Text

Issuance of Amendments 180 & 173 Revised Technical Specification to Extend Reactor Trip System and Engineered Safety Features Actuation System Completion Times, Bypass Test Times, and Surveillance Test..
	ML083450588
Person / Time
Site:	Farley
Issue date:	01/15/2009
From:	Martin R; Plant Licensing Branch II
To:	Jerrica Johnson; Southern Nuclear Operating Co
	Feintuch K, NRR/DORL/LPL2-1, 415-3079
References
	TAC MD8135, TAC MD8136
	Download: ML083450588 (40)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 15, 2009 Mr. J. Randy Johnson Vice President - Farley Joseph M. Farley Nuclear Plant 7388 North State Highway 95 Columbia, AL 36319 SUB../ECT: JOSEPH M. FARLEY NUCLEAR PLANT, UNITS 1 AND 2 RE: ISSUANCE OF AMENDMENTS RE: REVISED TECHNICAL SPECIFICATION TO EXTEND REACTOR TRIP SYSTEM AND E!'JGINEERED SAFETY FEATURES ACTUATION SYSTEM COMPLETION TIMES, BYPASS TEST TIMES, AND SURVEILLANCE TEST INTERVALS (TAC NOS. MD8135 AND MD8136)

Dear Mr. Johnson:

The U.S. Nuclear Regulatory Commission (NRC) has issued the enclosed Amendment No. 180 to Renewed Facility Operating License No. NPF-2 and Amendment No. 173 to Renewed Facility Operating License No. NPF-8 for the Joseph M. Farley Nuclear Plant, Units 1 and 2. The amendments consist of changes to the Technical Specifications in response to your application dated December 20, 2007, (Agencywide Documents Access and Management System (ADAMS)

Accession No. ML073580502), as supplemented by letters dated September 12, 2008, (ADAMS Accession No. ML082590057), October 8, 2008, (ADAMS Accession No. ML082830009) and October 27, 2008 (ADAMS Accession No. ML083020162).

The amendments adopt changes as described in Westinghouse Commercial Atomic Power (WCAP) topical report WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS

[reactor protection system] and ESFAS [engineered safety features actuation system] Test Times and Completion Times," issued October 1998 and approved by letter dated July 15, 1998.

Implementation of the proposed changes is consistent with Technical Specification Task Force (TSTF) Traveler TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)." The NRC approved TSTF-418 by letter dated April 2, 2003.

In addition, the amendments adopt changes as described in WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," issued March 2003, as approved by NRC letter dated December 20, 2002. Implementation of the proposed changes is consistent with TSTF Traveler TSTF-411, Revision 1, "Surveillance Test Interval Extension for Components of the Reactor Protection System (WCAP-15376)." The NRC approved TSTF-411 , Revision 1, by letter dated AUgust 30,2002. The licensee also requested additional changes not specifically included in the above topical reports. These changes were evaluated on a plant specific basis.

The licensee also proposed changes referenced to TSTF-242, Revision 1, "Increase the Time to perform a COT [Channel Operational Test] on Power Range and Intermediate Range Instruments" and TSTF-246, Revision 0, "RTS [Reactor Trip System] Instrumentation, 3.3.1 Condition F Completion Time."

J.R. Johnson -2 A copy of the related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, r;-7~fJ1~

V R~ert E. Martin, Senior Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-348 and 50-364

Enclosures:

1. Amendment No.18Qo NPF-2

2. Amendment No.17~0 NPF-8

3. Safety Evaluation cc w/encl: Distribution via ListServ

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERATING COMPANY, INC.

ALABAMA POWER COMPANY DOCKET NO. 50-348 JOSEPH M. FARLEY NUCLEAR PLANT, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 180 Renewed License No. NPF-2

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by Southern Nuclear Operating Company, Inc.

(Southern Nuclear), dated December 20, 2007, as supplemented by letters dated September 12, 2008, October 8, 2008, and October 27,2008, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications, as indicated in the attachment to this license amendment; and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-2 is hereby amended to read as follows:

-2 (2) Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No.180are hereby incorporated in the license. Southern Nuclear shall operate the facility In accordance with the Technical Specifications.

3. This license amendment is effective as of its date of issuance and shall be implemented within 90 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

!i~~f;Jrd Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance: January 15, 2009

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SOUTHERN NUCLEAR OPERATING COMPANY. INC.

ALABAMA POWER COMPANY DOCKET NO. 50-364 JOSEPH M. FARLEY NUCLEAR PLANT, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 173 Renewed License No. NPF-8

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by Southern Nuclear Operating Company, Inc.

(Southern Nuclear), dated December 20, 2007, as supplemented by letters dated September 12, 2008, October 8, 2008, and October 27, 2008, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public: and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications, as indicated in the attachment to this license amendment; and paragraph 2.C.(2) of Renewed Facility Operating License No. t\lPF-8 is hereby amended to read as follows:

-2 (2) Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No~ 7 3are hereby incorporated in the license. Southern Nuclear shall operate the facility In accordance with the Technical Specifications.

3. This license amendment is effective as of its date of issuance and shall be implemented within 90 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION j:!~f~

Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance: January 15, 2009

ATTACHMENT TO LICENSE AMENDMENT NO. 180 TO RENEWED FACILITY OPERATING LICENSE NO. I\IPF-2 DOCKET NO. 50-348, AND ATTACHMENT TO LICENSE AMENDMENT NO. 173 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-8 DOCKET NO. 50-364 Replace the following pages of the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert License Pages License Pages I\IPF-2 page 4 NPF-2 page 4 NPF-8 page 3 NPF-8 page 3 TS Pages TS Pages 3.3.1-2 3.3.1-2 3.3.1-3 3.3.1-3 3.3.1-5 3.3.1-5 3.3.1-6 3.3.1-6 3.3.1-7 3.3.1-7 3.3.1-8 3.3.1-8 3.3.1-10 3.3.1-10 3.3.1-11 3.3.1-11 3.3.1-12 3.3.1-12 3.3.1-17 3.3.1-17 3.3.1-18 3.3.1-18 3.3.1-19 3.3.1-19 3.3.2-2 3.3.2-2 3.3.2-3 3.3.2-3 3.3.2-4 3.3.2-4 3.3.2-5 3.3.2-5 3.3.2-6 3.3.2-6 3.3.6-3 3.3.6-3 3.3.7-3 3.3.7-3 3.3.8-3 3.3.8-3

-4 (2) Technical Specifications The Technical Soecifications contained in Appendix A, as revised through Amendment No 180, are hereby incorporated in the renewed license.

Southern Nuclear snail operate the facility in accordance with the Technical Specifications. '

(3) Additional Conditions The matters specified in the following conditions shall be completed to the satisfaction of the Commission within the stated time periods .

following the issuance of the renewed license or within the operational restrictions indicated. The removal of these conditions shall be made by .

an amendment to the renewed license supported by a favorable . .

evaluation by the Commission.

. a. Southern Nuclear shall not operate the reactor in Operational Modes 1 and 2 with less than three reactor coolant pumps in operation.. .

b. Deleted per Amendment 13

c. Deleted per Amendment 2

d. Deleted per Amendment 2

e. Deleted per Amendment 152 Deleted per Amendment 2

1. Deleted per Amendment 158 . '.'

g. Southern Nuclear shall maintain a secondary water chemistry .

monitoring program to Inhibit steam generator tube degration.

This program shall include: .

1) Identification of a sampling schedule for the critical parameters and control points for these parameters;

2) Identification of the procedures used to quantify parameters that are critical to control points;

3) Identification of process sampling points;

4) A procedure for the recording and management of data; Farley - Unit 1 Renewed License No. NPF-2 Amendment No.180

'3 (2) Alabama Power Company, pursuant to Section 10~ of the Act and 10 CFA Part 50, "Licensing of Production and Utilization Facilities," to possess but not operate the facility at the designated location in Houston County, Alabama In accordance with te procedures and limitations set forth in this renewed licenSe.

(3) Southern Nuclear, pursuant to the Act and 10 CFA Part 70, to receive, possess and use at any time special nuclear material as reactor fuel,' in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (4) Southern Nuclear, pursuant to the Act and 10 CFR Parts 30,40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup,

. sealed sources for reactor lnstrumentanon and'radiation'monitoring ,

equipment calibration, andas fission detectors in amounts as required; (5) Southern Nuclear, pursuant to the Act and 10 CFR Parts 30,40 and 70, to receive. possess and use in amounts as required any byproduct, .

source or special nuclear material without 'restriction to chemical or' physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) Southern Nuclear, pursuant to the Act and 10 CFA Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may beproduced by the operation of the facility, C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commissions's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) , Maximum Power Level Southern Nuclear is authorized to operate the facility at reactor core power levels not in excess of 2775 megawatts thermal.

(2) Technical SPecifications The' Technical Specifications contained in Appendix A, 85 revised through Amendment No.173 " are hereby incorporated in the renewed license.

Southern Nuclear snail operate the facility in accordance with the' Technical Specifications.

Farley - Unit 2 Renewed License No. NPF-8'

. Amendment No. 173

RTS Instrumentation 3.3.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. One channel or train C.1 Restore channel or train 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable. to OPERABLE status.

OR C.2 Open RTBs. 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months D. One Power Range Neutron --------------------NOTE---------------

Flux channel inoperable. The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing and setpoint adjustment of other channels.

D.1.1 Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months AND D.1.2 Reduce THERMAL 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months POWER to s 75% RTP.

OR D.2.1 Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months AND (continued)

Farley Units 1 and 2 3.3.1-2 Amendment NO.180 (Unit 1)

Amendment No.173 (Unit 2)

RTS Instrumentation 3.3.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. (continued) D.2.2 -----------NOTE-----------

Only required to be performed when the Power Range Neutron Flux input to QPTR is inoperable.

Perform SR 3.2.4.2. Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR D.3 Be in MODE 3. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months E, One channel inoperable. ------------------NOTE-----------------

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

E,1 Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR E,2 Be in MODE 3. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months F. THERMAL POWER> P-6 F.1 Reduce THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and < P-10, one POWER to < P-6.

Intermediate Range Neutron Flux channel OR inoperable.

F.2 Increase THERMAL 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months POWER to > P-10.

Farley Units 1 and 2 3.3.1-3 Amendment No1.80 (Unit 1)

Amendment No173 (Unit 2)

RTS Instrumentation 3.3.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME L. Required Source Range L.1 Suspend operations Immediately Neutron Flux channel involving positive inoperable. reactivity additions.

AND L.2 Close unborated water 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months source isolation valves.

AND L.3 Perform SR 3.1.1.1. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter M. One channel inoperable. -----------------NOTE------------------

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

M.1 Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR M.2 Reduce THERMAL 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months POWER to < P-7.

Farley Units 1 and 2 3.3.1-5 Amendment No. 180(Unit 1)

Amendment No. 173(Unit 2)

RTS Instrumentation 3.3.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME N. One Reactor Coolant N.1 Restore channel to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Pump Breaker Position OPERABLE status.

(Single Loop) channel inoperable. OR N.2 Reduce THERMAL 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months POWER to <: peS.

O. One Reactor Coolant 0.1 Place channel in trip. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Pump Breaker Position (Two Loops) channel OR inoperable.

0.2 Reduce THERMAL 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months POWER to <: P-7.

P. One Low Auto Stop Oil ------------------NOTE-----------------

Pressure channel The inoperable channel may be inoperable. bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

P.1 Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR P.2 Reduce THERMAL 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months POWER to <: P-9.

Q. One, two, or three Turbine Q.1 Place channel(s) in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Throttle Valve Closure channel(s) inoperable. OR Q.2 Reduce THERMAL 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months POWER to <: P-9.

Farley Units 1 and 2 3.3.1-6 Amendment NO.180 (Unit 1)

Amendment No.173 (Unit 2)

RTS Instrumentation 3.3.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME R. One train inoperable. -----.------------NOTE---------------***

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillancetesting provided the other train is OPERABLE.

R.1 Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR R.2 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months S. One RTB train inoperable. ----------------NOTE---------*****_**_*

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing, provided the other train is OPERABLE.

S.1 Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR S.2 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months T. One or more channels T.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. required state for existing unit conditions.

OR T.2 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months Farley Units 1 and 2 3.3.1-7 Amendment No.180 (Unit 1)

Amendment No.1? 3 (Unit 2)

RTS Instrumentation 3.3.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME U. One or more channels U.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. required state for existing unit conditions.

OR U.2 Be in MODE 2. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months V. One trip mechanism --------*.--.---NOTE.-----------------

inoperable for one RTB. One RTB may be bypassed for maintenance on an undervoltage or shunt trip mechanism, provided the other RTB train is OPERABLE.

V.1 Restore inoperable trip 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months mechanism to OPERABLE status.

OR 54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months V.2 Be in MODE 3.

W. Two RTS trains inoperable. W.1 Enter LCO 3.0.3. Immediately Farley Units 1 and 2 3.3.1-8 Amendment NO.180 (Unit 1)

Amendment NO'I ?3 (Unit 2)

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.4 ----------------------------NOTE-------------------------_**---

This Surveillance must be performed on the reactor trip bypass breaker prior to placing the bypass breaker in service.

