ML063100442

Supplemental Information - Changes to Instrumentation Surveillance Test Intervals and Allowed Out-of-Service Times

ML063100442
Person / Time
Site:	Browns Ferry
Issue date:	11/01/2006
From:	Crouch W Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML063100442 (62)

Text

Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000 November 1, 2006 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk 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 1 - SUPPLEMENTAL INFORMATION - CHANGES TO INSTRUMENTATION SURVEILLANCE TEST INTERVALS (STIs) AND ALLOWED OUT-OF-SERVICE TIMES (AOTs)

The purpose of this letter is to provide the BFN Unit 1 plant specific information associated with the NRC approved generic methodology (BWR Topical Reports) supporting instrument surveillance intervals and allowed outage times as discussed in TVA's September 7, 2006 letter (Reference 1). TVA's September 7, 2006 letter responded to NRC's July 7, 2006 letter (Reference 2) pertaining to License Condition 2.C(4).

Specifically, in BFN's Improved Technical Specification (ITS) conversion, TVA referred to several BWROG Licensing Topical Reports (LTRs) used to justify the Surveillance Test Intervals (STIs) and Allowed Outage Times (AOTs) for instrument systems. The BWROG LTRs established the generic basis for supporting the plant specific TS change. TVA's December 11, 1997 letter provided plant specific assessments for Units 2 and.3 that concluded that the generic analyses were applicable to BFN Units 2 and 3. BFN has performed a similar analysis for Unit 1 and is it provided in the Enclosure. In the ITS conversion, TVA referred to several BWROG Licensing Topical Reports used in justifying the STIs and AOTs for particular instrument systems. These were:

,;) C)3

U.S. Nuclear Regulatory Commission Page 2 November 1, 2006

1. NEDC-30851P-A, Technical Specification Improvement Analysis for Reactor Protection System; NEDC-30851P-A Supplement 1, Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation; and NEDC-30851P-A Supplement 2, Technical Specification Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation.

2. GENE-770-06-1, Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times For Selected Instrumentation Technical Specifications

3. GENE-770-06-2, Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times For Selected Instrumentation Technical Specifications

4. NEDC-31677P-A, Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation

5. NEDC-30936P-A, Technical Specification Improvement Methodology, Parts 1 and 2 (With Demonstration for BWR ECCS Actuation Instrumentation).

TVA previously performed a review of the methodology and determined it was applicable to Unit 3 based on its configuration. For Unit 1, TVA performed a similarity analysis between the Unit 3 and Unit 1 instrumentation systems and concluded that the configuration of the two units is functionally the same and thus the evaluation was likewise applicable to Unit 1. Note that the setpoint methodology used for Unit 1 is the same as that used for Units 2 and 3.

Therefore, TVA has concluded that the BWROG generic analyses are applicable to BFN Unit 1 and the STI and AOT extensions in the current Unit 1 TS are acceptable.

U.S. Nuclear Regulatory Commission Page 3 November 1, 2006 There are no new commitments contained in this letter. If you have further questions on this submittal, please contact me at (205) 729-2636.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 1st day of November, 2006.

Sincerely, William D. Crouch Manager of Licensing and Industry Affairs

References:

1. TVA Letter dated September 7, 2006, BFN - Unit 1 -

Response to NRC Letter, Dated July 7, 2006 - Review of Pending License Amendment Request (TAC No. MC4797) (TS-432)

2. NRC letter dated July 7, 2006, Review of Pending License Amendment Request (TAC No. MC4797) (TS-432)

3. TVA Letter dated December 11, 1997, BFN - Units 1, 2, and 3 TS-362 - ITS - Supplemental Information - Changes to Instrumentation STIs and AOTs.

Enclosures cc: See page 5

U.S. Nuclear Regulatory Commission Page 4 November 1, 2006 Enclosure cc (Enclosure):

State Health Officer Alabama State Department of Public Health RSA Tower - Administration Suite 1552 P.O. Box 303017 Montgomery, Alabama 36130-3017 U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-8931 Mr. Malcolm T. Widmann, Branch Chief U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite Atlanta, Georgia 30303-8931 Margaret Chernoff, Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

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

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 NRC Unit 1 Restart Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611-6970

ENCLOSURE BROWNS FERRY NUCLEAR PLANT Unit 1 Comparison to Unit 3 Support for Applicability Analysis BWR Owner's Group Technical Specification Improvement Analysis

BROWNS FERRY NUCLEAR PLANT Unit 1 00.1 W77 061030 Comparison to Unit 3 Support for Applicability Analysis BWR Owner's Group Technical Specification Improvement Analysis Preparer Date 10/30106 George A. Washburn Checker Date 10/30/06 SRiA* ýSparks I

BROWNS FERRY NUCLEAR PLANT Unit I Comparison to Unit 3 History The generic study performed by GE provides the technical basis to modify the surveillance test frequencies and allowable out-of-service time of the RPS/ECCS/Rod Block/PCIS/ATWS&EOC RPT from the Generic Tech Specs. This generic study was extended by GE to apply to BFN Unit 2 based upon their analysis of the differences between Unit 2 and the generic plant previously evaluated.

Purpose The purpose of this analysis is to compare the configuration of BFN Unit 1 to the present configuration of BFN Unit 3 that was evaluated by TVA against the Unit 2 evaluation of the generic plant configuration, with the intent to conclude that the units are identical and therefore the previously issued TVA analysis of Unit 3 can be directly applied to Unit 1. The following pages are the comparison documented in the same format as the TVA analysis for Unit 3.

Methad The method of analysis consisted of the following steps:

• Review TVA Unit 3 analysis

• Pull Unit 1 and 3 drawings and documented references for affected systems.

• Compare Unit 1 configuration against current Unit 3 configuration

• Document and justify differences.

, Develop conclusion.

Concl1*ion Based upon the comparison of Unit 3 to Unit I as documented on the following pages it is concluded that the configuration of the two units is functionally the same and that the TVA analysis of Unit 3 is directly applicable to Unit 1.

References

• Various Drawings and documents as documented in the following sections.

• Unit I Technical Specification Change requests, TS-430, TS-433, TS-434, TS-436, TS-437, TS-438, TS-443, TS-447.

• Units 1, 2, 3 ITS Conversion request TS-362.

• Units 1, 2, 3 Technical Specification Change request TS-424

• Unit 3 Technical Specifications through Amendment 253.

• Unit I Technical Specifications through Amendment 255.

Page 1

BROWNS FERRY NUCLEAR PLANT UNIT 1 INSTRUMENTATION DATA

" ECCS INSTRUMENTATION

• RPV LEVEL 8 FEEDWATER PUMP/MAIN TURBINE TRIP

" CREV INITIATION INSTRUMENTATION

• END-OF-CYCLE RPT & ATWS RPT INSTRUMENTATION

• ROD BLOCK INSTRUMENTATION

• CONTAINMENT ISOLATION INSTRUMENTATION

• RPS INSTRUMENTATION Page 2

ECCS EVALUATION CHECKLIST FOR BROWNS FERRY NUCLEAR PLANT - Unit 1 Comparison to Unit 3 Support for applicability analysis BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation The ECCS configuration for UNIT I was compared to the current configuration of UNIT 3. The comparison is as documented as follows.

Page 3

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit I Section I - ECCS Plant Specific Data Sources Source Number

1. Main Steam (ADS) Flow Diagram: 1,3-47E801-1

2. RHR Flow Diagram: 1,3-47E81 1-1

3. HPCI Flow Diagram: 1,3-47E812-1

4. RCIC Flow Diagram 1,3-47E813-1

5. Core Spray Flow Diagram: 1,3-47E814-1

6. EECW Flow Diagram: 1,2,3-47E859-1

7. EECW System Design Criteria: BFN-50-7067

8. RCIC System Design Criteria: BFN-50-7071

9. HPCI System Design Criteria: BFN-50-7073

10. RHR System Design Criteria: BFN-50-7074

11. Core Spray System Design Criteria: BFN-50-7075

12. Technical Specifications, BFNP Unit 1 through Amendment 257.

13 NEDC-30936P-A, Part I, Technical Specification Improvement Methodology (With Demonstration For BWR ECCS Actuation Instrumentation), December 1988.

14. Browns Ferry FSAR: Section 4.4

15. Browns Ferry FSAR: Chapter 8

16. 1-SR-3.5.1.3.5(CS 1), (CS I), (R-R I), (RHR II), RHR & CS SYSTEM MOV OPERABILITY LOOP II

17. Technical Specifications, BFNP Unit 3 through Amendment 254 Page 4

Section II - ECCS Configuration Data A. ECCS System Difference U3 Vs U1 Data BFN-1(3) (Yes/No) Source1

1. Number of:

Core Spray Pumps/Loops 4/2(4/2) No 5 LPCI Pumps 4(4) No 2 ADS Valves 6(6) No I HPCI Pumps 1(1) No 3

2. Needed for Success, Number of:

Core Spray Pumps/Loops 2/1(2/1) No 13 LPCI Pumps 1(1) No 13 ADS Valves 2(2) No 13

3. Number of:

Diesel Generators 42(4) No 15 DC Power Divisions 2(2) No 15 AC Power Divisions 2 3A (2 3.5) No 15

4. IC or RCIC RCIC(RCIC) No 8 Loop Selection Logic No(No) No

'The numbers shown in the Data Source column refer to the documents listed in Section 1.

