of hours as suppression pool gradually heats up.

Reference for Manipulation Time:

Simulator Observations: Required steps can be done within control room by one RO Duration of time window available for action (TW): 103.00 Minutes Table 2: HPSPC1 COGNITIVE UNRECOVERED L!P Faiur Me nis Banchl Pca: Availability of Information A neg.

Pcb: Failure of Attention D 1.5e-04 Pcc: Misread/miscommunicate data A neg.

Pcd: Information misleading A neg.

Pce: Skip a step in procedure A 1.0e-03 Pcf: Misinterpret instruction A neg.

Pcg: Misinterpret decision logic K neg.

Pch: Deliberate violation A neg.

Sum of PCa through PCh = Initial Pc = 1.2e-03 B-47

Cognitive Recovery HPSPC1 Table 3: HPSPC1 COGNITIVE RECOVERY U- (D2 )

Initial HEP 75 l)

• l> iL I ]- Final Value (i) W (fl) CI). Wa) 0 W cc4 (.rs x ~ >R..~

neg. - NC 1.0 E 1.5e-04 X - 1.0e-01 1.0e-01 1.3e-02 2.0e-06 neg. = = - NC 1.0 l neg. = - NC 1.0 Pc 1.0e-03 X- - 5.0e-01 5.0e-01 1.3e-03 1.3e-06 neg. - - NC 1.0 neg. - - NC 1.0 E neg. - NC 1.0 0gr1 6f..hroughtT= 3.3e-06 Recovery Factors identified:

pcb and pce: Inattention and skip a step implies that other actions may initially take precedence over SP cooling. Multiple recovery opportunities account for override value of recovery factor.

1) pce only: Self check of RO in response to two additional high SP temperature alarms at 110 andl20 F. Assume 0.1

2) SRO conducts periodic review of plant status against EOls. Formally requests plant parameters for plant safety parameters: judged low dependency with operators. Assume MD

3) STA conducts independent reviews of critical plant parameters and notifies SRO of problems. Assume LD

4) Multiple opportunites to repeat the above cognitive operaitions over period of heat up. Assume HD Estimate multiple recovery factor = 0.1 *.5*.05*.5 =

B-48

Execution Unrecovered HPSPC1 Table 4: HPSPC1 EXECUTION UNRECOVERED ttm Sttress rsTbe Itm StrssSM es And~~~~. . t'i..'........

. 3 t........ .'.61' 2 a-c \.0e+00 Actions: Verify/establish adequate RHRSW flow through heat exchangers Comments: Verifies heat sink for cooling. Other top events covers its functionality. Not a critical step 2 g. 1.3E-3 l 20-7 1 0 1 1 l 1.3e-03 Actions: Open RHR SYS 1911) SUPPR CHBR / POOL ISOL VLV Comments:

2 h. 0.Oe+00 Actions: Verify desired RHR pump (s)operating Comments: Included to show that overall functioning is continually considered.

Since RHR pumps are operating, not a critical step 2 i. 1.3E-3 l 20-7 1 0 1 l 1.3e-03 Actions: Throttle open RHR SYSI(II)SUPPR POOL CLGITEST VLV to specified Comments:

flow 2 i. 1) 1.3E-3 20-7 1 0 1 1.3E-3 l 20-10 2 0 1 2.6e-03 Actions: Verify flow within limits Comments:

2 k. I 1.3E-3 l20-7 1 1 1 l 1.3e-03 Actions: RO Monitor RHR Pump NPSH Comments:

STA I 1.3E-3 l20-7 l 1 l 1 7 1.3e-03 Actions: STA independent monitor of important plant safety parameters Comments: STA records and tracks important plant safety parameters over time.

The parameters that indicate failure to establish SP cooling are included on his safety parameter form.

B-49

Execution Recovery HPSPC1 Table 5: HPSPC1 EXECUTION RECOVERY 2 g. Open RHR SYS 1911) SUPPR CHBR / POOL ISOL VLV 1.3e-03 1.4e-06 2 i. 1) Verify flow within limits 2.6e-03 MD 1.5e-01 2 k. RO Monitor RHR Pump NPSH 1.3e-03 LD 5.1e-02 STA STA independent monitor of important plant safety parameters 1.3e-03 MD 1.4e-01 2 i. Throttle open RHR SYS 1(11) SUPPR POOL CLG/TEST VLV to 1.3e-03 1.4e-06 specified flow 2 i. 1) Verify flow within limits 2.6e-03 MD 1.5e-01 2 k. RO Monitor RHR Pump NPSH 1.3e-03 LD 5.1e-02 STA STA independent monitor of important plant safety parameters 1.3e-03 MD 1.4e-01 2 a-c Verify/establish adequate RHRSW flow through heat 0.0e+0 0.0e+00 exchangers 2 h. Verify desired RHR pump (s) operating 0.0e+00 0.0e+00 B-50