Perform TADOT. 62 days on a STAGGERED TEST BASIS SR 3.3.1.5 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.1.6 Perform TADOT. 184 days SR 3.3.1.7 ----------*-----*-----------NOTE-------*****-----------------

Not required to be performed for source range instrumentation prior to entering MODE 3 from MODE 2 until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after entry into MODE 3.

Perform COT. 184 days Farley Units 1 and 2 3.3.1-10 Amendment NO'180 (Unit 1)

Amendment NO'l 73 (Unit 2)

RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.8 -----------------------------NOTE--------------------------------

This Surveillance shall include verification that interlocks P-6 and P-10 are in their required state for existing unit conditions.

Perform COT. --------NOTE-------

Only required when not performed within previous 184 days Prior to reactor startup Four hours after reducing power below P-6 for source range instrumentation Twelve hours after reducing power below P-10 for power range and intermediate range instrumentation Every 184 days thereafter Farley Units 1 and 2 3.3.1-11 Amendment No' I80 (Unit 1)

Amendment NO'173 (Unit 2)

RTS Instrumentation 3.3.1 SURVEI LLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.9 ---*------*---*-*********---NOTES----------------------.--.---

1. Neutron detectors are excluded from the calibration.

2. Not required to be performed until 7 days after THERMAL POWER is ~ 50% RTP.

Calibrate excore channels to agree with incore 18 months detector measurements.

SR 3.3.1.10 *-------------------*---------NOTES----*------------*-._----.---

1. Neutron detectors are excluded from CHANNEL CALIBRATION.

2. This Surveillance shall include verification that the time constants are adjusted to the prescribed values.

Perform CHANNEL CALIBRATION. 18 months SR 3.3.1.11 Perform COT. 18 months AND

NOTE*---*

Only required when not performed within previous 184 days.

Prior to reactor startup Farley Units 1 and 2 3.3.1-12 Amendment No. 180 (Unit 1)

Amendment No. 173 (Unit 2)

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

11. Reactor Coolant Pump (RCP)

Breaker Position 1(g)

a. Single Loop 1 per RCP N SR 3.3.1.12 NA NA 1(h)

b. Two Loops 1 per RCP 0 SR3.3.1.12 NA NA 1(1)

12. Undervoltage 3 M SR 3.3.1.6 ~ 2640 V ~2680V RCPs SR 3.3.1.10 1(1)

13. Underfrequency 3 M SR 3.3.1.6 ~56.9Hz ~57Hz RCPs SR 3.3.1.10

14. Steam 1,2 3perSG E SR 3.3.1.1 ~27.6% ~28%

Generator (SG) SR 3.3.1.7 Water Level- SR 3.3.1.10 Low Low SR 3.3.1.14 (1) Above the P-7 (Low Power Reactor Trips Block) interlock.

(g) Above the P*8 (Power Range Neutron Rux) interlock.

(h) Above the P-7 (Low Power Reactor Trips Block) interlock and below the P-8 (Power Range Neutron Flux) interlock.

Farley Units 1 and 2 3.3.1-17 Amendment NOl80 (Unit 1)

Amendment NO'173 (Unit 2)

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 5 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALLIE SETPOINT

15. Turbine Trip

a. Low Auto Stop 1 (i) 3 P SR 3.3.1.10 ~43 psig ~ 45 psig Oil Pressure SR 3.3.1.13

b. Turbine Throttle 1 (i) 4 Q SR3.3.1.10 NA NA Valve Closure SR3.3.1.13

16. Safety Injection (51) 1,2 2 trains R SR3.3.1.12 NA NA Input from Engineered Safety Feature Actuation System (ESFAS)

17. ReactorTrlp System Interlocks

a. Intennediate 2 (d) 2 T SR 3.3.1.10 ~ 6E-11 amp ~ 1E-10 Range Neutron SR 3.3.1.11 amp Flux, P-6

b. Low Power 1 per train U NA NA NA Reactor Trips Block, P-7

c. Power Range 4 U SR 3.3.1.10 SR 3.3.1.11 s30.4%RTP s30%RTP I Neutron Flux, p*e

d. Power Range 4 U SR 3.3.1.10 S; 50.4% RTP S;50% RTP I Neutron Flux, SR 3.3.1.11 P-9

e. Power Range Neutron Flux, 1,2 4 T SR 3.3.1.10 SR 3.3.1.11

~7.6%

and RTP ~8% RTP and I

P-10 S; 10.4% RTP :S 10% RTP

f. Turbine Impulse 2 U SA 3.3.1.1 s 11% s10%

Pressure, P-13 SA 3.3.1.10 turbine turbine SA 3.3.1.11 power power (d) Below the P-6 (Intermediate Range Neutron Flux) interlocks.

(I) Above the p.g (Power Range Neutron Flux) interlock.

Farley Units 1 and 2 3.3.1-18 Amendment No. 180(Unit 1)

Amendment No. 173 (Unit 2)

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 6 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR FUNCTION OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS CONDITIONS SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE TRIP SETPOINT I

18. Reactor Trip 1,2 2 trains S,W SR3.3.1.4 NA NA Breakers Ul 3 (a) , 4 (a)

5 (a) 2 trains C,W SR 3.3.1.4 NA NA

19. Reactor Trip 1,2 1 each per V SR 3.3.1.4 NA NA Breaker RTB Undervoltage and 3 (a) , 4 (a) , 5 (a) C SR 3.3.1.4 NA NA Shunt Trip 1 each per Mechanisms RTB

20. Automatic Trip 1,2 2 trains R,W SA 3.3.1.5 NA NA Logic 3 (a)

4 (a) , 5 (a) 2 trains C,W SR 3.3.1.5 NA NA (a) With RTBs closed and Rod Control System capable of rod withdrawal.

m Including any reactor trip bypass breaker that Is racked in and closed for bypassing an RTB.

Farley Units 1 and 2 3.3.1-19 Amendment NO.180 (Unit 1)

Amendment NO'173 (Unit 2)

ESFAS Instrumentation 3.3.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. One train inoperable. C.1 -------------NOTE----------

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR C.2.1 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months AND C.2.2 Be in MODES. 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months D. One channel inoperable. D.1 -------------NOTE----------

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR D.2.1 Be in MODE 3. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months AND D.2.2 Be in MODE 4. 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months Farley Units 1 and 2 3.3.2-2 Amendment Nof9~ (Unit 1)

Amendment No. (Unit 2)

ESFAS Instrumentation 3.3.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. One Containment E.1 ********---NOTE--*--*----*-

Pressure channel One additional channel inoperable. may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing.

Place channel in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months bypass.

OR E.2.1 Be in MODE 3. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months AND E.2.2 Be in MODE 4. 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months F. One channel or train F.1 Restore channel or train 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months inoperable. to OPERABLE status.

OR F.2.1 Be in MODE 3. 54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months AND F.2.2 Be in MODE 4. 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months Farley Units 1 and 2 3.3.2-3 Amendment No.180(Unit 1)

Amendment NO.17 3 (Unit 2)

ESFAS Instrumentation 3.3.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G. One train inoperable. G.1 ------------NOTE-----------

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR G.2.1 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months AND G.2.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months H. One train inoperable. H.1 ------------NOTE-----------

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing provided the other train is OPERABLE.

Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR H.2 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months Farley Units 1 and 2 3.3.2-4 Amendment Nq*~80 (Unit 1)

Amendment No. 173(Unit 2)

ESFAS Instrumentation 3.3.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME I. One channel inoperable. 1.1 -----------NOTE------------

The inoperable channel may be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels.

Place channel in trip. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OR 1.2 Be in MODE 3. 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months J. One or more Main J.1 Restore channel(s) to Prior to next required Feedwater Pump trip OPERABLE status. TADOT channels inoperable on one or more Main Feedwater Pumps.

K. Two channels inoperable. K.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required state for existing unit condition.

OR K.2.1 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months AND K.2.2 Be in MODE 4. 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months L. One train inoperable. L.1 Verify interlock is in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required state for existing unit condition.

OR (continued)

Farley Units 1 and 2 3.3.2-5 Amendment NOJ.80 (Unit 1)

Amendment No173 (Unit 2)

ESFAS Instrumentation 3.3.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME L. (continued) L.2 ------------NOTE----------

One train may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for Surveillance testing, provided the other train is OPERABLE.

Restore train to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

OR L.3.1 Be in MODE 3. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months AND L.3.2 Be in MODE 5 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months SURVEILLANCE REQUIREMENTS

NOTE--------------------------------------------------------

Refer to Table 3.3.2-1 to determine which SRs apply for each ESFAS Function.

SURVEILLANCE FREQUENCY SR 3.3.2.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.2.2 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.3 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.2.4 Perform COT. 184 days SR 3.3.2.5 Perform TADOT. 184 days Farley Units 1 and 2 3.3.2-6 Amendment No. 180(Unit 1)

Amendment No. 173(Unit 2)

Containment Purge and Exhaust Isolation Instrumentation 3.3.6 SURVEILLANCE REQUIREMENTS

N()TE--------------------------------------------------------

Refer to Table 3.3.6-1 to determine which SRs apply for each Containment Purge and Exhaust Isolation Function.

SURVEILLANCE FREQUENCY SR 3.3.6.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.2 Perform ACTUATI()N L()GIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.6.3 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.6.4 Perform C()T. 92 days SR 3.3.6.5 Perform SLAVE RELAY TEST. 18 months SR 3.3.6.6 --------------------------------N()TE------------------._---------

Verification of setpoint is not required.

Perform TAD()T. 18 months SR 3.3.6.7 Perform CHANNEL CALIBRATI()N. 18 months SR 3.3.6.8 Verify ESF RESP()NSE TIME within limit. 18 months on a STAGGERED TEST BASIS Farley Units 1 and 2 3.3.6-3 Amendment No.180 (Unit 1)

Amendment No.173 (Unit 2)

CREFS Actuation Instrumentation 3.3.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.7.3 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.7.4 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.7.5 Perform SLAVE RELAY TEST. 18 months SR 3.3.7.6 ----------------------------NOTE--------------------------------

Verification of setpoint is not required.

Perform TADOT. 18 months SR 3.3.7.7 Perform CHANNEL CALIBRATION. 18 months Farley Units 1 and 2 3.3.7-3 Amendment No,180 (Unit 1)

Amendment No). 73 (Unit 2)

PRF Actuation Instrumentation 3.3.8 SURVEILLANCE REQUIREMENTS

NOTE-------------------------------------------------------------

Refer to Table 3.3.8-1 to determine which SRs apply for each PRF Actuation Function.

SURVEILLANCE FREQUENCY SR 3.3.8.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.8.2 Perform COT. 92 days SR 3.3.8.3 Perform ACTUATION LOGIC TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.8.4 Perform MASTER RELAY TEST. 92 days on a STAGGERED TEST BASIS SR 3.3.8.5 Perform SLAVE RELAY TEST. 18 months SR 3.3.8.6 ------------------------------NOTE-------------------------------

Verification of setpoint is not required.

Perform TADOT. 18 months SR 3.3.8.7 Perform CHANNEL CALIBRATION. 18 months Farley Units 1 and 2 3.3.8-3 Amendment No. 180 (Unit 1)

Amendment No; 173 (Unit 2)

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF I\JUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 180 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-2 AND AMENDMENT NO. 173 TO RENEWED FACILITY OPERATING LICENSE I\JO. NPF-8 SOUTHERN NUCLEAR OPERATING COMPANY, INC.

JOSEPH M. FARLEY NUCLEAR PLANT, UNITS 1 AND 2 DOCKET NOS. 50-348 AND 50-364

1.0 INTRODUCTION

By application dated December 20,2007 to the U.S. Nuclear Regulatory Commission, as supplemented by letters dated September 12, October 8, and October 27, 2008 (References 1, 2, 3 and 4, respectively), Southern Nuclear Operating Company (SNC, the licensee) submitted a License Amendment Request (LAR) requesting changes to the Technical Specifications (TSs) for Joseph M. Farley Nuclear Plant, Units 1 and 2 (FNP) in accordance with Title 10 of the Code of Federal Regulations (10 CFR), Section 50.90, "Application for Amendment of License, Construction Permit, or Early Site Permit". The supplement provided additional information that clarified the application, but did not expand the scope of the application as originally noticed and did not change the I\JRC staff original proposed no significant hazards consideration determination as published in the Federal Register on July 8, 2008 (73 FR 39056).

The licensee's proposed changes revise TS reactor trip system (RTS) and engineered safety features actuation systems (ESFAS) instrumentation completion times (CT), bypass test times, and surveillance test intervals (STI). The RTS is designed to initiate a reactor trip when the system exceeds limits to permissible operation. The ESFAS is designed to actuate emergency systems for accidents that challenge the normal control and heat removal systems.

The ESFAS instrumentation includes sensors, power supplies, signal processing, and bistable outputs and typically consists of three or four channels. Instrumentation signals (i.e., bistable outputs) feed relays that input into the logic portion of the ESFAS. The logic (i.e., logic cabinets) includes two redundant and independent logic blocks consisting of two trains (A and B) of logic where the input coincidence for various trip functions is determined. Either logic train initiates the ESFAS function through output cards driving master and slave relays.