2 The Standby AC System for Units 1/2 consists of four diesel generators. The Standby AC system for Unit 3 is separate and consists of four diesel generators that supply power to the ECCS equipment for Unit 3. Some of the safety-related support equipment required for operation of Unit 3 (e.g., EECW pumps, CREVS) is powered from the four Unit 1/2 diesel generators.

3 There are two 4KV Shutdown Boards in AC Power Division I and two 4KV Shutdown Boards in AC Power Division II.

tach of the four Units 1/2 4KV shutdown Boards is electrically separated and powered from a separate diesel generator with a Shutdown Board of each division dedicated to each unit.

5Each of the four Unit 3 4KV Shutdown Boards is electrically separated and powered from a separate diesel generator.

Page 5

Section II- ECCS Configuration Data B. Supoort System Dependencies The figure below shows the arrangement of the EECW/RHRSW pumps along with the support Diesel Generators needed.

I The above system is shared between Units 1/2 and Unit 3 already and therefore was evaluated under the Unit 3 analysis.

Page 6

Section II- ECCS Configuration Data B. Sunuort System Dependencies The Automatic Depressurization system is arranged as shown below.

MainStam Line A MAi SUa= LineB B -

~a72 MafnSte&nw. C

ý iý Mainstam Uw DI Zl'-

The following table documents the ADS valve dependencies on power (logic not shown).

______II I I Batt 1 Batt 3 Batt 2 250 V RMOV IA 250 V RMOV lB 250 V RMOV 1C 1-34, 1M, 2M 1-31 1M, 2M 1-30 1A 2A 1-22 1A 2A 1-19 1M, 2M 1-5 1M, 2M I M is primary power and 2M is secondary, with manual transter trom I to 2 and bacK.

IA is primary power and 2A is secondary with automatic transfer from IA to 2A and back.

Page 7

Section II - ECCS Configuration Data B. Support System Dependencies The table below represents the dependencies of the diesel generator/AC power system upon the 250 VDC power system.

480V 480V Batt Batt Batt 4KV 4KV 4KV Shtdn Shtdn Bd Bd Bd Shtdn Shtdn Shtdn Bd Bd 1 2 3 SBA SBB SBC SBD BdA BdB BdC 1A 1B 4KV Shtdn Bd A 2 1 4KV Shtdn BdB 2 1 4KV Shtdn Bd C 2 1 11 4KV Shtdn BdD 2 1 480V Shtdn Bd IA S/D D A 480V Shtdn Bd 1B S/D A D RMOV Bd IA S D D RMOV Bd IB S D D RMOV Bd IC S D D The following are the explanations of the annotations. The A is 480VAC alternate feed, D is 480VAC direct feed, S/D represents that a support supply is both a secondary support and direct (e.g., 480 V Shtdn Bd 1A is fed from 4KV Shtdn Bd A which has Batt I as its support therefore SB-A is S for the Shtdn Bd 1A, 1 is primary, 2 is alternate (manual transfer).

Page 8

Section I - ECCS Configuration Data B. Support System Dependencies LPCI RHR PUMPS CORE SPRAY ADS RCIC HPCI DIESELS LPCI I LPCI I CS I I CS H I I I I A C B D A/C B/D A B A B C D Off Site Power X X X X X X X X On Site AC Power Div I (SD Bd A) X 1 A Div I (SD Bd B) X C Div 11 (SD BdC)Q X B Div II (SD Bd D) X D On Site DC Power Div I X X X X X X X Div 11 X X X 2 X X Service Water=

EECW North (pumps Al&*&C1) X X X X X X (SD (SD I BD A) BD B)

EECW South (pumps B I & D 1) X X X X X I X _ _ _ (3EC) (3ED)

'The LPCI injection valve for loop I is normally powered from DG 3EA. The LPCI injection valve for loop UIis normally powered from DG 3EC. The I represents the secondary support DG automatically transferred to power the valve on loss of primary power.

'Two of the six ADS valves are normally powered from a Division II power source. However, these valves will automatically transfer to a Division I power source if the Division 11 power source fails. Should Division I fail the two Division II ADS valves will be available.

'TheUI and U3 systems utilize the same type relays between the units. (CSIRHR/ADS/RCIC/HPCI all use HFAJHGA/CR120/CR28201Agastat)

'The following alternate EECW pumps can be used if the primary fails. Al alternate for A3, B I for B3, CI for C3, D I for D3. See previous figure that shows diesel dependency of various pumps.

Page 9

Section II - ECCS Configuration Data C. Support mm System II Dependencies m

LPCI RHR PUMPS CORE SPRAY ADS RCIC -PCI DESELS LPCI I LPCI H CSI CSH i CIS A I C I B I D I A/C I B/n I A I it A N Water Supply Suppression Pool X X X X X X X X_

Condensate Storage Tank2 I X X River X X X X Air Drywell Control Ar_ X X Control Air: Div 1 Control Air: Div 2 1 Containment Instrument: Div 1 Containment Instrument: Div 2 Room Cooling4' LPCI X X X X CS x x RCIC X HPCI X Diesels X X X X 2

7he RHR (LPCI) and Core Spray can be manually aligned to take suction from the Condensate Storage Tank by repositioning hand-operated valves in the torus room.

3 The ADS valves have a backup tie to CAD and have accumulators sized for 5 openings.

4 Room cooling also requires EECW to be funtWional (justified elsewhere).

Page 10

Section 1I - ECCS Configuration Data C. Support System Instrumentation Dependencies LPCI RHR PUMPS CORE SPRAY ADS RCIC HPCI DIESELS LPCI I A C LPCI IH CSI I CS H I I 1 B D A/C B/D A B A B C D RPV Water Level 1 (Low Low Low)

LS-3-58A X X X X X X X LS-3-58B X X X X X X X LS-3-58C X X X X X X X LS-3-58D X X X X X X X RPV Water Level 2 (Low Low)

LIS-3-58A, C _ .__ X X LIS-3-58B, D X X RPV Water Level 2 (Low)

LIS-3-184 x LIS-3-185 X RPV Water Level 8 (High) .....

LIS-3-208A, C X LIS-3-208B, D 1 X Page It

Section 1I - ECCS Configuration Data C. Support System Instrumentation Dependencies LPCI RHR PUMPS I CORE SPRAY ADS RCIC HPCI DIESELS LPCI I LPCI H CSI I CS H I I I A IC IB D IA/C B/D IA IB A B IC ID Drywell Pressure B I Bligh PIS-64-57B, D X PIS-64-57A, C X PS-64-58A X X X X X X X PS-64-58B X X X X X X X PS-64-58C X X X X X X X _

PS-64-58D X X X X X X X RPV Pressure Low PIS-3-74A X X X X X PIS-3-74B X X X X X PIS-68-95 X X X X X PIS-68-96 X X X X X Injection Valve DP The instwumets noted above are used in same manner as they are used in Unit 3.

Page 12

Section II - ECCS Configuration Data C. Support System Instrumentation Dependencies LPCI RHR PUMPS CORE SPRAY ADS RCIC HPCI DIESELS LPCI I LPCI ] CS I C II CS 1 1 A C B D A/C IB/D IA IB A B C ID I LPCI Pump Discharge Pressure Hight_

PS-74-8A&B X X PS-74-19A&B X X PS-74-3 1A&B X X PS-74-42A&._ X X CS Pump Discharge Pressure High' PS-75-7 X X PS-75-16 X X PS-75-35 X X PS-75-44 x x ADS Drywell Pressure Bypass Timer' .....

2-1-58A2 X 2-1-58B2 X 2-1-58C2 X 2-1-58D2 X 5

3-730E938-6, 9 6

0-730E930-24, 23 7

3-730E929-2 Page 13

Section 11 - ECCS Configuration Data C. Support System Instrumentation Dependencies LPCI RHR PUMPS CORE SPRAY ADS RCIC HPCI DIESELS LPCI I LPC1 11 CS I CS 1 A C B D A/C B/D A B A B C D ADS Timer' 2E-K34&35 X X Manual Initiation Switch LPCI Pump Discharge Flow Low FS-74-50 X X FS-74-64 X X Core Spray System Discharge Flow Low FS-75-21 X FS-75-49 X CST Level Low9 LS-73-56A, B-- X Suppression Pool (Torus) Level High LS-73-57A, B' X

'3-730E929-2 9

7he BFN- I RCIC System Does NOT have automatic transfer of the pump suction path.

