ML17109A317

{{Adams | number = ML17109A317 | issue date = 04/13/2017 | title = Peach Bottom Atomic Power Station, Units 2 and 3 - Submittal of Changes to Technical Specifications Bases | author name = Barstow J | author affiliation = Exelon Generation Co, LLC | addressee name = | addressee affiliation = NRC/Document Control Desk, NRC/NRR | docket = 05000277, 05000278 | license number = DPR-044, DPR-046 | contact person = | case reference number = CCN 17-44 | document type = Letter, Technical Specification, Bases Change | page count = 1481 }}

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{{#Wiki_filter:200 Exelon Way #asr*' Exelon Generation Kennett Square, PA 19348 CCN 17-44 April 13, 2017 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 Peach Bottom Atomic Power Station, Units 2 and 3 www.exeloncorp.com Renewed Facility Operating License Nos. DPR-44 and DPR-56 NRG Docket Nos. 50-277 and 50-278

Subject:

Submittal of Changes to Technical Specifications Bases TS 5.5.10.d In accordance with the requirement of Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3 Technical Specification 5.5.1 O.d, Exelon Generation Company, LLC, hereby submits a complete updated copy of the Unit 2 and Unit 3 Technical Specifications Bases. The enclosed Bases include changes through the date of this letter. If you have any questions or require further information, please contact Stephanie J. Hanson at 610-765-5143. Sincerely, James Barstow Director, Licensing & Regulatory Affairs Exelon Generation Company, LLC

Enclosures:

1) PBAPS Unit 2 Technical Specifications Bases 2) PBAPS Unit 3 Technical Specifications Bases cc USNRC Region I, Regional Administrator (w/o enclosures) USNRC Senior Resident Inspector, PBAPS (w/o enclosures) USNRC Senior Project Manager, PBAPS (w/o enclosures) R. R. Janati, Pennsylvania Bureau of Radiation Protection (w/o enclosures) S. T. Gray, State of Maryland (w/o enclosures)

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• 3.4-37-.*.*..*....* ;.-:.; ....................... ;* ............ ; ................................. : ................. Rev 126 3:4-37a ....... ....... ; ..... : ......................... ; ...... ......... ; ................................... Rev 127 3.4-37b ... .' ....... -............ , ........................... -............................ _ ........................ Rev 126 -3.4-39 ............... ; ................... ; ............................................ ; ........ ............. Rev 126 3.4-42 ........ .'::.;; ...... , .............. : ............................... ; ................... ; ................. Rev 127 . 3.4-42a ......... ....... .-.............. ; .. ;-: ........................ ;.-................ ; .......... ;: ....... : .. Rev 126 _ 3.4-43 ... ' .... .': ** .... ; .. _.: ..... -...... ..... ........ .' ........ .... ; ...... .... -.. -........ ; ......... Re\I' 102 _ 3.4-44 ... :.;; ........ _ .................... ; ........ _ ............ _ ................................. _ ................ Rev *102 -3,4.45 ........ ; .................. , ..... ; ......... : ..... -......................................... _ ............. ;. Rev 102 3.4-46 ..** -..... : ................... ....... * .. : ........ , ...... -:. ..... -.. -;: ........... ............................ Rev 102 3.4-47 .. ... .. ..... _ .... :-.. *. -............. :;:: .............................. -........................ -.... Rev 102-.. Hi =: l E . 3.4-51 ........... :: ... : .......... :; ...... ; ... -............ ; ............ : .......... -:; ... : .. ; ........ .* : ......... Rev 102: _ 3.4-52 ** .-........ , ..... :-.. :.:_ .. .-......... ; .. ; ......... ;-....... : ............................. :_ .............. ; .... Rev 49 3.4-53 ........ ; ....... ;;; .......... .................... ;; .............. _ ............... ; ............ : ........... Rev 114 *' .':. PBAPS UNIT2 vL
• Revision No. 139 r.

PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM page(s) 3.5-3 ..*....***...*..*.*..*.***.*.**.*..**..*..........*.*..**..*.*.*.****.*.**.**** : ...*.*..*..****.*.*..**.... Rev 110 3.5-4 ***..**....*..***.*.**....**....*..*...*...**......*...**.*****..*.......*.*..*.*....*..*......**.*.*.*..*. Rev 125 3.5-5 .*.**.*..*.*...*..***....*.*...**..**.**..*****.*..*.* , ** ; ...*.*..*.*.*...*.*.*....***..*...**.*.*...**.*.* Rev 126 3.5-6 ..**...*.*.**..*..***....*....*...*.....**..*..*.**.*.******.*..*..*.*..*.*....*.*..***....*..*....*.**.*.* Rev 112 3.5-6a ..*.......**..****..*...*.......**....*.........*.**.***.*.**..*.*.*.*.....*.*...*.***......*....*......... Rev 96 3.5-7 **..**....*.*.**.*.....*..**.. ; .*..*****.****.***..***.***....****..*....***.**.*.**.....**.*.....*.**.*.*.*. Rev 89 3.5-8 **..**..*...*.****.....*..**.*..*...**.*..*.***.**...**..*...*.*.**...*.....*.*....*.*...*..*.....*.**.*.*. Rev 101 3.5-9 .**..**..***....*.****.*.*..*..*.**..*..**.....*..*.*...**.*.*.*.*.*..********.......****..*..***..*..*.*** Rev 126 3.5-10 .* ; *...*.*..**...*......*...*...***..*.*********.*..*.*...**.**.*.*.*.**..*......*.*.*..*.*.*...*.**....* Rev 127 3.5-10a *..*.*.*......**.....*..*.*.*..***.*..*****.**.*..*...*.*****.*.***.*.*.*.*....***.*.**.*.....*.**.*..* Rev 126 3.5-11 .**..*...***.*...**...*.**.*..*...*............**....**..*.*...*.***.*....****.....**.*..*.*..**...*.*...** Rev 86 3.5-12 ..***...*............*...*...*..*..........*..**.*.*...*.....*..........***...*..**.***..**.*....*........ Rev 131 3.5-13 ..................... , .**.........**..*..*..* ; .*.**.*.*..**.*.*.**...*...*.*.*.....****.*....*.*....*..*.*...* Rev 99 3.5-14 .*.****.**. : ..*.**.*...*....*.**.**..*..*....*...**.*....*....*.****..*...***....***...**.**......**.*..* Rev 130 3.5-15 *...*....*....*.**.*.. ; **..*..*...*..***.....*......**....*..*..****..*.*.*....*..*..*..*.......*..*.*..... Rev 86 3.5-16 .**..*...*....*.*..*....**..*.**..*..*...*...**.*.*..*..*.*......*.*..*...*.*.....*.....*........***.*...** Rev 86 3.5-17 .***.*....*.****.*...*.*.**....***..**....*...**.****.******...**....*.*.*.*.*.*..***..***.*....*.*.*.... Rev 101 3.5-18 .***......*.**.**.*..*.*.....**.**.*.....*..*....*.**..*.*.*..*...*...**.*...*..**.**...*..*...**.**..... Rev 133 3.5-19 **.*..*.*.** : ..***...*.*....*. ; ****..*..*.*..*.****.*..*.***.**...*.*.*.*....*.***.**..**..*......**.....*. Rev 96 3.5-19a ..**.*.*.**.*.*..**..*...*......*....*...*.*** , **.***.*. : .*..*.*.**...*.*.*..***..*.*. ; **........*.*.*.*. Rev 96 3.5-19b *..*.*..*****...**...*.*...**....**.*.* * **.*..*.*.**.**.***.........*.....*......*...*...*...*..*......... Rev 96 3.5-22 ..**. : ..*.*.*. : **.*.**.**.*. ; .*..**..*..... : .............................................................. Rev 126 3.5-23 ..**..... : ...*.**...........*.**.. .-....*......*** , ...**.*....*.*.*...*....*.*.*....**.*..**........*.....*. Rev 57 . 3.5-24 *****..*.*....*.**.*..**.*.*.**.....*.*..*.....***.***.*.**.***.* : ***.*.** : *****..**.*.*....*.*..**.....* Rev 110 3.5-25* .**.. : .*.**. ; .............*.*.**.*.*.*.**..*.**.*.**.**.*.. -.*....*......**..*...**..*..*.**...*.**.***..* Rev 126 3.5-26 ..**...**.*.. -..**.*..*.**.*.*..*** : ....* .-......*.*.*...*.*.*.*..*.*..***.**..*....**.**.*...*......*.*.*. :. Rev 66 3.5-27 **..**** ; *.**.*.*****.*..*.....*...*.*...*..**..*.*.***.*.*.*.*.**.**.*.*.*.*..***..*..* ; ****.....**..*.* Rev 127 3.5-27a *.* **.*.*.*..*......*..*.****..*..*.**. : *...*.*....*.**..****...........*...*..* : ..*..**..*...*.*.*. :.Rev 126 3.5-28 ................................................ : ....................................... , ..**....***...*.*. Rev 130 3.5-29 *****..****.*.*.*. : *..**.*....*..*...*...*.*..* : ***...*.**..* ; .*........ : .*.*.*.**...... .-*......*.*.*...... Rev 86 3.5-30_ .............. : *...**.*.*..*.*..*..*.*.**....*.. : .. : .*.*..*.*....*.*...*****.. , .............................. Rev 66 B 3.6 CONTAINMENT SYSTEMS* page(s) PBAPS UNIT 2 3.6-1 .*..*..*..*.*. ..**... : *.**...*..*.*..**** ;.; ***. .-** ;; .*...*.*....***.***.*...* ; .*....*..*.****.....*.*.*..*. Rev 27