-2 The RTS is comprised of instrumentation including sensors, power supplies, signal processing, comparators (bistables), input relays, logic circuits, and output cards. The RTS includes actuation paths from the Train A and Train B logic to the reactor trip breakers (RTB). Normally, an RTB receives its signal from its associated logic train. The system has bypass breakers for when a breaker is out of service. In this configuration, the bypass breaker is associated with the logic train of the operable RTB. The RTS utilizes two normally closed RTBs and two normally open bypass breakers. Train A logic actuates RTB A, and Train B logic actuates RTB B. Opening of either RTB will disconnect power from the control rods, causing a reactor trip.

FNP utilizes the solid state protection system (SSPS) for the logic portion of the RTS/ESFAS.

The licensee stated that proposed STI, CT and bypass test times will allow additional time to perform maintenance and test activities, enhance safety, provide additional operational flexibility, and reduce the potential for forced outages related to compliance with RTS and ESFAS instrumentation TS.

2.0 REGULATORY EVALUATION

The proposed changes are based on approved topical reports Westinghouse Commercial Atomic Power (WCAP) WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the [Reactor Protection System] RPS and ESFAS Test Times and Completion Times," and WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times." The licensee amendment request (LAR) implements WCAP-14333 and WCAP-15376 in accordance with Technical Specification Task Force (TSTF) TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)," approved by NRC letter dated April 2, 2003 and TSTF-411, Revision 1, "Surveillance Test Interval Extension for Components of the Reactor Protection System (WCAP-15376)," approved by NRC letter dated August 30, 2002. The licensee also requested additional changes not specifically addressed by the topical reports. These changes were evaluated on a plant specific basis by the licensee.

The Pressurized-Water Reactor Owners Group (PWROG) submitted WCAP-14333 in May 1995 to the NRC staff for review. WCAP-14333 was approved by the NRC staff by letter dated July 15, 1998. The purpose of WCAP-14333 was to provide justification for additional TS CT and bypass test time relaxations beyond those originally approved by the WCAP-10271 series of reports and supplements previously adopted into NUREG-1431, "Standard Technical Specifications Westinghouse Plants," Revision 0, issued September 1992. The WCAP-14333 changes are shown below:

Increase the NUREG-1431 bypass test times and CTs for both the solid-state and relay protection system (RTS and ESFAS) designs for the analog channels from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and increase the bypass test time from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for the logic cabinets.

Increase the CT from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for master relays, and slave relays. When the logic cabinet and reactor trip breaker (RTB) both cause their train to be inoperable when in test or maintenance, allow bypassing of the RTB for the period of time equivalent to the bypass test time for the logic cabinets, provided that both are tested at the same time and the plant design is such that both the RTB and the logic cabinet cause their associated electrical trains to be inoperable during test or maintenance.

-3 Following the approval of WCAP-14333, the PWROG submitted WCAP-15376 to the NRC staff on November 8,2000, which the NRC staff approved by letter dated December 20,2002.

WCAP-15376 specifically evaluated the analog channels, logic cabinets, master relays, and RTBs.

WCAP-15376 evaluated both the SSPS and the relay protection system. WCAP-15376 provided justification for the following additional TS relaxations:

An additional extension of the STI for components of the RTS and ESFAS beyond those previously approved in WCAP-1 0271-P-A.

An extension of the STI, CT, and bypass test times for the RTBs.

2.1 Regulatory Evaluation Pertaining To Probabilistic Risk Assessment (PRA) Issues 2.1.1 Applicable Regulations Although 10 CFR 50.36 does not list specific TS requirements, implicit within this rule are the requirements that action be taken when a limiting condition for operation (LCO) is not being met and that the surveillance requirements (SRs), bypass test times, and CTs specified in the TSs be based on reasonable protection of the public health and safety. Therefore, the NRC staff must be able to conclude that there is reasonable assurance that the RTS/ESFAS functions affected by these proposed TS changes will perform their required safety functions in accordance with the design-basis accidents described in Chapter 15 of the licensee's final safety analysis report, based on the proposed SRs, bypass test times, and CTs.

The Maintenance Rule, 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," requires licensees to monitor the performance or condition of SSCs against licensee-established goals in a manner sufficient to provide reasonable assurance that SSCs are capable of fulfilling their intended functions. In addition, 10 CFR 50.65(a)(4), as it relates to the proposed surveillance, bypass test times, and CTs, requires the assessment and management of the increase in risk that may result from the proposed maintenance activity. Enclosure 1A, Section 4.2, of the licensee's submittal references additional regulatory requirements and guidance applicable to the licensee's implementation of WCAP-14333 and WCAP-15376.

2.1.2 Applicable Regulatory Criteria/Guidelines RG 1.174, "An Approach for using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," issued November 2002, describes a risk-informed approach with associated acceptance guidelines for licensees to assess the nature and impact of proposed permanent licensing basis changes by considering engineering issues and applying risk insights.

RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," issued August 1998, describes an acceptable risk-informed approach and additional acceptance guidance geared toward the assessment of proposed permanent TS CT changes. RG 1.177 identifies a three-tiered approach for the licensee's evaluation of the risk associated with a proposed CT TS change, as discussed below:

-4

Tier 1 assesses the risk impact of the proposed change in accordance with acceptance guidelines consistent with the Commission's Safety Goal Policy Statement, as documented in RGs 1.174 and 1.177. The first tier assesses the impact on operational plant risk based on the change in core damage frequency (LlCDF) and change in large early release frequency (LlLERF). It also evaluates plant risk while equipment covered by the proposed CT is out of service, as represented by incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP).

Tier 1 also addresses probabilistic risk assessment (PRA) quality, including the technical adequacy of the licensee's plant-specific PRA for the subject application. Tier 1 also considers the cumulative risk of the present TS change in light of past (related) applications or additional applications under review along with uncertainty/sensitivity analysis with respect to the assumptions related to the proposed TS change.

Tier 2 identifies and evaluates any potential risk-significant plant equipment outage configurations that could result if equipment, in addition to that associated with the proposed LAR, is taken out of service simultaneously, or if other risk-signi"ficant operational factors, such as concurrent system or equipment testing, are also involved.

The purpose of this evaluation is to ensure that appropriate restrictions are in place such that risk-significant plant equipment outage configurations will not occur when equipment associated with the proposed CT is implemented.

Tier 3 addresses the licensee's overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and that the licensee takes appropriate compensatory measures to avoid risk-significant configurations that may not have been considered during the Tier 2 evaluation. Compared with Tier 2, Tier 3 provides additional coverage to ensure that the licensee identifies risk-significant plant equipment outage configurations in a timely manner and appropriately evaluates the risk impact of out-of-service equipment before performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by the Maintenance Rule, 10 CFR 50.65(a)(4), subject to the guidance provided in RG 1.177, Section 2.3.7.1, and the adequacy of the licensee's program and PRA model for this application. RG 1.182, "Assessing and Managing Risk Before maintenance Activities at Nuclear Power Plant,"

endorses NUMARC 93-01, Section 11 which also provides guidance on the implementation of 10 CFR 50.65(a)(4).

RGs 1.174 and 1.177 also describe acceptable implementation strategies and performance monitoring plans to help ensure that the assumptions and analyses used to support the proposed TS changes will remain valid. The implementation and monitoring program guidance of Section 2.3 of Regulatory Guide (RG) 1.174 and Section 3 of RG 1.177 states that monitoring performed in conformance with the Maintenance Rule can be used when it is sufficient for the SSCs affected by the risk-informed application.

Section 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance," of NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants" (hereafter referred to as the SRP), provides general guidance for evaluating the technical basis for proposed risk-informed changes. SRP Section 19.2 states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following five key principles:

-5 (1) The proposed change meets the current regulations, unless it explicitly relates to a requested exemption or rule change.

(2) The proposed change is consistent with the defense-in-depth philosophy.

(3) The proposed change maintains sufficient safety margins.

(4) When proposed changes increase CDF or risk, the increase(s) should be small and consistent with the intent of the Commission's Safety Goal Policy Statement.

(5) The licensee should monitor the impact of the proposed change using performance measurement strategies.

SRP Section 19.1, "Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," addresses the technical adequacy of a baseline PRA used by a licensee to support license amendments for an operating reactor. SRP Section 16.1, "Risk-Informed Decision Making: Technical Specifications," provides more specific guidance related to risk-informed TS changes, including STI, bypass test times, and CT changes as part of risk-informed decision making.

2.2 Regulatory Evaluation Pertaining To Traditional Engineering Analysis Issues As required by 10 CFR 50.36(d)(2)(ii)(C), a licensee's TSs must have LCOs for a SSC that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As required by 10 CFR 50.36(d)(3), a licensee's TS must have SRs for testing, calibration, and inspection to ensure that the necessary quality of systems and components is maintained, that facility operations remain within safety limits, and that the LCOs will be met.

As required by 10 CFR 50.55a(h)(2), protection systems must meet the requirements of Institute of Electrical and Electronics Engineers (IEEE) 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations," or IEEE 603-1991, "Criteria for Safety Systems for Nuclear Power Generating Stations," for plants with construction permits issued after January 1, 1971, but before May 13,1999. Section 4.2 of IEEE 279-1971 discusses the general functional requirement for protection systems to ensure that they satisfy the single failure criterion.

Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50 establishes the minimum requirements for the principle design criteria for the design, fabrication, construction, testing, and performance of SSCs important to safety. In this regard General Design Criterion (GDC) 13, "Instrumentation and Control," states that the licensee shall provide appropriate controls to maintain these variables and systems within prescribed operating ranges.

Furthermore, GDC 21, "Protection System Reliability and Testability," states that the design of the protection system shall provide for high functional reliability and in-service testability commensurate with the safety functions to be performed. GDC 22, "Protection System Independence," states in part that protection systems shall be designed to ensure that no single failure results in a loss of the protection function.

-6

3.0 TECHNICAL EVALUATION

3.1 Technical Evaluation-Probabilistic Risk Assessment The NRC staff reviewed the licensee's analyses in support of its proposed LAR, which are described in the submittal dated December 20, 2007, as supplemented by letters dated September 12, 2008, October 8,2008 and October 27,2008.

3.1.1 Detailed Description of the Proposed Change The following table summarizes the proposed WCAP-14333 changes, as applicable to FNP.

CT Bypass Test Time RTS/ESFAS Current Proposed Current Proposed Components (Hour) (Hour) (Hour) (Hour) 1 Analog Channels 6+6' 72+6 4 12 Logic Cabinets 6+6 24+6 4 No Change Master Relays 6+6 24+6 4 No Change Slave Relays 6+6 24+6 4 No Change Reactor Trip Breakers 6 No Change 2 No Change

1. The +6 hours is the time allowed for the specified mode change.

The following table summarizes the proposed WCAP-15376 changes, as applicable to FNP.

STI CT Bypass Test Time RTS/ESFAS Component Current Proposed Current I Proposed Current I Proposed (Month) (Month) (Hour) (Hour) (Hour) (Hour)

Logic Cabinets 2 6 No Change No Change Master Relays' 2 6 Requested Requested Analog Channels 3 6 Reactor Trip 2 4 1 24+6 2

2 4;j Breakers I I

1. Applicable to SSPS plants only

2. The +6 hours is the time allowed for the specified mode change.

3. With the implementation of WCAP-15376, the RTB bypass test time is increased to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months consistent with the logic cabinet.

The proposed changes revise FNP STls, bypass test times, and CTs for TS 3.3.1, "Reactor Trip System (RTS) Instrumentation," TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS)

Instrumentation." The licensee also proposed plant specific increased STls for TS 3.3.6, "Containment Purge and Exhaust Isolation Instrumentation, "TS 3.3.7, Control Room Emergency Filtration/Pressurization System (CREFS) Actuation Instrumentation," and TS 3.3.8, "Penetration Room Filtration (PRF) System Actuation Instrumentation" based on these functional units also using SSPS master relay and actuation logic. Enclosure 1A, Section 2.2 of the licensee's submittal lists the proposed TS changes to be implemented under WCAP-14333 and

-7 WCAP-15376. The licensee also provided TS markups in Enclosure 2 and, for information, a markup of the associated TS bases.

The licensee also identified plant specific STI and CT changes not generically evaluated by WCAP-14333, or WCAP-15376. The following TS changes were evaluated on a plant specific basis in Enclosure 1A, Section 2.2, "Proposed Changes," and Section 3.5.7, "Deviations From Approved TSTF-411 Revision 1 and TSTF-418 Revision 2" of the licensee's submittal. The affected functional units are evaluated in section 3.2.4 of this report.

3.1 .2 Review of Methodology In accordance with SRP Sections 19.1, 19.2, and 16.1, the NRC staff reviewed the FNP incorporation of WCAP-14333 and WCAP-15376 using the three-tiered approach and the five key principles of risk-informed decision-making presented in RGs 1.174 and 1.177 and the Safety Evaluation Report (SER) conditions and limitations for WCAP-14333 and WCAP-15376.