1056 OR 57 LOOPS Transfer Page 14

Section II - ECCS Configuration Data C. Support System Instrumentation Dependencies LPCI RHR PUMPS CORE SPRAY ADS RCIC HPCI DIESELS LPCI II LPCI H CS ICS H A C I B D A/C B/D A B A B IC D ADS Inhibit Switch XS-1-159A X XS-1-161A X HPCI Pump Discharge Flow Low FIS-73-33 X HPCI Turbine Exhaust Pressure High PS-73-22A&B X HPCI Pump Suction Pressure Low PIS-73-29-1 X HPCI Turbine Exhaust Rupture Disc Pressure High PS-73-20A,B,C,D X High Steam Supply Pressure Low PS-73-IA,B,CD X Page 15

Section II - ECCS Configuration Data D. Support System & Instrumentation Dependencies Summary A review of plant drawings and docunmnts has concluded that the Unit I systems are functionally identical to the Unit 3 systems. There is no difference in the UFSAR described design functions.

Page 16

Section II - ECCS Configuration Data D. Minimum Number of Sensors, Channels. or Components for Failure, BFN-1.

A = MINIMUM NUMBER OF SENSOR FAILURES REQUIRED TO FAIL TRIP FUNCTION B = MINIMUM NUMBER OF SENSOR FAILURES REQUIRED TO FAIL FUNCTION - TOTAL C = MINIMUM NUMBER OF SENSOR TYPES REQUIRED TO FAIL FUNCTION Different From unit 1 Unit 3 Trip Function A B C B C CS Pump (2 Drywell Pressure OR 2 Low RPV Pressure) 4 2 No No Initiation' AND 2 RPV Level I (LOLOLO)

CS Injection 2 2 RPV Low Pressure 2 1 No No Valve LPCI Pump (2 Drywell Pressure OR 2 Low RPV Pressure) 4 2 No No Initiation' AND 2 RPV Level 1 (LOLOLO)-

LPCI 3Inection 2 RPV Low Pressure 2 1 No No Valve ADS Initialion 2 RPV Level I (LOLOLO)4 2 1 No No OR 2 RPV Level 3 (LOW)-

OR 1 RPV Level I AND 1 RPV Level 36 OR 2 Drywell Press High AND 2 Drywell Press Bypass Tuners ADS Time Delay 2 timers 2 1 No No HPCI Level 8. 2 RPV Level 8 (High) 2 1 No No HPCL Initiation' 2 Drywell Pressure (high) 4 2 No No AND 2 RPV Level 2 (I)LOW))

HPCI Injection 2 Drywell Pressure (high) 4 2 No No Valve AND

,,___2 RPV Level 2 (LOLO)

HPCI Water 2 Condensate Header Level 2 1 No No Source' RCIC Initiation' 2 RPV Level 2 (LOLO) 2 1 No No RCIC Level 8' 2 RPV Level 8 (Hih) 2 1 No No RCIC Injection 2 RPV Level 2 (LOLO) 2 1 No No 9

Valve

'1 of 2 twice level OR (1 of 2 twice hi DWP and I of 2 twice Lo RVP).

21 of 2 for bus A, I of 2 for bus B.

31 of 2 twice RPV low pressure.

4 (one on bus A & one on bus B).

5 (one on bus A & one on bus B).

6(one on bus A & one on bus B).

71 of 2 twice level or 1 of 2 twice high DW pressure.

82 of 2 to trip.

9' of 2 twice on RPV level Page 17

l Section II - ECCS Configuration Data E. Surveillance Requirements, ECCS Instrumentation and Related Subsystems' DIFFERENCE BFN-1 BFN-3' (Ye/No)

CORE SPRAY SYSTEM REACTOR WATER LEVEL 1 (LOW-LOW-LOW) Q Q No DRYWELL PRESSURE HIGH Q Q No REACTOR PRESSURE LOW Q Q No MANUAL INITIATION N/A N/A No LPCI REACTOR WATER LEVEL 1 (LOW-LOW-LOW) Q Q No DRYWELL PRESSURE HIGH Q Q No REACTOR PRESSURE LOW Q Q No INJECTION VALVE DIFFERENTIAL PRESSURE LOW N/A N/A No MANUAL INITIATION N/A N/A No HPCI REACTOR WATER LEVEL 2 (LOW-LOW) Q Q No DRYWELL PRESS URE HIGH Q Q No CST LEVEL LOW Q Q No SUPPRESSION POOL LEVEL HIGH Q Q No REACTOR WATER LEVEL 8 (High) Q Q No MANUAL INITIATION N/A N/A No ADS REACTOR WATER LEVEL 1 (LOW-LOW-LOW) Q Q No DRYWELL PRESSURE HIGH Q Q No ADS DRYWELL PRESSURE BYPASS TIMER 24M 24M No ADS TIMER 24M 24M No CORE SPRAY PUMP DISCHARGE PRESSURE Q Q No LPCI PUMP DISCHARGE PRESSURE Q Q No REACTOR WATER LEVEL (LOW) Q Q No MANUAL INITIATION N/A N/A No INJECTION VALVE STROKE TEST Q Q(ref2l) No DIESEL GENERATOR M M No ELECTRIC POWER3 ESSENTIAL AC W W No ESSENTIAL DC W W No ESSENTIAL AC Buses W W No Page 18

4 DIFFERENCE BFN-1 BFN-3 (Yes/No)

RCIC REACTOR WATER LEVEL 2 (LOW LOW) Q Q No REACTOR WATER LEVEL 8 (HIGH) Q Q No CST LEVEL LOW N/A N/A No SUPPRESSION POOL LEVEL HIGH N/A N/A No MANUAL INITIATION N/A N/A No

'Based on Technical Specifications (Reference 12, 17) 2M = Monthly, W = Weekly, R = Refueling, Q = Quarterly 3

1-SR-3.3.8.1.3(3EC).a covers the weekly Essential DC. SI-2 (TS section 4.9.A.4.d) does a verification of 4KV Shutdown Board voltages every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> which could be construed to mean Essential AC and Essential AC Buses are verified more than 4 once per week.

ff Unit 3 took no credit for a function then Unit 1 also will not (N/A).

Page 19

RFPT & Main Turbine RPV High Water Level Trip Instrumentation EVALUATION CHECKLIST FOR BROWNS FERRY NUCLEAR PLANT - Unit 1 Comparison to Unit 3 Support for applicability analysis BWR Owners' Group Technical Specification Improvement Analyses for RFPT & Main Turbine RPV High Water Level Trip Instrumentation The RFPT & Main Turbine RPV High Water Level Trip Instrumentation configuration for UNIT 1 was compared to the configuration of UNIT 3 as evaluated by drawing and document review. The comparison is as documented as follows.

Page 20

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section I - RFPT & Main Turbine RPV High Water Level Trip Instrumentation Plant Specific Data Sources Source Number

1. RFPT Schematic: 1,3-45E612-1

2. Turbo Generator Auxiliaries Schematic: 1,3-45E602-1

3. Feedwater Control System 1,3-729E895

4. ECCS Div II ATU Schematic 1-45E670/1 series 3-45E670-36, -30

5. Technical Specification, BFNP Unit 1 Amendment 257

6. Technical Specifications, BFNP Unit 3 Amendment 254

7. Unit 3 data as documented in TS-362 Section I! - ECCS Configuration Data A. RFPT & Main Turbine RPV High Water Level Trip Instrumentation System The instrumentation listed in the table below initiates a signal to trip the three reactor feedwater pump turbines (RFPTs) and the main turbine from redundant trip channels A or B. Two out of Two logic in either trip channel will initiate a RFPT and Main Turbine Trip. Trip Channel A is initiated by coincident actuation of instrument loops A and C. Trip Channel B is initiated by coincident actuation of instrunmnt loops B and D.

Table 1 RFPT & Main Turbine Hiirh Water Level Trin Instrumentation Function Conmnon Instrument Test Cal to Common Function Number Frequency Frequency ECCS to RPS Umt 3 RPV Level 8 LS-3-208A RFPT & Main LS-3-208B Turbine Trip LS-3-208C 92 Days 24 Months Yes 1 No LS-3-208D Unit 1 RPV Level 8 RFPT LS-3-208A

& Main Turbine Trip LS-3-208B LS-3-208C 92 Days 24 Months Yes2 No LS-3-208D

==

Conclusion:==

As can be seen above the Unit 1 configuration is identical to the Unit 3 configuration previously analyzed and determined to be adequate.

'Instrument loops B and D are common to ECCS (e.g. HPCI high level trip). A and C provide RCIC high level trip.

2 lnstrument loops B and D are common to ECCS (e.g. HPCI high level trip). A and C provide RCIC high level trip.

Page 21

Control Room Emergency Ventilation/Isolation Instrumentation EVALUATION CHECKLIST FOR BROWNS FERRY NUCLEAR PLANT - UNIT 1 Comparison to Unit 3 Support for applicability analysis BWR Owners' Group Technical Specification Improvement Analyses for Control Room Emergency Ventilation/Isolation Instrumentation The Control Room Emergency Ventilation/Isolation Instrumentation configuration for UNIT 1 was compared to the configuration of UNIT 3 as evaluated by drawing and docunmnt review. The comparison is as documented as follows. The CREVs is a shared system previously evaluated for Unit 3; therefore, it equally applies to Unit 1.