• 3.6-2 *.**.**.**********.*. :; *.***. : .* .*.*** : ...... -*.* .-; ..*** * *.*.****.*.*.*.*****..*. .-: .********.*....*.* ; *.**** Rev 114 3.6-3 *.*.**..** .' .*.*.*.**.*...* ; .*.*..*....* *..* .**..** : .. ::.-.****.**...*.*.*.**...*.*..* -..*.*.**...*.. ; ......... Rev 66 .**.**.*. * .*.*.* : ****..*..*.*.* ................. .-** : ..* : ..*. , **.* .-.*.***....*.*.*.* :.: .*.**. : .*..****.*...... Rev 86 3.6-5 *.*.***.***.***.*..*.*.**.*.**.**..*.** .-; ..*.**.***.***. : .*.**.*.**....**** -.; ..*.**. ; .. ; ****.....**..***..* Rev 118 3.6-7 *. **. : *.* * .*.** ;:.; .*.*.**.*..**.********* -..*.*... : **.*. .-.*** :: .**.**.*..... : *.*.*.**.*** .. : *....*.. : ...* Rev .114. 3.6-11 ..**.*.*.* : *.*..**.*.*..***..**.** : *.* ..... .' .* ; *. _.: *..*...** .*.*..... _..'. *.*.*.. ; ..................... _ .*. *.* _Rev 6. ............... , **.*.*..*.**. -*********.**************.********.****...**.***.*. :, **.**..*....**.**.**.*. : .* Rev 86
• 3.6-13 **..* ;; *..* * *.*.* : **.*.** _ .* : .* :.:.' .**..*. .*.*.*...**..**.*.**.**. : .*.* , ..*. '..: *..***.* : *.*. '. .**..*.***...* Rev 1*14 3.6-16 **..*.**.*.***.**.*.*.**.*..**..* .-*.**.....*..*. , .**...* _ ..*..*..*.*.*....*.* ;., *.*..*..*.*......*.*.*.*.*..* Rev 91 * -3.6-17.; 18*.(inclusive) *..* * *.*.*****.**..* * **.****. :_ **.*.**. ; ..*....*... :-*.*.. '.********.*; *....*..* .-.: .*.*. : ** Rev 2 *. 3.6-20 *.* : **.. **.****.**.*.* ;._ *..*.**..**..*..***** : *** _: ........ **.. .-**.** : *.****.*.*... :.: .* : .*.. .-.**.*****.* :; ** Rev 57 -3.6-21'-...*..**..* -.*. _ .. , *.*...*.*..*..* ; **.* : *.....* .-..* .-.*.*. : **.**..*.....*....*.* : *.*...*. , **.......**** ; *.*.*. Rev 57 3.6-22 * .-: .* _ ....* .-*.*.***..*..*.*.*** : **.*.**...*.***** : **. .-.; .****.**.*.*.*.**.**.*..***.*** ; *.*.....*****.* -.*.* ; Rev 57 ... ".* vii Revision No. 139 PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.6 CONTAINMENT SYSTEMS (continued) page(s) 3.6-23 .**.**.*..*.***..*.*****..*.**.*.*..**..**.*...*.*******.**..*****.*.*.***..* : ..*.**.**..**..**....****.* Rev 114 PBAPS UNIT 2 3.6-23a ........................................................................................................ Rev 114 3.6-24 .*..*.*.****...*.**.*...**.**...***.*.......**.*.*.*.*.....*.***......*.*.*...*...**...*.*..*.*...*..*.*.** Rev 91 . 3.6-25 ****..*.....****.****...*..****...******....**.*******.*...*.****....**********.*.**....**..*.*...*..*..... Rev 86 3.6-26 **...**.*..*..**.**.*.**...**.*...**....***.*....*.*.****..*.****.....*...*.*.*....***..**..*.*...*****..*. Rev 86 3.6-27 .*.*.*****.*.*.*..*.*.****.*.**...**...*****.........**..********.*...*.......*..*.**...**..*.....*......*. Rev 86 3.6-28 *.**.....*.***...**.*.*.*..*......**...*.**.....*.*..*..******..*.*...........*...**.*..*...*.*...*.**.**** Rev 86 3.6-29 ..**.*...*.***.****.*.*.**.*.*..*.**......*.**..*..*...*.***.*****..*...*.*.*.*...****..**..*...*.*..*.** Rev 114 3.6-30 *....*.**......*..*****.*..*......**...*.*..**.**..*.*.*..***.*** .**.*.*..**......***.*.**.*.... *..**.. Rev 114 3.6-31 .*..*.***.*.*.**...*.***..*.***.***.* ; ****..**.*.**.***.**.*****.*..*.....*..*.*.*.*...*...*...*.*.*..***. Rev 18 3.6-33 .**..*.*.*......*..**......*.*.*.**..*....*..**.*.**.*.*..**..***.*...*.*.....*.*.***..***....*...*.*.... Rev 114 3.6-35 ..***...*.*.*.**.* : *.*....*.***..**.*.*..*..*****.*.*.******.****..*.*.*...*.*....*.*..**..*...*.*.*..*... Rev 91 3.6-38 .*..***.***.*..*.*.*....*.*.*.*.....*.**.*..*.***.*.*.**......****...*.*......*.*.*****.*.***..*..**...**. Rev 66 3.6-39 .*..*.*******..**.*...*****.*.*.*****..*.****.**..*.*.*******.****.*.*.......*...****..*****.**.*.**..**** Rev 91 3.6-40 ..*.*.....***.*....***...**......*****..*.*.....***..*.***..*..***....*****...*.*..***...*...*....*.**..*.* Rev 86 3.6-41 ..*..*.*****.**..*.*.*.. ; .**.