This Safety Evaluation includes an evaluation of risk impacts as well as a traditional engineering analysis 3.1.3 Key Information Used in the Review The key information used in the NRC staff review comes from Enclosures 1A and 4 of the licensee's LAR dated December 20, 2007 (Reference 1) and its three supplements (References 2,3 and 4), WCAP-14333 and WCAP-15376 NRC staff SEs (References 5 and 6), and TSTF-411 Revision 1 (Reference 8) and TSTF-418 Revision 2 (Reference 7);. The NRC staff also referred to previous SERs related to WCAP-1 0271, such as reference 9, and the licensee's individual plant examination (IPE) and individual plant examination of external events (IPEEE) assessments.

3.1.4 Comparison to Regulatory Criteria/Guidelines The following sections present the NRC staff evaluation of the licensee's proposed LAR to extend CTs and bypass test times using the three-tiered approach and the five key principles outlined in RGs 1.1 74 and 1.177.

3.1.4.1 Traditional Engineering Evaluation The traditional engineering evaluation addresses key principles 1, 2, 3, and 5 of the NRC staff philosophy of risk-informed decision-making, which concern (1 and 2) compliance with current regulations and evaluation of defense in depth, (3) evaluation of safety margins, and (5) performance measurement strategies. Key principle 4, Risk Evaluation, is addressed in Section 3.1.4.2.

Key Principles 1 and 2: Compliance with Current Regulations and Evaluations of Defense in Depth Section 3.2.3.2 of this safety evaluation (SE) provides the NRC staff evaluation of the licensee's compliance with current regulations and application of Defense in Depth.

-8 Key Principle 3: Evaluation of Safety Margins Section 3.2.3.3 of this SE provides the NRC staff evaluation of the sufficiency of the licensee's safety margins.

Key Principle 5: Performance Measurement Strategies-Implementation and Monitoring Program Section 3.1.4.3 of this SE provides the NRC staff evaluation of the licensee's implementation and monitoring program.

3.1.4.2 NRC Staff Technical Evaluation (Probabilistic Risk Assessment)

Key Principle 4: Risk Evaluation WCAP-14333 and WCAP-15376 employ a risk-informed approach to justify changes to RTS and ESFAS CTs, bypass test times, and STls. The licensee confirmed that the generic risk estimates of ~CDF, ~LERF, ICCDP, and ICLERP, were applicable to the proposed FNP TS changes and consistent with the acceptance guidance presented in RGs 1.174 and 1.177.

To determine that WCAP-14333 and WCAP-15736 are applicable to FNP, the licensee addressed the conditions and limitations of the NRC staff SERs and the implementation guidance that compares plant-specific data to the generic analysis assumptions. The evaluation compared the general baseline assumptions, including surveillance, maintenance, calibration, actuation signals, procedures, and operator actions, to confirm that the generic evaluation assumptions used in the topical reports are also applicable to FNP.

The following paragraphs discuss the NRC staff's evaluation of the licensee's response to the SE conditions and limitations of WCAP-14333 and WCAP-15376.

(Condition 1) A licensee should confirm the applicability of the WCAP-14333 and WCAP-15376 analyses for its plant.

The licensee's reference 1 submittal, Enclosure 1A, Section 3.5 including Tables 1A, 1B, 2, 3 and 4, provide the plant specific evaluation for WCAP-14333 and WCAP-15376. The licensee's evaluation included a comparison of analysis parameters and assumptions with FNP plant-specific data. The comparison included actuation signals, component test and maintenance intervals, procedures, operator action, anticipated transient without scram (ATWS) and plant specific baseline CDF and LERF values. Plant specific component failure probabilities associated with the SSPS (driver cards and master relays) were also evaluated and found to be applicable to WCAP-15376. As stated in the NRC staff SE for WCAP-15376, the estimates for LERF were based on the reference plant having a large dry containment and the assumption that the only contributions to LERF would be from containment bypass or core damage events with the containment not isolated. Both FNP units utilize a large dry containment. The FNP PRA LERF contribution includes failure of containment isolation, steam generator tube rupture events, and containment bypass from intersystem loss of coolant accidents (ISLOCA), consistent with WCAP-15376 assumptions.

In the NRC staff SE for WCAP-15376 the NRC staff recognized the similarity between RTS and ESFAS systems, design, function, and initiating event frequency but noted the unavailability of the

-9 RTS showed a wide range of estimates. One example was the apparent variability in the contribution to core damage from ATWS events. The licensee confirmed that the WCAP-14333 and WCAP-15376 ATWS analysis and assumptions including ATWS contribution to CDF are applicable to FNP. The licensee's conclusion in section 3.5.1 of reference 1 was that the WCAP-14333 and WCAP-15376 analyses and results are applicable to FNP.

The I'JRC staff finds that, based on the information above and the evaluation presented in Section 3.1.4.2.1, Tier 1, of this SE, Condition 1 is satisfied for FNP.

Condition 2 WCAP-14333 and WCAP-15376 - The licensee should address the Tier 2 and Tier 3 analyses, including CRMP insights, by confirming that these insights are incorporated into its decision making process before taking equipment out of service.

The NRC staff finds that, based on the evaluation presented in Section 3.1.4.2.2 (Tier 2) and Section 3.1.4.2.3 (Tier 3) of this SE, the licensee addressed both Tier 2 and Tier 3 risk significant configurations and confirmed that these insights are incorporated into the FNP CRMP. Therefore, the NRC staff considers this condition satisfied for FNP.

Condition 3. WCAP-15376 - The licensee should evaluate the risk impact of concurrent testing of one logic cabinet and associated RTB on a plant-specific basis to ensure conformance with the WCAP-15376 evaluation, including the guidance of RGs 1.174 and 1.177.

Concurrent testing of one logic cabinet and associated RTB was not originally evaluated or precluded by WCAP-15376. In response to a NRC staff RAI, the PWROG provided a generic ICCDP estimate of 3.2E-7 for the more limiting configuration of a logic cabinet and RTB out of service for 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The resulting generic estimate is within the RG 1.177 ICCDP acceptance guidance of 5.0E-7. The licensee stated that "Since this ICCDP value is based on the logic train and RTB being out of service for 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months at the same time, bypassing one logic train and associated RTB train for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for testing will also meet the Regulatory Guide 1.177 ICCDP guideline." Also, as noted in the previous discussion for Condition 1, the licensee has established the conformance of FNP to the generic WCAP-15376 analysis, as documented in Section 3.0 of the licensee's submittal. The NRC staff finds that, based on the above, the generic WCAP-15376 ICCDP estimates are expected to be applicable to the FNP plant specific case and, therefore, the NRC staff considers this condition satisfied for FNP.

Condition 4 To ensure consistency with the reference plant, the licensee should confirm that the model assumptions for human reliability in WCAP-15376 are applicable to the plant-specific configuration.

The licensee's reference 1, Table 4 submittal confirmed that the assumptions regarding human reliability used in WCAP-15376 are applicable to FNP. This review concluded that for the operator actions identified in WCAP-15376, plant procedures, training and sufficient time are available consistent with the assumptions in WCAP-15376. Based on the above, the NRC staff considers condition 4 to be satisfied.

- 10 Condition 5 For future digital upgrades with increased scope, integration, and architectural differences beyond those of Eagle 21, the NRC staff finds that the generic applicability of WCAP-15376 to a future digital system is not clear and should be considered on a plant-specific basis.

The FNP design is based on analog instrument racks and SSPS, therefore this condition is not applicable to the implementation of WCAP-15376 at FNP.

Condition 6 WCAP-15376 included an additional condition based on the PWROG response to an NRC staff RAI that committed each plant to review its plant-specific RPS and ESFAS setpoint uncertainty calculations and assumptions, including instrument drift, to determine the impact of extending the surveillance frequency of the COT from 92 days to 184 days. The licensee has performed this plant specific evaluation and its response is provided below.

Farley Response: The rack drift allowances used in the Farley-specific RTS/ESFAS setpoint uncertainty calculations are conservative values based on Westinghouse historical practices, manufacturers' specifications, and operating experience. With respect to Farley-specific setpoint calculations, evaluation of instrument channel performance data confirmed that the rack drift allowances for periodic surveillances are bounding for the proposed COT & TADOT surveillance period change from 92 to 184 days. Therefore, the Farley RTS/ESFAS setpoint uncertainty calculations continue to demonstrate the acceptability of the limiting safety system settings, and no calculation revisions are required.

With respect to actual instrumentation performance, Farley uses restrictive as-found calibration tolerances/administrative limits based on expected performance of a healthy instrument channel. Operating experience continues to demonstrate and recent evaluations confirmed that the actual rack drift magnitudes are consistent with as-found operability criteria for healthy channels. No significant adverse trends were noted. Based on historical experience, the rack instrument drift is expected to remain within the limiting as-found criteria assumptions of the existing setpoint uncertainty calculations with the proposed change to the COT & TADOT surveillance test frequency of 184 days. In addition, existing setpoint control program administrative controls ensure that corrective action is taken for multiple occurrences of excessive rack drift, which may indicate a degraded instrument channel. Therefore, no enhanced monitoring of rack performance is required.

The NRC staff concludes that the licensee has performed the evaluation addressed by this condition in the WCAP-15376 SE and that the results are acceptable. Therefore the staff considers this condition to be satisfied and finds that the changes justified in WCAP-15376 can be applied to FNP.

Based on the above, the NRC staff concludes that, with respect to the six conditions in the SE for WCAP-15376, the proposed TS changes to increase the COT and TADOT surveillance frequencies are acceptable.

3.1.4.2.1 Tier 1: Probabilistic Risk Assessment Capability and Insights

- 11 The first tier evaluates the impact of the proposed changes on plant operational risk based on the FNP implementation of WCAP-14333 and WCAP-15376. The Tier 1 NRC staff review involves (1) evaluation of the technical adequacy of the PRA and its application to the proposed changes, and (2) evaluation of the PRA results and insights based on the licensee's proposed application.

PRA Technical Adequacy WCAP-14333 and WCAP-15376 do not require specific use of the FNP PRA or plant-specific estimates of L1CDF, L1LERF, ICCDP, or ICLERP to implement either topical report. WCAP-14333 and WCAP-15376 utilized a representative PRA model for the evaluation of the CT, test bypass time, and STI extensions for Westinghouse plants. Although the WCAP-14333 and WCAP-15376 SERs accepted the use of a representative model as generally reasonable, the application of the representative model and the associated results to a specific plant introduces a degree of uncertainty because of modeling, design, and operational differences. Therefore, each licensee adopting WCAP-14333 and WCAP-15376 should confirm that the topical report analyses and results are applicable to its plant.

The licensee reviewed the scope and detail of the FNP PRA using the generic topical report implementation and analysis parameters as listed in Enclosu re 1A of the licensee's submittal to demonstrate the plant-specific applicability of the proposed CT, bypass test times, and STI changes evaluated by WCAP-14333 and WCAP-15376. The licensee confirmed the topical report actuation logic; component test, maintenance, and CTs, STI intervals; at-power maintenance; ATWS; total internal events CDF; transient events; operator actions; RTS trip actuation signals; and ESFAS actuation signals were consistent with FNP plant specific values.

Based on the cross comparison to the topical report analysis parameters and NRC staff SE conditions and limitations for WCAP-14333 and WCAP-15376, the licensee concluded that WCAP-14333 and WCAP-15376 are applicable to FNP.

The licensee also proposed changes to the FNP TS not specifically evaluated by WCAP-14333 and WCAP-15376 and therefore not within the scope of these topical reports. The licensee evaluation of these TS changes is included in Section 3.5.7 of the licensee's submittal.

Both WCAP-14333 and WCAP-15376 state that the CTs and STls evaluated under these topical reports are applicable to all the signals evaluated under WCAP-10271 and its supplements.

Previous plant specific functional units approved under WCAP-1 0271 are acceptable because the analysis performed under WCAP-14333 and WCAP-15376 is based on analysis methods used in WCAP-10271.

In addition, signals not specifically addressed under WCAP-1 0271 but found to be applicable to WCAP-10271 through previous plant specific evaluations are also applicable to WCAP-14333 and WCAP-15376. Proposed TS functional units that deviate from approved TSTF-411 Revision 1 and TSTF-418 Revision 2 are identified in Section 3.1 of this SE. The proposed TS changes are either addressed by previous implementation of WCAP-1 0271 and its related supplements at FNP, are in agreement with the stated W CAP-14333 and W CAP-15376 conditions and limitations, or the change provides consistency in implementing WCAP-14333 and WCAP-15376 with the FNP TS and plant design. Therefore, the proposed changes are also considered applicable to the analysis approach and guidance of WCAP-14333 and WCAP-15376 and are acceptable to the NRC staff.

- 12 Peer Review The Westinghouse Owners Group (WOG) peer reviewed revision 4 of the FNP PRA in 2001 with the final report issued in December 2002. The licensee provided the peer review facts and observations (F&Os) and their resolution in the LAR. Per the licensee's submittal, all level B F&Os have been resolved and either incorporated into the FI'JP Revision 7 PRA referenced for this LAR or justification provided as to why a PRA revision was not required. There were no Level A findings identified during the peer review. Therefore, the peer review F&Os and disposition are included in the PRA referenced to this LAR.