Page 22

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section I - Control Room Emergency Ventilation/Isolation Instrumentation Plant Specific Data Sources Source Number

1. Control Bay Emergency Isolation Schematic: 0-45E769-11

2. Primary Containment Isolation System: 1,3-730E927-18

3. CREVS Wiring Diagrams 0-55E725 0000

4. CREVS Wiring Diagrams 0-92D510-09 series

5. Technical Specifications, BFNP Unit 1 Amendment 257

6. BFNP Control Bay and Reactor Building Board Rooms BFN-50-7030A Environmental Control System Design Criteria:

7. Unit 3 data as documented in TS-362

8. Technical Specifications, BFNP Unit 3 Amendment 254 Section II - Control Room Emergency Ventilation/Isolation Instrumentation Configuration Data A. Control Room Emergency Ventilation/Isolation Instrumentation System The instrumentation listed in the table below initiates isolation of the Control Room and initiates the Control Room Emergency Ventilation (CREV) system due to high radiation in the Control Room air intake. A PCIS Group 6 isolation signal will also provide a Control Room isolation and CREVs initiation. One of two redundant control room emergency pressurization units will be initiated from the radiation monitors or PCIS group 6 isolation signal. The redundant control room pressurization unit will start upon failure or loss of the first unit. It should be noted that this is not a Unit 3 versus Unit 1 comparison. The two CREVS previously analyzed are shared by both Units.

==

Conclusion:==

It should be noted that this is not a Unit 3 versus Unit 1 comparison. The two CREVS previously analyzed are shared by both Units.

Page 23

EOC RPT & ATWS RPT EVALUATION CHECKLIST FOR BROWNS FERRY NUCLEAR PLANT - UNIT 1 Comparison to Unit 3 Support for applicability analysis BWR Owners' Group Technical Specification Improvement Analyses for EOC RPT & ATWS RPT Instrumentation The EOC RPT & ATWS RPT Instrumentation configuration for UNIT 1 was compared to the configuration of UNIT 3 as evaluated by drawing and document review. The comparison is as documented as follows:

Page 24 I

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section I - EOC RPT & ATWS RPT Instrumentation Plant Specific Data Sources Source Number

1. Reactor Recirculation Systenm 1,3-45E611-68-5

2. Recirculation Pump Trip Schematic Diagram: 1,3-45E763-11 R003, -12

3. BFN Reactor Water Recirculation System Design Criteria: BFN-50-7068

4. Technical Specifications, BFNP Unit 1 Amendment 257

5. Unit 3 data as documented in TS-362

6. Technical Specifications, BFNP Unit 3 Amendment 254 Section I1 - EOC RPT & ATWS RPT Instrumentation Configuration Data A. EOC RPT Instrumentation System There are two divisions of EOC RPT logic. Each division receives signals indicating turbine stop valve closures (two-out-of-two logic) or turbine control valve fast closure (two-out-of-two logic) from the reactor protection system (RPS) to trip the recirculation pump motor breakers, Either of these signals will trip both recirculation pumps. Signals indicating first stage turbine pressure greater than 30% are provided from RPS to permit the recirculation pump trip.

Table 1 EOC RPT Instrumentation Function Common Instrument Test Cal to Counon to Function Number reuency3 Frequency ECCS RPS Turbine Control (PS-47-142 AND PS-47-144)

Valve Closure OR 92 Days 24 M No Yes

.... (PS-.47-146 AND PS-47-148)

Above OR Below Turbine Stop (ZS-1-74F AND ZS-1-78F)

Valve Closure OR 92 Days 24 M No Yes (ZS-1-84F AND ZS-1-88F)

Allowed Out-of-Service Times Allowed outof-service times for EOC RPT instrumentation are addressed in the Technical Specification requirements. Inoperable instrument channels must be restored to operate status within 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />s4 s or additional actions must be taken (e.g. insert control rods or reduce power). The TS for Unit 1 states that one channel may be placed in an inoperable status fbr up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without placing the trip system in the tripped condition. The Unit 3 TS also states 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

3The RPT breakers are tested once per operating cycle.

4 TS 3.3.4.1.C Page 25

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 B. ATWS RPT Instrumentation System There are two divisions of ATWS RPT logic. Each division receives signals indicating low reactor water level (two out of two logic) or high reactor pressure (two-out-of-two logic) to trip the recirculation pump motor breakers. Either of these signals will trip both recirculation pumps. These signals are independent of the EOC RPT trip signals transmitted from RPS.

Table 1 ATWS RPT Instrumentation Function Common Instrument Test Cal to Common to Function Number Frequencf Frequency ECCS RPS RPV Water (LS-3-58A1 AND LS-3-58B1)

Level 2 (1o-lo) OR 92 Days 24 M Yes No (LS-3-58C1 AND LS-3-58D1)

Above OR Below RPV Pressure (PS-3-204A AND PS-3-204B)

High OR 92 Days 24 M Yes No (PS-3-204C AND PS-3-204D)

Allowed Out-of-Service Times Current Technical Specifications allow one channel of ATWS RPT instrumentation in only one trip system to be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance provided the other channels in that trip system are operable.

If a channel is found to be inoperable or if the surveillance/maintenance/ealibration period for one channel exceeds 6 consecutive hours, the trip system will be declared inoperable or the channel will be placed in a tripped condition.

C. Conclusions Review of the Unit 3 information (reference 5) shows that the Unit I data is identical.

5The breaker is tested once per operating cycle.

Page 26

Rod Block EVALUATION CHECKLIST FOR BROWNS FERRY NUCLEAR PLANT - UNIT 1 Comparison to Unit 3 Support for applicability analysis BWR Owners' Group Technical Specification Improvement Analyses for Rod Block Page 27

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section I - Rod Block Instrumentation Plant Specific Data Sources Source Number

1. Reactor Protection System Schematic: 1,3-730E915-series

2. Reactor Manual Controls Schematic 1,3-730E32 1-series

3. Start-up Range Neutron Mon Sys Schematic 1,3-730E237-series

4. Scram Discharge Volume Instruments 1,3-47E610-85-5

5. GE Analysis of ROD Block GENE-A31-0002-03

6. Technical Specifications, BFNP Unit 1 Amendment 257

7. Unit 3 data as documented in TS-362

8. Technical Specifications, BFNP Unit 3 Amendment 254 Page 28

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Rod Block Instrumentation Configuration Data A. Rod Block Instrumentation System The instrumentation used for Rod block signal generation are detailed in the table below. It should be noted that the equipment and configuration is the same as Unit 3.

BFN Unit 1 Rod Block Instrumentation Functional Test Calibration Common to Common Function Frequency Frequency ECCS to RPS APRMi NO YES

" upscale (flow biased) 184 Days 24M

• upscale (startup)7 184 Days 24M

• downscale8 184 Days 24M

" inoperative 184 Days N/A RBM NO NO

" upscale (flow biased) 184 Days 24M

" downscale 9 184 Days 24M

" inoperative1 5 184 Days N/A IRMLU NO YES

" upscale 7 Days 92 Days

" downscale tt 12 7 Days 92 Days

" detector not in start position 13"14 7 Days 24M SinoperativeM 7 Days N/A SRiM.. NO YES

" upscale 7 Days 92 Days

" downscale"7 7 Days 92 Days

" detector not in start position 7 Days 24M

" inoperative 7 Days N/A Recirc Flow Bias Comparator M 24M NO YES Recirc Flow Bias Upscale M 24M NO YES West SDV High Water Level LS-85-45L 92 Days 24M NO NO 6

The functional test frequency and calibration frequency specified for the APRMs and RBMs should be revised as part of the PRNM Upgrade Modification for Unit 1.

7 0 6

'-' " Bypasqed when Mode Switch placed in RUN.

8,9Active when mode switch is in RUN, Bypassed when IRMa are operable but not high.

Lt'13IRM downscale is bypassed on its lowest range.

2 1 All SRM rod Block functions are bypassed when all the IRMs are on range 8 or above.

14 '15A!1 SRM rod Block functions are bypassed when all the IRMs are on range 8 or above.

17SRM Downscale functions are bypassed when IRMs are above range 2. SRM detector not in startup position is bypassed when the count rate is >= 100 CPS or the condition above is satisfied.

Page 29 I

BFN Unit 1 Rod Block Instrumentation Functional Test Calibration Common to Common Function Frequency Frequency ECCS to RPS "East SD.V High Water L.evel NO NO LS-85-45M 92 Days 24M SDV High Water Level Scram Bypass N/A N/A NO YES Reactor Mode Switch HS-99-5A-S 1 24 M NIA NO YES Scram Discharge Volume High Water Level Rod Block There is one level instrument in each scram discharge volume which provides a rod block signal.

Each level instrument provides a rod block signal to one of the two rod block channels.

ROD Block Logic The Rod Block logic for BFN Unit 1 is the same as for Unit 3 based upon drawing review.

Allowed Outage Times for Rod Block Instrumentation Current Technical Specifications specify that during repair or calibration of equipment, not more than one SRM or RBM channel nor more than two APRM or IRM channels may be bypassed. Bypassed channels are not counted as operable channels to meet the minimum operable channel requirements specified in the TS Table 3.3.2.1.

Allowed outage time is specified as once per outage in the current Technical Specifications Basis for calibration and functional testing of the Recirculation Flow Bias Comparator or Flow Bias Upscale instrumentation. With the number of operable channels less than required by the minimum operable channels per trip function requirement, at least one inoperable channel must be placed in the tripped condition within one hour.

No specific allowed outage time is provided in the current Technical Specifications for calibration and functional testing of the SDV High Water Level Rod Block instrumentation. If this function is not operable at a time when operability is required, the channel must be tripped or administrative controls must be immediately imposed to prevent control rod withdrawal.

CONCLUSION The Unit I Rod block system is the same as the evaluated Unit 3 system.

Page 30

Containment Isolation Instrumentation Data EVALUATION CHECKLIST FOR BROWNS FERRY NUCLEAR PLANT - UNIT 1 Comparison to Unit 3 Support for applicability analysis BWR Owners' Group Technical Specification Improvement Analyses for Containment Isolation Instrumentation Page 31

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section I - Containment Isolation Instrumentation Plant Specific Data Sources Source Number

1. PCIS Elementary Diagrams 1,3-730E927-Series

2. Technical Specifications, BFNP Unit I Amrndment 257

3. GE Analysis of PCIS GENE-A31-0002-04 RI

4. Unit 3 data as documented in TS-362

5. Technical Specifications, BFNP Unit 3 Amendment 254 Page 32 I

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data A. Containment Isolation Instrumentation System The instrumentation for the containment isolation logic groups (table 1) initiates signals to perform various containment isolation functions as follows:

Group 1 Main steam isolation valve closure is initiated by one-of-two twice logic, and main steam drain valve by one-of-two-twice from Group 1 instrumentation.

Group 2 The RHR shutdown cooling suction and LPCI injection valves, the drywell floor and equipment sump drain valves, and the torus drain valves are isolated by one-of-two twice logic from Group 2 instrumentation. Instrumentation used for Group 2 isolation is common to RPS. A LPCI initiation signal will override the Group 2 isolation signal fbr the LPCI injection valves. Group 2 isolation also initiates Group 8 (TIP withdrawal).

Group 3 RWCU supply valve isolation is initiated by one-of-two-twice logic from Group 3 instrumentation.

Group 4 HPCI steam supply and pump suction isolation is initiated by one-of-two-twice logic (with the exception of high steam line flow (one-of-two) from Group 4 instrumentation.

Group 5 RCIC steam supply and pump suction isolation is initiated by one-of-two-twice logic (with the exception of high steam line flow (one-of-two) from Group 5 instrumentation.

Group 6 Group 6 isolation is initiated by four sets of instrumentation, two of which are common to RPS (RPV water level and high drywell pressure).

The RPV water level and high drywell pressure isolation are both one-of-two-twice.

Radiation monitor HIGH logic is one-of-(two-of-two twice). Radiation monitor DOWNSCALE logic is one-of-two-twice.

The Group 6 isolation signal activates SGTS, isolates the reactor zone, and refueling zone secondary containment boundaries, and isolates the reactor building main vent.

The Group 6 logic also isolates the following primary containment isolation valves: Containment purge and exhaust, containment inerting makeup/purge, drywell control air, post accident sampling, drywell/torus differential pressure compressor line, hydrogen/oxygen analyzers sample and return, CAD exhaust to SGTS, and airborne radiation monitor sample lines.

The relays used are a mixture of GE HFA, and CR 120 relays (as are the Unit 3 relays).

Page 33

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data B. Containment Isolation Instrumentation System PCIS Group 1 (Main Steam Line Isolation)

Instrument Function Test Calibration Common Common Same as Function Number Frequency's Frequency to ECCS to RPS Unit 3 LIS-3-56A RPV LevelRVLvl LIS-3-56B LS35B92 Days 24 M No No Yes (low-low-low) LIS-3-56C LIS-3-56D PIS-1-72 MS Line PIS-1-76 Pressure Low PIS-1-82 92 Days' 9 24 M No No Yes PIS-1-86 PDIS-1-13 (A-D)

Main Steam PDIS-1-25 (A-D) 92 Days 2 0 24 M No No Yes Line High Flow PDIS-1-36 (A-D)

PDIS-1-50 (A-D)

TS-1-17 (A-D)

Main Steam TS-1-29 (A-D)

Tunnel Space TS-1-40 (A-D) 92 Days 24 M No No Yes High Temp TS-1-54 (A-D)

" 8The Logic is tested as noted above (actual actuation is tested each refueling outage).

The Logic is ((A OR C) AND (B OR D))

"9 The functional test frequency was decreased to once per 3 month to reduce challenges to relief valve settings per NUREG 20 0737 Item I1.K3.16. TS TBL 3.3.6.1-1.

The functional test frequency was decreased to once per 3 month to reduce challenges to relief valve settings per NUREQ 0737 Item H.K3.16. TS TBL 3.3.6.1-1.

Page 34

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data B. Containment Isolation Instrumentation System PCIS Group 2 (RHR, Drywell Floor & Equipment Drain Valve Isolation)

Instrument Function Test Calibration Common Common Same as Function Number Frequency2 ' Frequency to ECCS to RPS Unit 3 LIS-3-203A RPV Level 3 (lw LIS-3-203B I--0C92 Days 24 M No Yes Yes (low) LIS-3-203C LIS-3-203D PIS-64-56A Drywell Drwl PIS-64-56B I-45B92 Days 24 M No yes Yes Pressure High PIS-64-56C PIS-64-56D 21 The Logic is tested as noted above (actual actuation is tested each refueling outage).

The Logic is ((A OR C) AND (B OR D))

Page 35

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data B. Containment Isolation Instrumentation System PCIS Group 3 (RWCU System Isolation)

Instrument Function Test Calibration Common Common Same as Number Frequencyu Frequency to ECCS to RPS Unit 3 LIS-3-203A RPV Level 3 LIS-3-203B (low) LIS-3-203C 92 Days 24 M No Yes Yes LIS-3-203D Main Steam TIS-69-834A Tunnel Temp TIS-69-834C 92 Days 24 M No No Yes High TIS-69-834D TIS-69-835A RWCU Pipe TIS-69-835B Trench Temp TIS-69-835C 92 Days 122 Days No No Yes High TIS-69-835D TIS-69-836A RWCU Pump TIS-69-836B Room 2A Temp TIS-69-836C 92 Days 122 Days No No Yes High TIS-69-836D TIS-69-837A RWCU Pump TIS-69-837B Room 2B Temp TIS-69-837C 92 Days 122 Days No No Yes High TIS-69-837D RWCU TIS-69-838A Exchanger RxcmaTem TIS-69-838BYe TIS-69-838B 92 Days 122 Days No No Yes Room Temp TIS-69-838C High TIS-69-838D RWCU Heat TIS-69-839A Exchanger TIS-69-839B Room Pipe TIS-69-839C 92 Days 122 Days No No Yes Chase Temp TIS-69-839D High_

22 The Logic is tested as noted above (actual actuation is tested each refueling outage).

The Logic is ((A OR C) AND (B OR D))

Page 36

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data B. Containment Isolation Instrumentation System PCIS Group 4 (HPCI System Line Isolation)

Instrument Function Test Calibration Common Common Same as Number Frequency Frequency to ECCS to RPS Unit 3 HPCI Steam PDIS-73-IA 92 Days 24 M No No Yes Line High Flow PDIS-73-IB PS-73-1A HPCI Steam PS-73-IA Supply Pressure PS-73-IC 92 Days 24 M No No Yes PS-73-lD HPCI Turbine PS-73-20A Exhaust R upt PS-73-20B PS-73-20B 92 Days 24 M No No Yes Rupture Di sc PS-73-20C Pressure High PS-73-20D HPCI Steam TS-73-2A Line Space TS-73-2BYe TempaHg TS-73-2C 92 Days 92 Days No No Temp High TS-73-2C Yes (HPCI Room) TS-73-2D_

HPCI Steam TS-73-2 (E,F,G,H)

Temp TS-73-2 (J,K,L,M) 92 Days 92 Days No No Yes Teru Room)

(Torus Rom ) TS-73-2 T-7-(,P,) (NPHiS)

Page 37

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data B. Containment Isolation Instrumentation System PCIS Group 5 (RCIC System Line Isolation)

Instrument Function Test Calibration Common Common Same as Number Frequency Frequency to ECCS to RPS Unit 3 RCIC Steam PDIS-71-IA 92 Days 24 M No No Yes Line High Flow PDIS-71-IB PS-71-1A RCIC Steam PS-71-IA Supply Pressure PS-71-1B 92 Days 24 M No No Yes Low PS-71-ID PS-71-ID RCIC Turbine PS-71-1 IA Exhaust PS-71-1IB 92 Days 24 M No No Yes Rupture Disc PS-71 -1IC Pressure High PS-71-11D RCIC Steam TS-7 1-2A Line Space TS-71-2B 92 Days 92 Days No No Yes Temp High TS-71-2C (RCIC Room) TS-71-2D RCIC Steam TS-71-2 (EF,G,H)