Licensee procedures require scheduled updating of the FNP PRA model. A review of the PRA is performed within 6 months of each refueling outage to identify newly completed plant modifications that impact PRA modeling. Updates of the model are performed based on this review and scheduled according to the significance of the revision. The licensee also performs a review of procedures on an annual basis to identify PRA impacts. Failure data, initiating events frequencies, and human reliability data are reviewed approximately every three years. The licensee provided the FNP revision history through Revision 7 dated July 6,2007. The PRA is treated as a calculation with both the calculation and revision schedule controlled by plant procedure.

The FNP PRA model was compared to the representative PRA model used in WCAP-14333 and WCAP-15376 to confirm the applicability of WCAP-14333 and WCAP-15376 to FNP. No plant design or operational modifications were identified that would impact the generic analysis of WCAP-14333 and WCAP-15376.

Based on the above the NRC staff concludes that the licensee has demonstrated the applicability of WCAP-14333 and WCAP-15376 to FI'JP for the proposed changes in CTs and STls. Therefore, the NRC staff concludes that the PRA is technically adequate for this application.

External Events The proposed changes will increase the unavailability of the affected structure systems or component (SSC) by increasing the CT for the analog cabinets, logic cabinets, master relays, slave relays, and RTBs. To be important for an external event, the external event must occur while the SSC is in the extended completion time.

The analysis for both WCAP-14333 and WCAP-15376 did not include external events including seismic, fire, and high winds, flood and other (HFO) external events. The NRC staff SE for WCAP-14333 qualitatively considered external events including a conservative estimate of the fire and seismic risk using a different plant PRA than used by the PWROG. The NRC staff SE for WCAP-14333 concluded that the proposed changes will have only a very small impact on external event risk. The licensee evaluated the proposed RTS and ESFAS STI, bypass test times and CTs for their potential impact on external events.

The licensee's seismic analysis is based on a seismic margins assessment (SMA) performed for the FNP Plant Examination of External Events (IPEEE). Therefore, a quantification of the seismic contribution to plant CDF is not available. The NRC staff, using a simple independent calculation with a FNP HCLPF value of 0.1g PGA, estimated a seismic CDF on the order of 2.0E-5/year for

- 13 FNP. The licensee estimated that the frequency of an earthquake greater than the FNP seismic margins assessment (SMA) review level earthquake (RLE) of 0.1g peak ground acceleration (PGA) occurring while in an extended CT to be about 2.37E-7/year. The estimate is based on the worst case contribution for the CT and on the FNP specific hazard curve (NU REG-14888, "Revised Livermore Seismic Hazard Estimate for Sixty Nine Nuclear Power Plant Sites East of the Rocky Mountains"). With an assumed conditional core damage probability of 0.1 the expected seismic contribution to the increase in risk is estimated to be in the range of 2.37E-8/year for the proposed CT. Based on the licensee's probability estimate of an earthquake greater than 0.1 g PGA during a RTS or ESFAS CT and consideration of the RLE value of 0.1 g PGA, it is expected that the seismic CDF increase due to increased WCAP-14333 and WCAP-15376 STI, bypass test times, and CTs would be very small and a negligible contributor FNP seismic risk.

The licensee performed a fire risk evaluation for FNP using the Electric Power Research Institute fire-induced vulnerability evaluation (FIVE) methodology. The licensee evaluated the potential impact of a fire on the proposed STI, bypass test times and CTs using the fire compartments identified in the IPEEE. The IPEEE estimated total CDF from "fires as 1.6E-4/year and 1.23E-4/year for FNP Units 1 and 2 respectively. The IPEEE states that no new vulnerabilities were identified. The IPEEE identifies procedure enhancements that were to be implemented by the licensee. The licensee in their RAI response verified that procedures are in place to address the fire risk identified for risk significant fire areas. Subsequent to the IPEEE, the licensee updated the IPEEE "fire contributions for signi"ficant fire areas. The revised CDF from fires is estimated as 4.98E-5/year and 5.87E-5/year for FNP Units 1 and 2 respectively. The FIVE analysis for FNP conservatively assumed components were failed by fire where cable routing was not documented.

Affected equipment included instrument air compressors A and B, containment fan coolers, containment spray systems, steam dumps, main feedwater pumps, condensate pumps and opposite unit service water and instrument air. Also the licensee indicated that modifications performed to the Unit 2 service water pumps eliminated the need for an external booster pump for the lube and cooling system. This licensee indicated that this modification should make the FNP Unit 2 fire results similar to Unit 1.

The primary fire risk noted in the IPEEE concerns the loss of offsite power or the loss of reactor coolant pump seal cooling support systems. For these sequences, the licensee credits operator action to manually trip the reactor (for loss of offsite power sequences the reactor trips on loss of power to the RTS) and to start needed equipment to mitigate core damage. Failure of actuation signals associated with the proposed CT and bypass test times would be expected to have negligible impact on the operator actions relied on to mitigate these sequences. Therefore, the impact on FNP fire risk for the proposed RTS and ESFAS instrumentation STI, CT, and bypass test times are expected to have a negligible contribution to FNP fire risk.

Although not originally reviewed under the 1975 Standard Review Plan (SRP), FNP evaluated HFO events using the progressive screening approach of NUREG-1407, "Procedure and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," issued June 1991, and GL 88-20, "Individual Plant Examination for Severe Accident Vulnerabilities," Supplement 4, dated November 23, 1988, to demonstrate that FNP conforms to the 1975 SRP criteria. The IPEEE concluded that FNP was designed to withstand high winds and conformed to the 1975 SRP criteria. External floods were also evaluated and it was also determined that FNP conformed to the 1975 SRP criteria. No significant issues were identified regarding flooding. The licensee evaluated highway, aircraft, railroad, and

- 14 barge and ship accidents. Industrial hazards were also evaluated i.e., chemical spills, chemical storage and explosions. The IPEEE also found FNP to be in conformance with the 1975 SRP criteria with regards to transportation hazards. No plant-unique external events were identified with potential severe accident vulnerability. In accordance with NUREG-1407, if a plant meets the 1975 SRP screening guidelines (i.e., If the plant is in conformance with the 1975 SRP for an external event, then it is concluded that the contribution to core damage from that external event is less than 1.0E-6/year - assuming that the conditional probability of core damage is less than 0.1) licensees can screen out HFO external events as a significant contributor to total CDF. Therefore, any risk increase from the proposed CT, bypass test time and STI changes is expected to be much less than 1.0E-6 and a negligible contribution to FNP HFO risk.

Total Risk Contribution RG 1.174, page 17, states that when the calculated increase in CDF is in the range of 1E-6 to 1E-5 (a small change) the application will be considered only if it can be reasonably shown that the total CDF is less than 1E-4/year. The NRC staff considered whether the estimated external event risk, in conjunction with the FNP internal event risk, could exceed the RG 1.174 base CDF of 1E-4/year with the implementation of WCAP-14333 and WCAP-15376. RG 1.174 states in Section 2.2.5.5 that if the calculated values of aCDF and aLERF are very small, as defined by Region III in Figure 3 and 4, a detailed quantitative assessment of base line value CDF and LERF will not be necessary. However, if there is an indication that CDF and LERF could considerably exceed 1E-4 or 1E-5 respectively, in order for the change to be considered the licensee may be required to present arguments as to why steps should not be taken to reduce CDF or LERF. Such an indication would result, for example, if the contribution to CDF or LERF calculated from a limited scope analysis, such as the IPE or IPEEE, significantly exceeds 1E-4 or 1E-5 respectively. The estimated combined total internal and external CDF is about 9.33E-5/year and 9.9E-5/year for FNP Units 1 and 2 respectively (utilizing the NRC staff seismic CDF estimate and revised licensee fire CDF estimates) and is below the RG 1.174 base CDF of 1E-4/year.

The licensee performed a qualitative analysis for each fire area considered risk significant in the IPEEE with regard to the proposed STI, bypass test times, and CTs risk impact. Based on this evaluation it was determined that the proposed STI, bypass test times and CTs had negligible impact on fire risk for these areas. In addition, the licensee has established procedures to minimize and control "fire risk for significant fire areas. The licensee also identified additional conservatisms with the IPEEE and subsequent fire risk estimates. Therefore, the evaluation of risk significant fire areas by the licensee and the established procedures to minimize fire risk is consistent with the guidance in RG 1.174 Section 2.2.5.5 with regard to steps taken to reduce CDF or LERF.

In addition, FNP was originally categorized as a 0.3g focused-scope plant. Subsequently, FNP was categorized as a reduced-scope plant for the IPEEE seismic analysis based on FNP being located in a low seismicity area. As a reduced-scope plant an RLE of 0.1g PGA and a HCLPF of 0.1 g PGA may provide additional conservatism with respect to the seismic CDF estimate.

Therefore, based on a combination of the assessment above that the combined total internal and external CDF is below a value of 1E-04/year with an expectation of negligible impact on fire risk from the subject TS changes, the NRC staff concludes that the implementation of W CAP-14333 and WCAP-15376 at FNP is not expected to contribute to a total internal/external CDF higher than 1E-4/year.

- 15 Cumulative Risk WCAP-15376 (Table 8.33) evaluated the cumulative CDF and LERF impact from pre-TOP WCAP-10271 to WCAP-15376 (WCAP-14333 inclusive). The cumulative impact on CDF for logic representative of FNP is slightly above the RG 1.174 acceptance guidelines of 1E-6 for a very small change, but within the acceptance guidelines for a small change. FNP previously implemented WCAP-1 0271 and its related supplements by LAR. Therefore, the WCAP-1 0271 CTs and STls have been incorporated into the FNP PRA models used to evaluate this LAR. Since the proposed change for FNP is limited from WCAP-10271 to WCAP-15376, the change in cumulative risk is expected to be within the RG 1.174 dCDF and dLERF acceptance guidelines for a small change.

The licensee also identified, in Reference 1, section 3.4, two previously approved risk-informed license amendments including a one-time extension of the integrated leak rate test (ILRT) interval and a change to the accumulator completion time. These LARs have limited risk impact on the proposed WCAP-14333 and WCAP-15376 CTs, STI and bypass test times.

PRA Results and Insights The FNP CDF for internal events is 2.35E-5/yr for Unit 1 and 2.03E-5 Unit 2. The LERF for internal events is 5.11 E-7/yr for Unit 1 and 5.06E-7/yr for Unit 2 respectively. From reference 1, page 10 of 49, the dCDF when implementing WCAP-14333 is estimated to be 6.1 E-7/year (2 out of 3 logic) for plants having implemented WCAP-1 0271. The dCDF for WCAP-15376 is estimated at 8.5E-7/year (2 out of 3 logic), based on plants having previously implemented WCAP-14333.

Both dCDF estimates are within RG 1.174 acceptance guidance of 1E-6/yr for a very small change. The 2/3 logic CDF estimates bound 2/4 logic as well. The total internal and external dCDF is therefore expected to meet the RG 1.174 acceptance guidance for a small change. The estimated dLERF for both WCAP-14333 and WCAP-15376 are within the RG 1.174 dLERF acceptance guidelines of 1.0E-7/year for a very small change. Again, the 2/3 logic results bound the 2/4 logic. The estimated ICCDP for WCAP-14333 is dependent on the CT selected but remains within the RG 1.177 acceptance guideline of less than 5.0E-7 for a single CT change.

The estimated ICCDP for WCAP-15376 for a RTB and/or a RTB and logic cabinet out of service is also within the RG 1.177 ICCDP acceptance guideline of 5.0E-7. The estimated ICLERP for WCAP-14333 and WCAP-15376 (logic Cabinet and RTB) is also dependent on the CT selected but remains within the RG 1.177 ICLERP acceptance guideline of 5.0E-8. Both the ICCDP and ICLERP estimates were evaluated for 2/3 logic but also bound 2/4 logic. The above risk estimates are applicable to plants that previously implemented WCAP-1 0271 such as FNP (i.e., a TOP).

3.1.4.2.2 Tier 2-Avoidance of Risk-Significant Plant Configurations A licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is taken out of service in accordance with the proposed TS change.

Based on WCAP-14333, WCAP-15376, and licensee evaluations, including the TS changes not evaluated generically by WCAP-14333 and WCAP-15376 the licensee identified the following Tier 2 conditions:

- 16 For WCAP-14333 and WCAP-15376

Test or maintenance activities that degrade the availability of the auxiliary feedwater system, RCS [reactor coolant system] pressure relief system (pressurizer PORVs

[power operated relief valves] and safety valves), AMSAC [anticipated transient without scram (ATWS) mitigating systems actuation circuitry], or turbine trip should not be scheduled when a logic train or RTB train is inoperable for maintenance.

One complete ECCS [emergency core cooling system] train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.

Test or maintenance activities that cause master relays or slave relays in the available SSPS train to be unavailable and test or maintenance activities that cause analog channels to be unavailable should not be scheduled when a SSPS logic train or RTB train is inoperable for maintenance.

Test or maintenance activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., service water and component cooling water (CCW only for an inoperable logic train)) that support the systems or functions listed in the above commitments should not be scheduled when a SSPS logic train or RTB train is inoperable for maintenance. That is, one complete train of a function listed in this commitment that supports a complete train of a function noted above in commitments 2 through 4 must be available.