Line Space TS-71-2 (J,K,L,M) 92 Days 92 Days No No Yes Temp Rom (Torus Room) TS-71-2 (NPHgS)

TS7-(N,,)

Page 38

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data B. Containment Isolation Instrumentation System PCIS Group 6 Instrument Number Function Test Frequency Calibration Frequency Common Common Same as to ECCS to RPS Unit 3 LIS-3-203A RPV Level 3 LIS-3-203B (low) LIS-3-203C 92 Days 24 M No Yes Yes LIS-3-203D PIS-64-56A Drywell PIS-64-56B Yes Pressure High PIS-64-56C 92 Days 24 M No Yes PIS-64-56D RM-90-142A Reactor Zone RM-90-142B Radiation High RM-90-143A 92 Days 24 M No No Yes RM-90-143B RM-90-140A Refuel Zone RM-90-140B Radiation High RM-90-141A RM-90-141B Page 39

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - Containment Isolation Instrumentation Configuration Data B. Containment Isolation Instrumentation System Allowed Out of Service Times Current Technical Specifications allow one channel of containment isolation instrumentation to be placed in an inoperable status for up to six hours for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter. For the reactor building ventilation system, one channel may be inoperable for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for functional testing or for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for calibration and maintenance, as long as the downscale trip of the inoperable channel is placed in the tripped condition.

C. Summary As noted in the tables the logic is the same, and the relays used are the same in the logic. The instrumentation is the same (TS Settings are the same) between Unit 1 and Unit 3 therefore any conclusions drawn for Unit 3 are applicable to Unit 1 also.

Page 40

RPS Instrumentation Data EVALUATION CHECKLIST FOR BROWNS FERRY NUCLEAR PLANT - UNIT 1 Comparison to Unit 3 Support for applicability analysis BWR Owners' Group Technical Specification Improvement Analyses for RPS Instrumentation Page 41

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section I - RPS Instrumentation Plant Specific Data Sources Source Number I. RPS Elementary Diagrams: 1,3-730E9 15-Series

2. RPS Circuit Protector Elementary Diagrams: 1,3-45E641-5

3. RPS Design Criteria: BFN-50-7099 Rev 7

4. FSAR Section 7

5. Technical Specifications, BFNP Unit 1 Amendment 257

6. BFN Sis (e.g., 1-*SR-3.3.1.1.9(IRM A), 1÷SR-3.3. 1.1.15(B 1)

7. Main Steam Flow Diagram 1,3-47E801-1

8. Unit 3 data as documented in TS-362

9. Technical Specifications, BFNP Unit 3 Amendment 254 Page 42

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - RPS Instrumentation Configuration Data A. RPS Instrumentation System Data Source (aee r ce Item Data Same as Unit 3 (see references)

Number of trip systems 2 Yes I Number of logic channels per trip system:

For Automatic Scram 2 Yes 1 For Manual Scram 1 1 Power Supply source for each channel MG Setzo Yes 2 Operation Mode Yes Yes De-energize to trip Logic Arrangement Yes1 Yes I One-of-two twice Electrical Protection Assemblies (EPAs) Yes Yes 2 Design Requirement IEEE 279 Yes 3, 4 23 There is an alternate feed from a regulating transformer (also circuit protected).

2"Tip logic is one-of-two twice except for (1) Turbine stop valve closure which is 3-of-4, and (2) MSIV closure scram which is 3-of-4 steam lines less than 90% open.

Page 43

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - liPS Instrumentation Configuration Data B. RPS Sensors

1. Identify the type, total number, and number per RPS channel for the following RPS sensors Total Number Same as Type Number per RPS Reference Unit 3 Channel APRM Analog 6 2 2 Yes Turbine Stop Valve Position switch 4 2 2 Yes Turbine Control Valve Pressure switch 4 1 2 Yes MSIV Position Pressure switch 8 4 2 Yes RPV Low Level 3 ATU 4 1 2 Yes SDV Level Type 1 Heated RTD 4 1 2,5 Yes SDV Level Type 2 Float switch 4 1 2,5 Yes High Reactor Pressure ATU 4 1 2 Yes High Drywell Pressure ATU 4 1 2 Yes Manual Trip2' Switch 2 1 2 Yes Mode Switch Trip Switch 1 1 2 Yes Low Condenser Vacuum NA Yes low Scram Air Header Pressure Pressure switch 4 1 2 Yes IRM Analog 8 2 2 Yes 25

' There are two manual trip switches one for each of the two RPS trip systems.

Page 44

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - RPS Instrumentation Configuration Data B. lIPS Sensors

2. Turbine stop valve closure logic arrangement is closure of Reference 2 3-out-of-4 valves initiates scam

3. Turbine stop valve closure monitoring is via position switches Reference 2

4. Turbine control valve fast closure monitoring is via oil pressure switches Reference 2

5. MSIV closure logic arrangement is closure of 3-out-of-4 mainsteam Reference 2 lines initiates scam

6. Diversity in SDV level sensors is via float switches and heated RTD Reference 5 level sensors

7. BFN Unit 1 has 4 steam lines as does Unit 3 Reference 7

8. List of available bypasses Reference 1, 3, 4 IRM trip bypass yes APRM trip bypass yes Noncoincident neutron monitoring system trip bypass yes26 RPV high level RPS trip bypass NA27 Turbine stop valve RPS trip bypass yes Turbine control valve RPS trip bypass yes28 29 MSIV closure RPS trip bypass yes SDV high level trip bypass yes 30 Reactor mode switch "shutdown" mode trip bypass no Technical Specification Table 3.3.1.1-1 for both units shows the same settings for the trip instrumentation.

6Shorting links "7Bypassed at <30% power

• SBypassed at <30% power 29 1n refuel/shutdown 3 0SDV bypassed in shutdown Page 45

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - RPS Instrumentation Configuration Data C. Sensor Relays

1. Types of relays used are GE type HFA and CR120A. Contactors are GE type CR105 per Reference 1.

2. Number of pairs of contacts per relay in trip channel is 2 per Reference 1.

3. List type of relay for each RPS sensor CRI05 HFA CR120

" APRM/IRM X X

• Turbine Stop Valve X

" Turbine Control Valve X

• MSIV Position X

" RPV Level 3 X X

• SDV Level RTD X

• SDV Level Float Sw X

• High RPV Pressure X

• High Drywell Pressure X

• Manual Trip X

• Mode Switch Trip X D. Scram Contactors

1. Scram contactors are GE CR105 per Reference 1.

2. Total number of scram contactors is 8 for auto trip and 4 for manual trip per Reference 1.

3. The number of contactors per channel is 2 for auto per Reference 1.

E. Air Pilot Solenoids Valves 1, There are 2 solenoid valves per control rod per Reference 1, 4.

2. There are 2 scram solenoid valves per control rod drive. Both scram solenoid valves must de-energize to vent the control air header which opens the associated scram outlet valve and opens the associated scram inlet valve to insert the control rod.

F. Backup Scram Valves

1. Scram contactors for the Backup scram valves are GE type CR105 per Reference 1.

2. There are 6 scram contactors for each backup scram valve (4 automatic, 2 manual) per Reference 1.

3. The scram contactors are the same as those used for RPS per Reference 1.

4. The backup scram valves are energized to actuate per Reference 1.

5. The technical specifications do not specify any tests for the backup scram valves.

Page 46

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - RPS Instrumentation Configuration Data G. RPS Technical Specification Requirements

1. Calibration frequency for LPRMs is every 1000 effective full power hours. Per Reference 5.

2. Calibration frequency for trip units is not specified directly but a functional check of the setpoints is performed monthly as part of 1-SR-3.3.1.1.9(IRMA-H) and Reference 7 (If outside bounds calibration occurs).

3. Frequency of logic system functional are not specifically called out in the technical specifications but are performed as part of the ATU calibrations in item 2 (up to half scrams). See item 2 references.

4. The allowable time to place an inoperable channel or trip system in tripped condition when the number of operable channels is less than the required minimum operable channels for one trip systems is 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Reference 5.

5. There is an exception to item 4, six hours is allowed to perform required surveillances. (TS 3.3.1.1, Reference 5).

6. Allowable time to restore a trip system when the number of operable channels is less than the required minimum operable channels for both trip systems where placing the channel in trip will trip the plant is 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per Reference 5.