The licensee evaluated the concurrent component outage configurations and confirmed the applicability of the Tier 2 restrictions for FI\JP. The I\JRC staff compared these conditions with the applicable conditions from the NRC staff SE's forWCAP-14333 and WCAP-15376 and finds that they are consistent with the SEs for the two WCAP SEs.

Based on the above, the NRC staff finds the licensee's Tier 2 analysis supports the implementation of WCAP-14333 and WCAP-15376 at FNP and satisfies the condition of the I\JRC staff SERs for WCAP-14333 and WCAP-15376 regarding Tier 2.

3.1.4.2.3 Tier 3-Risk-lnformed Configuration Risk Management Program The management of risk assessment of online configurations and scheduling for FNP is controlled through plant procedures. FNP procedures follow the guidance of RG 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants" and I\JUMARC 93-01, Section 11, "Assessment of Risk Resulting From Performance of Maintenance Activities" to meet the requirements of 10 CFR 50.65 (a)(4). FNP procedures require a risk assessment for all maintenance activities prior to performing the work and include the establishment of risk thresholds to ensure the average baseline risk is maintained within an acceptable band. When administrative limits are exceeded, management approval is required before initiating work. The licensee utilizes the Equipment out of Service Risk monitor (EOOS) computer based system to perform assessments for both planned and emergent conditions. The current EOOS risk monitor reflects the same PRA and databases utilized for this amendment. RTS/ESFAS data will be

- 17 revised to incorporate the proposed RTS and ESFAS STls. Procedures are to be revised by the licensee to reflect the regulatory commitments listed in Section 4.0 (Tier 2) of this safety evaluation.

A review of recent inspection reports that evaluated the licensee's maintenance risk and emergent work risk assessments, scheduling, and configuration control for selected planned and emergent work activities found them acceptable and monitored in accordance with the requirements of the Maintenance Rule, 10 CFR 50.65(a)(4) and plant procedures.

Based on the licensee's conformance to the requirements of the Maintenance Rule, 10 CFR 50.65(a)(4), and the RG 1.177 guidelines for the key components of a CRMP, and the licensee's commitment to incorporate the conditions identified in the Tier 2 evaluation as regulatory commitments, the CRMP for FNP is adequate to support the proposed change and therefore acceptable to the NRC staff.

3.1.4.3 Implementation and Monitoring Program RGs 1.174 and 1.177 also establish the need for an implementation and monitoring program to ensure that extensions to TS STI, CT, or bypass test times do not degrade operational safety over time and that no adverse effects occur from unanticipated degradation or common-cause mechanisms. The purpose of an implementation and monitoring program is to ensure that the impact of the proposed TS change continues to reflect the reliability and availability of SSCs impacted by the change.

The licensee discussed in Enclosure 1A and provided in Enclosure 4 a regulatory commitment to implement and monitor both RTS and ESFAS equipment unavailability and component failures to ensure consistency with the modeling assumptions of WCAP-1 0271, WCAP-14333 and WCAP-15376. Failures will be included in the site corrective action program. Therefore, FNP satisfies the RG 1.174 and RG 1.177 guidelines for an implementation and monitoring program for the proposed change.

3.1.5 Comparison with Regulatory Guidance The proposed changes conform to TSTF-411 , Revision 1, and also conform to TSTF-418, Revision 2, and the analysis performed in WCAP-14333 and WCAP-15376 as approved by the NRC staff, including limitations and conditions identified in the NRC staff SERs. Additional changes not evaluated by WCAP-14333 and WCAP-15376 were either justified by the licensee's previous implementation of WCAP-1 0271 or by plant specific evaluation. As such, the implementation of WCAP-14333 and WCAP-15376 at FNP is within the RG 1.174 and RG 1.177 acceptance guidance for b.CDF, b.LERF, ICCDP, and ICLERP.

3.1.6 NRC Staff Findings and Conditions The I'JRC staff finds that the licensee has demonstrated the applicability of WCAP-14333 and WCAP-15376 to FNP and has met the limitations and conditions as outlined in the NRC staff SERs. The NRC staff found the risk impacts for b.CDF, b.LERF, ICCDP, and ICLERP as estimated by WCAP-14333 and WCAP-15376 and as supplemented by the plant specific external events analysis to be applicable to FNP and within the acceptance guidelines for RG 1.174 and RG 1.177.

- 18 The licensee's Tier 2 analysis evaluated concurrent outage configurations and confirmed the applicability of the risk-significant configurations identified by the NRC staff SER limitations and conditions and topical report analysis to ensure control of these configurations.

The licensee's Tier 3 CRMP is consistent with the RG 1.177 CRMP guidelines and the Maintenance Rule (Section (a)(4)) for the implementation of WCAP-14333 and WCAP-15376.

The licensee provided a regulatory commitment to monitor the reliability and availability of the RTS and ESFAS components under the Maintenance Rule (Section (a)(1 )).

Therefore, the NRC staff finds the TS revisions proposed by the licensee are consistent with the CTs, bypass test times, and STls approved for WCAP-14333 and WCAP-15376 and meet the NRC staff SE conditions and limitations for WCAP-14333 and WCAP-15376.

3.2 Technical Evaluation Pertaining To Traditional Engineering Analysis Issues 3.2.1 The licensee has proposed the following TS changes:

3.2.1.1 Proposed Changes to Completion Times, Bypass Test Times, and Required Actions Based on WCAP-14333 The bypass test time in the note of the required action for TS 3.3.1, Condition D, would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the CT for Required Actions D.1.1 and D.2.1 would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and the CT for Required Actions D.1.2 and D.3 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months . Condition D is applicable to TS Table 3.3.1-1, Function 2a, "Power Range Neutron Flux - High," and Function 3, "Power Range Neutron Flux - High Positive Rate."

The bypass test time in the note of the required action for TS 3.3.1, Condition E, would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the CT for Required Action E.1 would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and the CT for Required Action E.2 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months . Condition E is applicable to TS Table 3.3.1-1, Function 2b, "Power Range Neutron Flux Low," Function 6, "Overtemperature ~T," Function 7, "Overpower ~T," and Function 14, "SG Water Level - Low Low."

The bypass test time in the note of the required action for TS 3.3.1, Condition M, would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the CT for Required Action M.1 would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and the CT for Required Action M.2 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months . Condition M is applicable to TS Table 3.3.1-1, Function 8a, "Pressurizer Pressure - Low,"

Function 9, "Pressurizer Water Level - High," Function 10, "Reactor Coolant Flow - Low," Function 12, "Undervoltage RCPs," and Function 13, "Underfrequency RCPs."

New TS 3.3.1, Condition 0, would be added with a CT for Required Action 0.1 of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and a CT for Required Action 0.2 of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Condition 0 would be applicable to TS Table 3.3.1-1, Function 11b, "Reactor Coolant Pump Two Loop Breaker Position."

The bypass test time in the note of the required action for TS 3.3.1, Condition P, would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the CT for Required Action P.1 would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and the CT for Required Action P.2 would be increased from 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months to 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months . Condition P is applicable to TS Table 3.3.1-1, Function 15a, "Turbine Trip Low Auto Stop Oil Pressure."

- 19 The CT for TS 3.3.1, Required Action Q.1, would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and the CT for Required Action Q.2 would be increased from 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months to 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months . Condition Q is applicable to TS Table 3.3.1-1, Function 15b, "Turbine Throttle Valve Closure."

The CT for TS 3.3.1, Required Action R.1, would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and the CT for Required Action R.2 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . Condition R is applicable to TS Table 3.3.1-1, Function 16, "Safety Injection Input from ESFAS," and Function 20, "Automatic Trip Logic."

The bypass test time in the note of the required action for TS 3.3.1, Condition S, would be increased from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the CT for Required Action S.1 would be increased from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and the CT for Required Action S.2 would be increased from 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months to 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Condition S is applicable to TS Table 3.3.1-1, Function 18, "Reactor Trip Breakers."

The CT for TS 3.3.2, Required Action C.1 , would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the CT for Required Action C.2.1 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , and the CT for Required Action C.2.2 would be increased from 42 hours4.861111e-4 days 0.0117 hours 6.944444e-5 weeks 1.5981e-5 months to 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months . Condition C is applicable to TS Table 3.3.2-1, Function 1b, "Safety Injection Automatic Actuation Logic and Actuation Relays," Function 2b, "Containment Spray Automatic Actuation Logic and Actuation Relays," Function 3a(2),

"Containment Isolation - Phase A Automatic Actuation Logic and Actuation Relays," Function 3b(2), "Containment Isolation - Phase B Automatic Actuation Logic and Actuation Relays," and Function 7b, "ESFAS Interlock Reactor Trip P-4."

The bypass test time in the note of the required action for TS 3.3.2, Condition D, would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the CT for Required Action D.1 would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the CT for Required Action D.2.1 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months , and the CT for Required Action D.2.2 would be increased from 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months to 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . Condition D is applicable to TS Table 3.3.2-1, Function1c, "Safety Injection Containment Pressure - High 1,"

Function 1d, "Safety Injection Pressurizer Pressure - Low," Function 1e(1), "Safety Injection Steam Line Pressure - Low," Function 1e(2), "Safety Injection High Differential Pressure Between Steam Lines," Function 4c, "Steam Line Isolation Containment Pressure - High 2," Function 4d, "Steam Line Isolation Steam Line Pressure - Low," Function 4e, "Steam Line Isolation High Steam Flow in Two Steam Lines," and "Steam Line Isolation High Flow in Two Steam Lines Coincident with T avg - Low Low," and Function 6b, "Safety Injection Auxiliary Feedwater Steam Generator Water Level - Low Low."

The bypass test time in the note of the required action for TS 3.3.2, Condition E, would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the CT for Required Action E.1 would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the CT for Required Action E.2.1 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months , and the CT for Required Action E.2.2 would be increased from 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months , to 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . Condition E is applicable to TS Table 3.3.2-1, Function 2c, "Containment Spray Containment Pressure High 3," and Function 3b(3), "Containment Isolation - Phase B Isolation Containment Pressure High 3."

The CT for TS 3.3.2, Required Action G.1, would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the CT for Required Action G.2.1 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , and the CT for Required Action G.2.2 would be increased from 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months to 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . Condition G is applicable to TS Table 3.3.2-1, Function 4b, "Steam Line Isolation Automatic Actuation Logic and Actuation Relays," and Function 6a, "Auxiliary Feedwater Automatic Actuation Logic and Actuation Relays."

The CT for TS 3.3.2, Required Action H.1, would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and the CT for Required Action H.2 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . Condition H is

- 20 applicable to TS Table 3.3.2-1, Function 5a, "Turbine Trip and Feedwater Isolation Automatic Actuation Logic and Actuation Relays."

The bypass test time in the note of the required action for TS 3.3.2, Condition I, would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the CT for Required Action 1.1 would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and the CT for Required Action 1.2 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months . Condition I is applicable to TS Table 3.3.2-1, Function 5b, "Turbine Trip and Feedwater Isolation on SG Water Level - High High," and Function 6d, "Auxiliary Feedwater Undervoltage Reactor Coolant Pump."

The CT for TS 3.3.2, Required Action L.2, would be increased from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , the CT for Required Action L.3.1 would be increased from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , and the CT for Required Action L.3.2 would be increased from 42 hours4.861111e-4 days 0.0117 hours 6.944444e-5 weeks 1.5981e-5 months to 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months . Condition L is applicable to TS Table 3.3.2-1, Function 7a, "ESFAS Interlocks Automatic Actuation Logic and Actuation Relays."

3.2.1.2 Proposed Changes to Surveillance Frequencies Based on WCAP-15376 The frequency of TS 3.3.1, SR 3.3.1.4, "Trip Actuated Device Operational Test (TADOT)," would be increased from 31 days on a staggered test basis to 62 days on a staggered test basis. SR 3.3.1.4 is applicable to TS Table 3.3.1-1, Function 18, "Reactor Trip Breakers," and Function 19, "RTB Undervoltage and Shunt Trip Mechanisms."

The frequency of TS 3.3.1, SR 3.3.1.5, "Actuation Logic Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.1.5 is applicable to TS Table 3.3.1-1, Function 20, "Automatic Trip Logic."

The frequency of TS 3.3.1, SR 3.3.1.6, "TADOT," would be increased from 92 days to 184 days.

SR 3.3.1.6 is applicable to TS Table 3.3.1-1, Function 12, "Undervoltage RCPs," and Function 13, "Underfrequency RCPs."

The frequency of TS 3.3.1, SR 3.3.1.7, "COT," would be increased from 92 days to 184 days. SR 3.3.1.7 is applicable to TS Table 3.3.1-1, Function 2a, "Power Range Neutron Flux High," Function 3, "Power Range Neutron Flux High Positive Rate," Function 5, "Source Range Neutron Flux,"

Function 6 "Overtemperature ~T," Function 7, "Overpower ~T," Function 8a, "Pressurizer Pressure Low," Function 8b, "Pressurizer Pressure High," Function 9, "Pressurizer Water Level High," Function 10, "Reactor Coolant Flow - Low," and Function 14, "Steam Generator Water Level - Low Low."

The frequency note for TS 3.3.1, SR 3.3.1.11, "COT," would be increased from only required when not performed within previous 92 days to only required when not performed within previous 184 days. SR 3.3.1 .11 is applicable to TS Table 3.3.1-1 , Function 17a, "Reactor Trip System Interlock Intermediate Range Neutron Flux P-6," Function 17c, "Reactor Trip System Interlock Power Range Neutron Flux P-8," Function 17d, "Reactor Trip System Interlock Power Range Neutron Flux P-9," Function 17e, "Reactor Trip System Interlock Power Range Neutron Flux P-10," and Function 17f, "Reactor Trip System Interlock Turbine Impulse Pressure P-13."

The frequency of TS 3.3.2, SR 3.3.2.2, "Actuation Logic Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.2.2 is applicable to TS

- 21 Table 3.3.2-1, Function 1b, "Safety Injection Automatic Actuation Logic and Actuation Relays,"

Function 2b, "Containment Spray Automatic Actuation Logic and Actuation Relays," Function 3a(2), "Containment Isolation Phase A Isolation Automatic Actuation Logic and Actuation Relays,"

Function 3b(2), "Containment Isolation Phase B Isolation Automatic Actuation Logic and Actuation Relays," Function 4b, "Steam Line Isolation Automatic Actuation Logic and Actuation Relays,"

Function 5a, Turbine Trip and Feedwater Isolation Automatic Actuation Logic and Actuation Relays," Function 6a, "Auxiliary Feedwater Automatic Actuation Logic and Actuation Relays," and Function 7a, "ESFAS Interlocks Automatic Actuation Logic and Actuation Relays."

The frequency of TS 3.3.2, SR 3.3.2.3, "Master Relay Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.2.3 is applicable to TS Table 3.3.2-1, Function 1b, "Safety Injection Automatic Actuation Logic and Actuation Relays," Function 2b, "Containment Spray Automatic Actuation Logic and Actuation Relays," Function 3a(2),

"Containment Isolation Phase A Isolation Automatic Actuation Logic and Actuation Relays,"

Function 3b(2), "Containment Isolation Phase B Isolation Automatic Actuation Logic and Actuation Relays," Function 4b, "Steam Line Isolation Automatic Actuation Logic and Actuation Relays,"

Function 5a, "Turbine Trip and Feedwater Isolation Automatic Actuation Logic and Actuation Relays," Function 6a, "Auxiliary Feedwater Automatic Actuation Logic and Actuation Relays," and Function 7a, "ESFAS Interlocks Automatic Actuation Logic and Actuation Relays."

The frequency of TS 3.3.2, SR 3.3.2.4, "COT," would be increased from 92 days to 184 days. SR 3.3.2.4 is applicable to TS Table 3.3.2-1, Function 1c, "Safety Injection Containment Pressure High 1," Function 1d, "Safety Injection Pressurizer Pressure - Low," Function 1e(1), "Safety Injection Steam Line Pressure Low," Function 1e(2), "Safety Injection Steam Line Pressure High Differential Pressure Between Steam Lines," Function 2c, "Containment Spray Containment Pressure High - 3," Function 3b(3), "Containment Isolation Phase B Isolation Containment Pressure High - 3," Function 4c, "Steam Line Isolation Containment Pressure - High 2," Function 4d, "Steam Line Isolation Steam Line Pressure Low," Function 4e, "Steam Line Isolation High Steam Flow in Two Steam Lines," and "Steam Line Isolation Coincident with T avg - Low Low,"

Function 5b, "Turbine Trip and Feedwater Isolation SG Water Level- High High (P-14)," Function 6b, "Auxiliary Feedwater SG Water Level- Low Low," Function 7c, "ESFAS Interlocks Pressurizer Pressure P-11 ," and Function 7d, "ESFAS Interlocks with T avg - Low Low P-12."

The frequency of TS 3.3.2, SR 3.3.2.5, "TADOT," would be increased from 92 days to 184 days.

SR 3.3.2.5 is applicable to TS Table 3.3.2-1, Function 6d, "Auxiliary Feedwater Undervoltage Reactor Coolant Pump."

The frequency of TS 3.3.6, SR 3.3.6.2, "Actuation Logic Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.6.2 is applicable to TS Table 3.3.6-1, Function 2, "Automatic Actuation Logic and Actuation Relays."

The frequency of TS 3.3.6, SR 3.3.6.3, "Master Relay Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.6.3 is applicable to TS Table 3.3.6-1, Function 2, "Automatic Actuation Logic and Actuation Relays."

The frequency of TS 3.3.7, SR 3.3.7.3, "Actuation Logic Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.7.3 is applicable to TS Table 3.3.7-1, Function 2, "Automatic Actuation Logic and Actuation Relays."

- 22 The frequency of TS 3.3.7, SR 3.3.7.4, "Master Relay Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.7.4 is applicable to TS Table 3.3.7-1, Function 2, "Automatic Actuation Logic and Actuation Relays."

The frequency of TS 3.3.8, SR 3.3.8.3, "Actuation Logic Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.8.3 is applicable to TS Table 3.3.8-1, Function 2, "Automatic Actuation Logic and Actuation Relays."

The frequency of TS 3.3.8, SR 3.3.8.4, "Master Relay Test," would be increased from 31 days on a staggered test basis to 92 days on a staggered test basis. SR 3.3.8.4 is applicable to TS Table 3.3.8-1, Function 2, "Automatic Actuation Logic and Actuation Relays."

3.2.1.3 Proposed Changes to Surveillance Frequencies Based on TSTF-242 The frequency note for TS 3.3.1, SR 3.3.1 .8, "COT," would be increased from only required when not performed within previous 92 days to only required when not performed within previous 184 days, the frequency would be increased from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power below P-10 for power range and intermediate range instrumentation to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-10 for power range and intermediate range instrumentation, and the frequency would be increased from every 92 days thereafter to every 184 days thereafter. SR 3.3.1.8 is applicable to TS Table 3.3.1-1, Function 2b, "Power Range Neutron Flux Low," Function 4, "Intermediate Range Neutron Flux,"

and Function 5, "Source Range Neutron Flux."

3.2.1.4 Proposed Changes to CTs Based on TSTF-246 The CT for TS 3.3.1, Required Action F.1 and Required Action F.2 would be increased from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . TS 3.3.1, Condition F is applicable to TS Table 3.3.1-1, Function 4, "Intermediate Range Neutron Flux."

3.2.2 Compliance with Current Regulations and Oefense-in-Oepth The proposed changes do not involve changes to instrument actuation setpoints, setpoint tolerances, testing acceptance criteria, or channel response times. No hardware changes are being proposed or required to implement these changes. This LAR would allow more time for maintenance and testing activities, provide additional operational flexibility, and reduce the potential for forced outages to comply with the current RTS and ESFAS instrumentation TS. The licensee explained that industry information has shown that a significant number of reactor trips are related to instrumentation test and maintenance activities, indicating that the TS should provide sufficient time to complete these activities in an orderly and efficient manner.

There is no change in the licensee's conformance with 10 CFR 50.36, 10 CFR 50.55a(h), or GOC 13, 21, and 22 as a result of the changes proposed in this LAR. There would be no change to the RTS, ESFAS, Containment Purge and Exhaust Isolation, CREFS, or PRF instrumentation design.

Therefore, the proposed TS changes meet the applicable regulatory requirements and there is no change in defense-in-depth.

- 23 3.2.3 Evaluation of Sufficient Safety Margins The proposed changes do not affect the acceptance criteria for any analyzed event and there is no change to any safety limit. There is no impact on the RTS and ESFAS setpoint calculations or the limiting safety system settings trip setpoint safety margin. Reduced testing is expected to result in fewer inadvertent reactor trips and less frequent actuations of ESFAS components.

Extension of CTs would provide additional time to complete test and maintenance activities, while at power, potentially reducing the number of forced outages.

Therefore, the proposed changes do not involve a significant reduction in the margin of safety.

3.2.4 Reconciliation of FNP TS Changes with Approved WCAP-14333 (TSTF-418) and WCAP-15376 (TSTF-411)

(a), RTB Bypass Time For TS 3.3.1, Function 18, "Reactor Trip Breakers," Condition S (currently Condition R) the licensee has proposed that the bypass test time allowed for surveillance testing in the required action note be extended from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The licensee's proposal is consistent with TSTF-411 , Function 19, "Reactor Trip Breakers," Condition O. TSTF-411, Insert 6, directs how the Condition 0 required action notes should be incorporated depending on which WCAPs a licensee is implementing. Since both WCAP-14333 and WCAP-15376 are being implemented, the licensee proposes that TSTF-411, Insert 6, Note 3 be implemented, thus allowing 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months of bypass test time for surveillance testing of one RTB train. The licensee's proposal is consistent with the two NRC approved TSTF-418 and TSTF-411, and accordingly is acceptable to the NRC staff.

(b), ESFAS Interlocks Condition L CTs For TS 3.3.2, Function 7a, "ESFAS Interlocks Automatic Actuation Logic and Actuation Relays," the licensee has proposed the revision of CTs for Required Action L.2 from 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , Required Action L.3.1 from 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , and Required Action L.3.2 from 42 hours4.861111e-4 days 0.0117 hours 6.944444e-5 weeks 1.5981e-5 months to 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months . Condition L is applicable to ESFAS Solid State Protection System (SSPS) automatic actuation logic and actuation relays. The licensee states that the proposed CTs are similar to the CTs for FNP, TS 3.3.2, Conditions C, G, and H, which are also applicable to ESFAS SSPS automatic actuation logic and actuation relays. The CTs for Conditions C, G, and H were justified in WCAP-14333. The licensee states that since the signals for Function 7a and other ESFAS automatic actuation logic and actuation relays functions are processed through the SSPS, the same CTs should be applicable for Condition L. On the above basis, the NRC staff finds that the proposed CTs for TS 3.3.2, Required Action L.2, Required Action L.3.1, and Required Action L.3.2, are acceptable.

(c), RCP Breaker Position For TS 3.3.1, Function 11b, "Reactor Coolant Pump Breaker Position Two Loops," the licensee has proposed that the note in the required action for TSTF-418, Condition M, not be included in the required action of new Condition O. This note would provide the allowance to bypass a single inoperable channel to allow surveillance of the remaining channels. The Farley design does not allow for the bypassing of a Reactor Coolant Pump

- 24 Breaker Position channel, and testing must be performed during shutdown. Therefore, this note is necessary and the licensee's proposal not to include this note in Condition 0 is acceptable.

(d), Surveillance Test Frequency for TS 3.3.6, TS 3.3.7 and TS 3.3.8 For TS 3.3.6, Containment Purge and Exhaust Isolation (CPEI) Instrumentation, TS 3.3.7, CREFS Actuation Instrumentation, the licensee proposes to change the surveillance frequency for the actuation logic test and the master relay test (SRs 3.3.6.2, 3.3.6.3, 3.3.7.3,3.3.7.4) from every 31 days on a staggered test basis to every 92 days on a staggered test basis. This is consistent with the NRC approved WCAP-15376 and TSTF-411, and is accordingly acceptable to the NRC staff.

The licensee also proposed to change the surveillance frequency for TS 3.3.8, Penetration Room Filtration (PRF) Actuation Instrumentation, actuation logic test and the master relay test (SRs 3.3.8.3 and 3.3.8.4) from every 31 days to every 92 days, on a staggered test basis. The licensee's basis is that the actuation logic and the master relays associated with the PRF Actuation Instrumentation are processed through the SSPS similar to the actuation logic and master relays associated with the TS 3.3.6, and TS 3.3.7. The surveillance frequency extensions for the actuation logic and master relays of the TS 3.3.6 and TS 3.3.7 were justified in WCAP-15376. As stated in WCAP-15376, these surveillance frequency extensions are also applicable to actuation logic and master relays for all signals processed through the SSPS, which would include TS 3.3.8 since they are also processed through the SSPS. Based on the extensions for TS 3.3.6 and 3.3.7 being approved in the NRC approved W CAP-15373 topical report and their comparability to the TS 3.3.8 extensions, the NRC staff finds the proposed surveillance "frequency extension for TS 3.3.8 to be acceptable.

(e), Turbine Trip For TS 3.3.1, Function 15a, Turbine Trip Low Auto Stop Pressure," and Function 15b,

Turbine Trip Turbine Throttle Valve Closure," the licensee has proposed to retain Conditions P and Q (currently Conditions 0 and P) in lieu of the single turbine trip condition N that is in NUREG-1431. The licensee states that use of two separate turbine trip conditions is consistent with the Farley licensing basis and that, as documented in WOG letter 06-17, the CT and bypass time changes are applicable to both Conditions for plants that contain two turbine trip conditions. The licensee's proposed revisions to the turbine trip CTs and bypass times are consistent with the NRC approved WCAP-14333 and TSTF-418 and are applicable to Farley based on letter WOG-06-17. Therefore, on this basis, the NRC staff finds that the application of the WCAP-14333 CTs and bypass times for proposed Conditions P and Q is acceptable.