7. There are no exceptions to item 6.

Channel Functional Channel Operable Functional Unit Check Test Calibration Channels per Check Test_ Calibration Trip System APRM

" Flow biased simulated thermal power high N/A 184 Days 24 M 3

" Neutron flux high 184 Days 24 M 3

" Inoperative 184 Days N/A 3

" Downscale W 24 M 3 Reactor Vessel Steam Dome Pressure High N/A 92 Days 184 Days 2 Reactor Vessel Water Level Low Level 3 N/A 92 Days 24 M 2 Reactor Vessel Water Level High evel 8 N/A 92 Days 24 M 2 MSIV Closure N/A 92 Days 24 M 8 Main Steam Line High Radiation N/A N/A NIA N/A Drywell Pressure High N/A 92 Days 24 M 2 Main Condenser Low Vacuum N/A N/A NIA N/A SDV High Level (RTD and Float SW) N/A 92 Days 24 M 2 Turbine Stop Valve Closure N/A 92 Days 24 M 4 Turbine Control Valve Fast Closure (oil N/A 92 Days 24 M pressure low)

Reactor Mode Switch Shutdown Position N/A 24 M N/A I Manual Scram N/A 92 Days N/A I Scram Air Header Pressure Low N/A 184 Days 24 M 2 IRM

• Neutron Flux High 7 Days 92 Days 3 e Inoperative 7 Days IN/A 1_3 W = Weekly - Q = Quarterly - M = Monthly

• R = Refueling Outage

• WR = Weekly During Refueling Outage Page 47

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - RPS Instrumentation Configuration Data H. RPS Surveillance Test Procedures

1. The following components are all tested as part of an individual channel functional test:

(Reference 8)

a. Individual channel sensor(s), e.g., transmitters and trip units, switches, flux or radiation sensors.

b. Associated logic relay(s)

c. Associated scam contactors List any plant specific differences from the above.

RESPONSE

Transmitters are calibrated once per fuel cycle. The trip unit's setpoints are verified monthly and calibrated if outside bounds (1-SR-3.3.1.1.9(TRMA-H)).

2. When an individual sensor channel is in test or repair, is associated logic channel tripped or is the sensor channel jumpered? State which of two conditions applies to your plant. If any other condition exists in your plant, describe. Reference 8.

RESPONSE

The channel is not tripped prior to the test, or jumpered. The test will trip the channel to verify proper functioning.

3. For those plants which do not place individual channels in a tripped condition during test or repair, it is assumed in the GE analysis that only the individual sensor and associated logic relay is placed in an inoperable condition during test or repair of the individual channel. If this assumption is not true for your plant, list the components (from sensor to scram contactors) which are placed in inoperable condition during test or repair (Reference 8).

RESPONSE

This assumption is true for BFNP-Unit 1.

4. The following number of individual scram contactor actuations are assumed in the GE analyses for each channel functional test: Reference 8.

a. APRM channel functional tests 2 actuations per scram contactor pair in each trip logic channel.

b. MSIV closure channel functional tests 4 actuations per scram contactor pair in each trip logic channel.

Page 48

Tennessee Valley Authority Browns Ferry Nuclear Plant - Unit 1 Section II - RPS Instrumentation Configuration Data H. RPS Surveillance Test Procedures

c. Other channel functional tests 1 actuation per scram contactor pair in each trip logic channel.

List any differences from the above for your specific plant.

RESPONSE

Turbine Stop Valve Functional Tests - 2 actuations

5. Do plant procedures allow simultaneous inoperable conditions (failed condition) of diverse sensors in a given logic channel?

RESPONSE

Yes, provided the associated RPS logic channel or the affected instrument channels are placed in the tripped condition.

I. Summary The Unit 1 RPS configuration is the samne as the Unit 3 RPS configuration.

Page 49

BROWNS FERRY NUCLEAR PLANT Unit 1 Comparison to Unit 3 Unit Differences ECCS INSTRUMENTATION Differences Based on Comparison of Unit 1 & Unit 3:

Results of Review of ECCS-RHR (Residual Heat Removal) Instrumentation Design Criteria Document BFN-50-7074, R17

1. R-R logic circuitry provisions in Ul to initiate U2 ECCS Preferred Pump Logic; nothing in U3 because U4 does not exist.

2. For a LOCA with normal power available in either Ut or U2, RHR logic circuitry provisions in U I to initiate U2 ECCS Preferred Pump Logic; nothing in U3 because U4 does not exist.

3- A spurious accident signal from a non-accident unit combined with a real accident signal from the other unit, the U 1/U2 ECCS Preferred Pump Logic shall generate a signal to the U1 RHR pump start logic to dedicate it to U1 and same for U2; nothing in U3 because U4 does not exist.

4. For Unit 1 RHR loop isolation, the RHR loop crosstie header isolation valve has been removed and the pipe capped per DCN 51199. A Technical Specification Change Request and Design Criteria revision are in process for this change. For Unit 2, a normally closed electrically disabled isolation valve isolates the loops. For Unit 3, either an electrically disabled isolation valve or a locked manual shutoff valve is maintained closed to provide loop isolation.

5. LPCI operation for U 1/ U2 different than U3.

6. RHR logic circuitry provisions in U1 to initiate U2 ECCS Preferred Pump Logic on RV level 1 or high Drywell pressure with low RV pressure.

7. Core spray logic circuitry provisions in Ul to initiate U2 ECCS Preferred Pump Logic to trip running RHR pumps and to divisionally assign RHR pumps so that Div. 1 to U 1 and Div. II to U2.

8. For a LOCA with normal power available in either Ul or U2, RHR logic circuitry provisions in U I to initiate U2 ECCS Preferred Pump Logic to trip any running RHR and Core Spray Pumps and other selected 4kv loads in the non-accident unit.

9. A spurious accident signal from a non-accident unit combined with a real accident signal from the other unit, the U 1/U2 ECCS Preferred Pump Logic shall generate a signal to the RHR pump start logic to automatically lockout the Ul Div II pumps and the U2 Div 1 pumps...;

nothing in U3 because U4 does not exist.

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10. RHR to provide a signal to the ECCS Preferred Pump Logic to trip any Core Spray pumps and to divisionally assign Core Spray pumps Div. I to Ul and Div. 11 to U2.

RESOLUTION:

The above unit differences are associated with the sharing of diesel generators between Units 1&2 and the preferred pump logic. The NRC has approved the Unit's configuration in the SER associated with TS-424.

Results of Review of ECCS-CSCS (Core Spray Cooling System) Instrumentation Design Criteria Document BFN-50-7075. R10

1. Units 1 and 2 only: A spurious accident signal from the non-accident unit combined with a real accident signal from the other unit is a design basis single failure. To compensate for this single failure, the Core Spray logic shall provide a signal to the opposite unit to initiate the Unit 1/2 ECCS Preferred Pump Logic to dedicate the Division I Core Spray and RHR pumps to Unit 1 and the Division 11 Core Spray and RHR pumps to Unit 2 (References 8.1.12, 8.1.17, and 8.1.18). This prevents unanalyzed loading of the Unit 1 and 2 4kV Shutdown Boards following a spurious accident signal with a real accident signal due to a LOCA with a loss of offsite power (see Section 3.9-1).

2. Units I and 2 only: For a LOCA with normal power available in either Units 1 or 2, the Core Spray logic circuitry shall provide a signal to the opposite non-accident unit to initiate the Unit 1/2 ECCS Preferred Pump Logic to trip any running RHR or Core Spray pumps, and other selected 4kV loads in the non-accident unit (Reference 8.1.17 and 8.1.18). This allows all four RHR and Core Spray pumps to start in the accident unit without overloading the 4kV Shutdown Buses and maintains the reliability of the normal offsite power distribution system In the event of a real accident signal combined with a spurious accident signal from the opposite unit with normal power available, the Unit 1/2 ECCS Preferred Pump Logic dedicates the Division I RHR and Core Spray pumps to Unit 1 and the Division II RHR and Core Spray pumps to Unit 2. This prevents overloading the 4kV Shutdown Buses and maintains the reliability of the normal offsite power distribution system while ensuring that at least one division of ECCS pumps are available in the unit with the real accident.

3. A control circuit shall be provided at the 4kV shutdown boards (four for units 1 and 2, four for unit 3) for its respective core spray pumps to establish control at the boards of all CS pumps (to trip and lock out the pumps) independent of the condition of the control room or spreading room circuits in accordance with reference 8.3.24 (to prevent potential overloading of these 4kV buses/diesel). (C/R BFNEEBGRR141 1)

4. Following an initiation of a Common Accident Signal from either Unit 2 or Unit 3 (which trips the diesel beakers), a second diesel breaker trip initiated for the RHR system on a "unit Page 51

priority" basis ensures that the diesel supplied buses are stripped prior to starting the ECCS pumps and other required loads.

5. Units 1 and 2 only: The ECCS Preferred Pump Logic shall provide a signal to lock the Unit 1 initiated Unit Priority Re-Trip of the Division II diesel generator breakers and the Unit 2 initiated Re-Trip of the Division I diesel generator breakers (see BFN-50-7075, section 3.9.11). This prevents unanalyzed loading of the Unit 1/2 4kV shutdown Boards and diesel generators while maintaining the minimum number of required RHR pumps for each unit.