(f), TADOT Extension from 92 to 184 Days For TS 3.3.1, Function 12, "Undervoltage RCPs," and Function 13, "Underfrequency RCPs," and TS 3.3.2, Function 6.d, "Auxiliary Feedwater - Undervoltage Reactor Coolant Pump," the licensee proposed the extension of SR 3.3.1.6, "TADOT," and SR 3.3.2.5, "TADOT," from 92 days to 184 days. As approved, WCAP-10271 , Supplement 1 and Supplement 2, Revision 1, included TADOT changes for RTS Undervoltage Reactor

- 25 Coolant Pumps, RTS Underfrequency Reactor Coolant Pumps, and ESFAS Auxiliary Feedwater - Undervoltage Reactor Coolant Pumps. WCAP-15376 justified the extension of the surveillance frequency for COT from 92 days to 184 days. The justification for the surveillance frequency extensions in WCAP-15376 utilized a "representative signal approach." The results of the evaluation of representative signals were indicative of all signals that were evaluated in WCAP-1 0271. As stated in Section 11 of WCAP-15376, "These recommendations are applicable to all signals evaluated in WaG TOP." WaG TOP refers to WCAP-1 0271.

Since WCAP-10271 is applicable to TADOT changes for RTS Undervoltage Reactor Coolant Pumps, RTS Underfrequency Reactor Coolant Pumps, and ESFAS Auxiliary Feedwater - Undervoltage Reactor Coolant Pumps, the extension of SR 3.3.1.6 and SR 3.3.2.5 from 92 days to 184 days is acceptable.

(9) COT extension For TS 3.3.1, Functions 17a, 17c, 17d, 17e, and 17f, which are RTS permissive functions P-6, P-8, P-9, P-10, and P-13, respectively, the licensee has proposed to extend the conditional frequency note of SR 3.3.1.11, "COT," from only required when not performed within the previous 92 days to only required when not performed within the previous 184 days. The intent of the COT for RTS permissive functions is to ensure that the permissive instrument channels are functionally tested periodically and/or before startup and power ascension, which is consistent with the surveillance frequencies for other RTS channels.

WCAP-15376 justified extending the surveillance frequencies for SR 3.3.1.7, "COT" and SR 3.3.1.8, "COT" from 92 days to 184 days, and this is reflected in the current STS. The SR 3.3.1.7 and SR 3.3.1.8 COTs are applicable to RTS functions that are supported by permissives P-6, P-8, P-9, P-1 0, and P-13. Each of the permissive instrument channels share one or more signal processing modules and a sensor with the functions for which SR 3.3.1.7 or SR 3.3.1.8 is applicable. Since the COT surveillance frequency of the functions that share signal processing modules and sensors with the permissive functions would be extended to 184 days, the !\IRC staff finds it acceptable to also extend the SR 3.3.1.11 surveillance frequency to 184 days for TS 3.3.1, Functions 17a, 17c, 17d, 17e, and 17f.

3.2.4.3 TSTF-242 The licensee proposed the extension of the CT for SR 3.3.1.8, "COT," from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after reducing power below P-10 to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reducing power below P-1 O. The licensee's proposal is consistent with TSTF-242, Revision 1, which allows the extension of the surveillance frequency of the COT, for power range and intermediate range neutron flux instrumentation after reducing power below P-1 0, from 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The licensee provided a basis, stating that a reasonable time allowance to perform COTs on all four power range and two intermediate range neutron flux channels is 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months per channel. Thus, the total time allowance to perform SR 3.3.1.8 COTs on all six channels after reducing power below P-10 would be 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The NRC staff finds the licensee's basis to be consistent with the staff's basis for approval of TSTF-242, Revision 1. Accordingly, the NRC staff finds that TSTF-242, Revision 1, is applicable to FNP and that the proposed change is acceptable.

- 26 3.2.4.4 TSTF-246 The licensee proposed the extension of the CT for TS 3.3.1, Required Action F.1 and Required Action F.2, from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , when thermal power is greater than P-6 and less than P-10 with one Intermediate Range Neutron Flux channel inoperable. The licensee's proposal is consistent with TSTF-246 which allows an increase in this CT from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The licensee has provided the following basis for this proposed change:

This proposed change is acceptable for the following reasons: (a) the power range (PR) low setpoint is the safety analysis credited protection for power excursions between P-6 and P-10, (b) adequate protection is still provided by the remaining intermediate range (IR) channel and the PR channels, and (c) if the second IR channel is not available, Condition G would require no positive reactivity additions and reduction of power to below P-6 within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . If a PR low setpoint channel is not available, Condition E would require that channel to be placed in trip within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (or be in MODE 3 within 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months ) thus fUlfilling the safety function for that PR channel.

In addition, a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time may be impractical for increasing power above P-10.

The actual time required depends on plant conditions at the time one channel is determined inoperable.

The NRC staff finds the licensee's basis to be consistent with the staff's basis for approval of TSTF-246 and thus the proposed 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months time limit for TS 3.3.1, Condition F, is a reasonable time frame for accomplishing the required actions (i.e., slow and controlled power adjustment either above P-10 or below P-6). Accordingly, the NRC staff finds that TSTF-246 is applicable to FNP and that the proposed change is acceptable.

4.0 REGULATORY COMMITMENT In most cases, including analog channels, master relays, and slave relays, the relative contribution to CDF among SSCs did not change significantly for the proposed CTs evaluated by WCAP-14333 and WCAP-15376. However, a relatively significant change in actuation signals and associated SSC contributions to CDF were noted for a logic cabinet or a RTB in maintenance.

To address this, both WCAP-14333 and WCAP-153766 established that each licensee referencing WCAP-14333 and WCAP-15376 must determine the need for and place the necessary restrictions on concurrent maintenance configurations when entering the proposed CTs to avoid risk-significant configurations. The Tier 2 risk-significant configurations in Section 3.1.4.2.2 were identified by the licensee based on WCAP-14333, WCAP-15376 analysis, RAI responses, and plant specific licensee evaluations.

Based on the licensee's conformance to the requirements of the Maintenance Rule, 10 CFR 50.65(a)(4), and the RG 1.177 guidelines for the key components of a CRMP, and the licensee's commitment to administratively control Tier 2 risk-significant configurations, the following regulatory commitments provides adequate configuration risk management support for the proposed change and are therefore acceptable to the staff.

For WCAP-14333 and WCAP-15376:

Test or maintenance activities that degrade the availability of the auxiliary feedwater system, RCS [reactor coolant system] pressure relief system (pressurizer PORVs [power

- 27 operated relief valves] and safety valves), AMSAC [anticipated transient without scram (ATWS) mitigating systems actuation circuitry], or turbine trip should not be scheduled when a logic train or RTB train is inoperable for maintenance.

One complete ECCS [emergency core cooling system] train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.

Test or maintenance activities that cause master relays or slave relays in the available SSPS train to be unavailable and test or maintenance activities that cause analog channels to be unavailable should not be scheduled when a SSPS logic train or RTB train is inoperable for maintenance.

Test or maintenance activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g., service water and component cooling water (CCW only for an inoperable logic train)) that support the systems or functions listed in commitments 2 through 4 above should not be scheduled when a SSPS logictrain or RTB train is inoperable for maintenance. That is, one complete train of a function listed in this commitment that supports a complete train of a function noted above in commitments 2 through 4 must be available.

Implement a program to monitor RTS and ESFAS protection system equipment unavailability and component failures to ensure consistency with WCAP-1 0271, WCAP-14333, and WCAP-15376 modeling assumptions.

For channels with built-in bypass capability, or for inoperable channels bypassed for surveillance testing of other channels, implement administrative controls to ensure that analog channels are not routinely removed from service at-power for channel calibration, if such calibration would take more than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

The NRC staff finds that reasonable controls for the implementation and subsequent evaluation of the proposed changes pertaining to the above regulatory commitments are best provided by the licensee's administrative processes, includinq its commitment management program. Moreover, the subjects of these commitments are, in a general sense, reflected in existing TSs and in the licensee's programs for the implementation of the Maintenance Rule. Therefore, the above regulatory commitments do not warrant the creation of regulatory requirements (i.e., items requiring prior NRC approval of subsequent changes).

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the State of Alabama official was notified of the proposed issuance of the amendments. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued

- 28 a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (73 FR 39056). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

7.0 CONCLUSION

7.1 Conclusion - Probabilistic Risk Assessment The NRC staff finds that the TS revisions proposed by the licensee are consistent with the CTs, bypass test times, and surveillance intervals evaluated in WCAP-14333 and WCAP-15376 and meet the NRC staff SER conditions for the implementation of WCAP-14333 and WCAP-15376.

The NRC staff finds that the topical report generic analyses are applicable to FI\lP. The estimates for L1CDF, L1LERF, ICCDP, and ICLERP were found to be applicable and within the acceptance guidance of RGs 1.174 and 1.177. The Tier 2 conditions were found to be applicable to Ff\lP and will be incorporated into plant programs and procedures consistent with WCAP-14333 and WCAP-15376 and associated NRC staff SERs. Implementation of the licensee's Tier 3 CRMP is in accordance with the Maintenance Rule (Section (a)(4)) and is consistent with the CRMP guidance of RG 1.177. The implementation and monitoring program satisfies the RG 1.174 and RG 1.177 guidelines for the proposed change. Therefore, based on the above evaluation, the I\JRC staff concludes that the proposed LAR to extend FNP RTS and ESFAS CTs, bypass test times, and STls is acceptable.

7.2 Conclusion - I&C Assessment The NRC staff has reviewed the licensee's proposed TS changes for RTS, ESFAS, CPAE Isolation, CREFS, and PRF instrumentation for CT, bypass test times, and surveillance frequency extensions. The NRC staff finds that the proposed TS changes are consistent with WCAP-14333, WCAP-15376, TSTF-411 , TSTF-418, TSFT-242, and TSTF 246, and meet the SE conditions and limitations of WCAP-14333 and WCAP-15376. Therefore, the proposed changes are acceptable 7.3 Conclusion - Overall The Commission has concluded, based on the considerations discussed above, that (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or the health and safety of the public.

8.0 References

1. License Amendment Request for Joseph M. Farley Nuclear Plants, Units 1 and 2, "Revision to Technical Specification 3.3.1,3.3.2,3.3.6,3.3.7, and 3.3.8," dated December 20,2007, ADAMS Accession Number ML073580499.

2. Supplement to reference 1, September 12, 2008, (ADAMS Accession l\lo. ML082590057

3. Supplement to reference 1, October 8, 2008, (ADAMS Accession No. ML082830009)

- 29

4. Supplement to reference 1, October 27,2008, (ADAMS Accession No. ML083020162).

5. Topical Report WCAP-14333-P-A, Revision 1,

6. Topical Report WCAP-15376-P-A, Revision 1,

7. Letter with Safety Evaluation for TSTF-418, Revision 2, "RPS and ESFAS Test Times and Completion Times (WCAP-14333)," dated April 2, 2003, ML030920633.

8. Letter on TSTF-411, Revision 1, "Surveillance Test Interval Extension for Components of the Reactor Protection System (WCAP-15376)," August 30,2002, ML022460347.

9. Vogtle Electric Generating Plant License Amendment, September 1,2006, ML062360588.

Principal Contributors: C. Doutt B. Marcus Date: January 15, 2009

J.R. Johnson -2 A copy of the related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely, IRA!

Robert E. Martin, Senior Project Manager Plant Licensing Branch 11-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-348 and 50-364

Enclosures:

1. Amendment No. 180 to NPF-2

2. Amendment No. 173 to NPF-8

3. Safety Evaluation cc w/encl: Distribution via ListServ DISTRIBUTION:

Public RidsAcrsAcnwMailCenter Ridsl\JrrDirs LPL2-1 R/F GHili (4 hard copies) RidsNrrDss Ridsl\JrrDorILpI2-1 RidsNrrDirsltsb ALewin RidsNrrPMRMartin (hard copy) CDoutt BMarcus RidsNrrGLappert (hard copy) RidsRgn2MailCenter (SShaeffer)

RidsOgcRp RidsNrrDorlDpr Amendment No.: ML083450588 *Per Memo Dated, (**\ Per E-mail OFFICE LPL2-1/PM LPL2-1/LA APLAlBC EICB/BC ITSB/BC OGC LPL2-1/BC NAME RMartin GLappert MRubin WKemper RElliott BMizuno MWong DATE 01/12/09 12/04/08 11/19/08* 11/20/08* 12/4/08 01/14/09 01/16/09 OFFICIAL RECORD COpy

v t e Letter Sequence Approval
TAC:MD8135, Increase the Time to Perform a Cot on Power Range and Intermediate Range Instruments, RTS Instrumentation, 3.3.1 Condition F Completion Time (Approved, Closed) TAC:MD8136, Increase the Time to Perform a Cot on Power Range and Intermediate Range Instruments, RTS Instrumentation, 3.3.1 Condition F Completion Time (Approved, Closed)
Initiation Request, Request, Request Acceptance... Administration Questions 10 September 2008 Answers Results Approval Other: ML083430635
MONTHYEAR2008-12-08 [Table View]

ML083450588

Text

Dear Mr. Johnson:

Enclosures:

Attachment:

Attachment:

1.0 INTRODUCTION

2.0 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

5.0 STATE CONSULTATION

6.0 ENVIRONMENTAL CONSIDERATION

7.0 CONCLUSION

Enclosures:

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