6. Units I and 2 only: The Core Spray logic circuitry shall provide a signal to the opposite unit on RV water Level 1 on high drywell pressure concurrent with low RV pressure to initiate the Unit 1/2 ECCS Preferred Pump Logic. The ECCS Preferred Pump Logic will trip any running core Spray pump in the opposite unit. After 60 seconds, the trip signal shall be removed so that the opposite unit's operators may manually restart the Core Spray pumps when the 4 kV Shutdown Board electrical loading conditions will allow the restoration of the pUMps.

7. An ECCS inhibit key-lock switch shall be provided to block the automatic start of the Core Spray pumps and automatic opening of the Core Spray injection valves (Units 1 and 2 only).

Only the automatic initiation functions are impacted. Manual control of the Core Spray system is not affected by these key-lock switches. Units 1 and 2 only: The ECCS inhibit key-lock switch will also block the initiation of the opposite Unit's ECCS Preferred Pump Logic.

8. Units 1 and 2 only: The RHR system shall provide an initiation signal to the ECCS Preferred Pump Logic (redundant to the Core Spray initiation signal) to trip any running Core Spray pumps and divisionally assign the Core Spray pumps so that the Division I pumps are dedicated to Unit 1 and Division H pumps are dedicated to Unit 2 (see section 3.9(12)).

9. Units 1 and 2 only: The Core Spray system shall provide an initiation signal to the ECCS Preferred Pump Logic (redundant the RHR initiation signal) to trip any running RHR pumps and divisionally assign the RHR pumps so that the Division I pumps are dedicated the Unitl and the Division II pumps are dedicated to Unit 2 (Reference 8.3.3).

RESOLUTION:

The above unit differences are associated with the sharing of diesel generators between Units 1&2 and the preferred pump logic. The NRC has approved the Unit's configuration in the SER associated with TS-424.

Results of Review of ECCS-EECW (Emergency Equipment Cooling Water) Instrumentation Design Criteria Document. BFN-50-7067, R15

1. U1/U2 & U3 fed from primary and emergency EECW headers. For Ul1U2, RCW is available to the RHR HXs & Pump Room Coolers and Control Bay Chillers.

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2. RCW serves as an alternate cooling water supply for the U3 Shutdown Board Chillers and U3 H2 & 02 Analyzers/Panels.

3. The EECW serves as cooling water supply to the U 1/U2 Control Bay emergency condensing unit.

4. U1/U2 Emergency Cooling Unit is valved in and out of service if the U1/U2 Chillers are out of service and valved out. U3 does not have these provisions.

5. U 1 and U3 have different sources of Class lE power to their components. For example, the 480v Reactor MOV Board supplies power to sectionalizing valves in the reactor and U3 DG buildings. U 1 receives power from the 480v Diesel Auxiliary Board.

6. Piping from the two loop headers are muted differently for the U1/U2 and U3 DG buildings.

RESOLUTION:

The EECW system is shared among all three units and was previously evaluated by Unit 3.

Therefore, the above items have been previously deemed acceptable.

The following drawings associated with the ECCS Instrumentation have the listed differences between Unit I and Unit 3:

1-45E670-3, -5, & -11 The Unit 1 MSRV Auto Actuation logic derives its reactor pressure signal from master trip units 1-PIS-3-244A, 244B, 244C, and 244D and associated slave trip units. These loops are independent in that they have no other design functions than to provide signals for the MSRV Auto Actuation logic. This is a Unit difference from Units 2 and 3 which derive their signals from the P-3-204A, 204B, 204C, and 204D loops associated with ATWS, ARI, EHC, etc.

The independence of the loops is an enhancement that reduces the likelihood of system interface errors. The safety related features of the MSRV's designed to prevent reactor pressure from exceeding the technical specification limits has not changed by the addition of this MSRV Auto Actuation logic.

RPV LEVEL 8 FEEDWATER PUMP/MAIN TURBINE TRIP Differences Based on Comparison of Unit 1 & Unit 3:

Results of Review of RPV Level 8 Feedwater Pump/Main Turbine Trip Instrumentation The drawings associated with the RPV Level 8 Feedwater Pump/Main Turbine Trip Instrumentation were reviewed and no functional differences were found between Unit 1 and Unit 3.

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CREV INITIATION INSTRUMENTATION Differences Based on Comparison of Unit 1 & Unit 3:

Design Criteria Document BFN-50-7030A. R12

1. SR & Non-SR HVAC do not supply HVAC to the same areas for U3 & Ul:

a. Computer Room is SR, while Ul Computer Room is not

b. SR HVAC to U3 Shutdown Board in DG Bldg.

2. The Chilled Water systems between Ul and U3 differ.

c. Ul MCR AHUs have non-SR cooling coils served by a single cooling water condensing unit.

d. Flow switches provided with U3 water chiller. U1 abandoned in place.

3. U1 MCR AHUs operation and chilled water interconnections not identical to U3.

e. U1/U2 standby AHU cooled by U3 chilled water

f. Ul1U2 standby AHUs automatically switch on loss of power, U3 assuned to only have one (1) AHU.

4- U3 water chillers and condensing units receive cooling water from EECW. Raw Cooling Water supplies U1 direct expansion refrigerant condensing units w/U3 backup.

5. U 1 250v battery vent system furnishes air to control H2 concentrations.

g. UI&U2 250v Battery Room downgraded to non-SR.

RESOLUTION:

Since Unit I and Unit 2 have a shared control room, the above items were resolved during the Unit 3 evaluation and are therefore, not a concern.

END-OF-CYCLE RPT & ATWS RPT INSTRUMENTATION Differences Based on Comparison of Unit 1 & Unit 3:

Results of Review of RWRS (Reactor Water Recirculation System) & RFCS (Recirculation Flow Control System) Instrumentation Design Criteria Document BFN-50-7068. Ru1 Pagre 54

1. Ul Recirculation Pumps are constant speed pumps and U3 and U2 have variable frequency drives.

a. Controls associated with each should be physically different as will be the wiring.

RESOLUTION:

DCN 51219 will be installing variable frequency drives in Unit 1.

CONTAINMENT ISOLATION INSTRUMENTATION Differences Based on Comparison of Unit 1 & Unit 3:

Results of Review of Containment Isolation Instrumentation The following drawings associated with the Containment Isolation Instrumentation have the listed differences between Unit 1 and Unit 3:

1-730E927-10, & -11 The Containment Isolation Status System (CISS) has been designed as a non-safety related system for Unit 1 with class- lE isolation for the safety related system interfaces. Units 2 and 3 CISS systems were designed as safety related. The differences in the Unit 1 CISS are due to the safety related / non-safety related interfaces. The design function of the CISS remains the same as Units 2 and 3 except that valve stroke times are monitored by computer to verify stroke times for surveillances.

RPS INSTRUMENTATION Differences Based on Comparison of Unit 1 & Unit 3:

Results of Review of RPS (Reactor Protective System) Instrumentation Desimn Criteria Document BFN-50-7099, R11

1. The RPS shall generate a reactor scram upon receipt of: (1) high SDV water level or (2) low scram discharge air header pressure trip signals. Either of these conditions will prevent effective insertion of the control rods into the active core region. Note: Not applicable to Unit 2 per DCN 50897 or Unit 3 per DCN 50729.

The RPS shall generate a reactor scram upon receipt of high SDV water level. This condition will prevent effective insertion of the control rod drives into the active core region.

Applicable to Unit 2 per DCN 50897, Unit 3 per DCN 50729.

2. The NTSP value used for the control air header low pressure scram shall be selected low enough to avoid spurious scrams and high enough to prevent unseating the scram inlet and outlet values. Note: Not applicable to Unit 2 per DCN 50897 or Unit 3 per DCN 50729.

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3. Scram discharge low air header pressure- Not applicable to Unit 2 per DCN 50897 or Unit 3 per DCN 50729.

4. The reactor scram function for a high Scram Discharge Volume (SDV) level or low scram discharge air header pressure trip shall be bypassed by the combination of both the SDV scram bypass switch and the reactor mode switch being placed in the shutdown or refuel position. A keylock switch in proximity to the scram reset switches shall be furnished to bypass these two scram initiators as required under administrative control. Note: Not applicable to Unit 2 per DCN 50897 or Unit 3 per DCN 50729.

The reactor scram function for a high Scram Discharge Volume (SDV) level trip shall be bypassed by the combination of both the SDV scram bypass switch and the reactor mode switch being placed in the shutdown or refuel position. A key switch in proximity to the scram reset switches shall be furnished to bypass these two scram initiators as required under administrative control. Note: Applicable to Unit 2 per DCN 50897 and Unit 3 per DCN 50729.

5. The CRD system shall monitor control air header pressure to the HCU and SDV equipment.

Pressure switches shall initiate scram signal outputs to the RPS trip logic if the air pressure is too low. Note: Not applicable to Unit 2 per DCN 50897 or Unit 3 per DCN 50729.

RESOLUTION:

Unit I DCNs 51080 and 51206 will install modifications to Unit 1 that will be equivalent to the changes in Units 2&3 and the Units will then be the same.

The drawings associated with the RPS Instrumentation were reviewed and no functional differences were found between Unit 1 and Unit 3.

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