**..**.**..***..**..*.*.*.***..*.**.*..*.*.*..........*.*.***......*..**.*.**. Rev 86 3.6-43 ....**..*.*.*...**.*....*.*.*.*.**..*.*.**.**.*.*..* : *.******..***................. * ......................... Rev 44 3.6-45 .***..*.***..*...*......*.*.*.*.**..*...*.....*.*..*...*...**..***..*...*...*..*...*.*...*...*...*..***...* Rev 66 3.6-46 ***.*.*.*.*...*..*.***...........**.....*.*.....*..*.*.***..***..*...................*...*...**..*.**...*.* Rev 86 3.6-47 ..*.**.*.*.**.*..*.*.*.*...*..*..*****..*.**..*..*.*.*.***.****..*...**********.**...*.***...*...*..*.*.*** Rev 86 3.6-49 -51 (inclusive) .*..**.***.*..*....*.*.***.*.****..***.*.**....*.*.....*.*.*.*.*...**..*..*.*.*.. Rev 24 3.6-52 .**.**.*..* : .*..**...*...***.*...***....*.*..*.*. : .*.*..**..****.*... : ...*.**..**...**..**.*..*..*..*.*.* Rev 114 3.6-55 ***..*.*....***.*.**.....*....*..*****.*..*..*.**.....*.***.****...* , .. , .........**..*.*.*....*..*.. .*.*.* Rev 86 3.6-56 *.*..**.**.*.**.****.*.*.*.*.*.*...*.*.*.*.......**.*.*...**.***.*.*.........*...***.....*........*.*.*.* Rev 114 3.6-57 ****.*.*.*.*.**.*.***..*...**..*...*.*.*.*..*.***********.**.****..*....*.*..***.***...*.**..**.*.*.***.* Rev 126 3.6-58 **.*.*..**.***** * ............................................................................................ Rev 66 3.6-59 .*.*.***.*.*..*...******.*..**..**...*...*..*..*.*.****.********...*..*..*.*..**.*..*..*...*..*..*.*.*.*** Rev 114 3.6-59a .***.*.*.*...*.....*..*...*..**.......*.....*....*...****.* ; **.......*............*.*.*.*.....*.***...* Rev 127 3.6"59b ....*.***.**...*......*.*.**...**.**.........*.*.**.***..*..**....*....*..*.*..***...**..*....*....*.*. Rev 126 3.6-60 ..***.**.*. _..Rev 114 . 3.6-61 ... ...................................................................................................... Rev 126 3.6-62 .******.*.*.*** : .*.*.*...*.**. *.***.*.*.**.*.******.******..***.**..*.*.*..****.*.*.*....*.**.**.**.*.*... Rev 66 3.6-63 ..***.*.*.*.*.*.**.*.***...*..**..**...*.*..*.*.**...**.*.**.***.*.....*.*****. : .***.*..***.**.....*..*..* Rev 130 3.*6-63a ........ ; .* ; ............................................................................. *.......*..*.. Rev 127 3.6-63b ***.**.*..***.*..*...*...*.* * **** : .******** : *.*.*.**.*********.*...*..*.*...**....*.....*.*...........*. Rev 126 3.6-63c *...**.*.***..*.*..*.**....*.****.* *.**..***..*.*.. ***.****....*.**..**...*.**.**.*..*..*.*.*.*.*.... Rev 126 3.6-63d **.*.***.***.**.......***.**.********...*********.**..*.*.**.*.***.**.*.*...*..**..**.*....*..******.*. Rev 126 3.6-63e ****.*.*.*.*.*..**.*..*****.*.***.****.**.*.*.**** : *.*****.*.*..*****.*.***..*.**..*.*.**..*..*.******. Rev 126 3.6-63f ***.*****.*.*.*.**.***.*.***.*.******.*.*..*.*.**.*.***..****.*.**..*.***.***.*.***.***.**.**....**.**** Rev 130 3.6-639 .*...*.*.*. ; ...*....*.*.*.*.******.***.*..*...*..*.*********.**............****..*..*..* ; *.....*..*.*.. Rev 127 3.6-63h ***************-'*******************: ................................................................... Rev 126 3.6-64 *....*.**..*.***.*...*.......***..**.****.**.*.*.*.*.*****..***....*......***.*.***...**...*.**.*...*..*.*. Rev 80 3.6-70 *.*..*..*.**.*.*.*...**.*...*.**..*..****.****.*.*.**.*.***.***.*.****..***********.**.....*..*.*.****.***. Rev 80 3.6-72 ****...*.******* : ........................................................................................... Rev 86 3.6-73 *.*..*.*.*****.*..**.**.....*.*...**.*.* , ..*****.*.**.*****.**..**.**.*...***.*.***.....*..*..*.*.*..*.*.*. Rev 75 3.6-74 *..*.*.*.*.*.***..*...*... .*.**.. ; *..*....*.*.*.*. : **..*.*.*...*..*......*.**...***.*.. : .**.*....*..***... Rev 75 3.6-75 ***..*....****.*.*...***..***..**.*****.*..*.*.*.******.*.****.*..**..** .*.**.*.***....*..***.......***... Rev 75 viii ' Revision No. t39 *,.**.

PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.6 CONTAINMENT SYSTEMS (continued) page(s) 3.6-76 .......**.*....*.....*...**......*...***...*.*..*.....*.......*..*.*.**..*****.....*........*.**...*..*.. Rev 120 3.6-77 ......****..*.*.*..*..**...*..*.*****.**..****.*.*.************.....***..*****.*....****.****.****...*..*.. Rev 97 3.6-78 ..*......*.** : .............................................................................................. Rev 75 3.6-79 ......**.*..*.*.*..**.*.*..*.**.**...***...*...*......*..*..*..**....*.****..*..**.*..****..****...*.**.*.* Rev 75 3.6-81 *....*.***.*.**.***.*.......*...****...*.......*......*.**....***.**.**.*.**.*.....**..***....*......**.*** Rev 57 3.6-82 *.****..**.*.**.*...*.......*...**..*.**.*...*.*....*.*.**..*.*.*...**...***...*...*...*......*......**.... Rev 75 3.6-83 ...*.*...........*.....*.*...*..**.*..**.*.*...*....*.*..*......**..**..***.*..* : ***..**.*..***....*.*....* Rev 86 3.6-84 *.**..*..*...*..**..*.*..*.*....**.....*...*..***.*.*****.*.*.**.*.***...***.*.*.*...*.*....*.**..********* Rev 86 3.6-87 *..*.***.*.**.*.....*...*..*.***.**..*.**..*.*..*...*.**..***..***...**.***....*.******.....*..*.....**...* Rev 75 3.6-88 *..*.*********...*...*.*.******.**.*..***..**...**..*..*.*..*.......**..**..*.*....*...*.*.*.**.*....***... Rev 75 3.6-89 **..**.**.*.**.*.*.***.*..*.**.****.*..*.*..*.......*.**.**.*.**....*..***....*..*.*.**.*....**.*....*..... Rev 86 3.6-90 .*****.*....*.....*....*....*...*.....***..*........*.**.......*.*...*..***.*..*.*.***..*.....*.....**.*... Rev 86 B 3.7 PLANT SYSTEMS page(s) 3.7-1 .*..**.**.**.*.***.*..*.*.*..*..****..*.*..*..*******.*.***.**.*.*..****.**.**..*...*..*..*..*.***...*.*..* Rev 114 3.7-2 .*.*...**.**.*..*.....*.*.*.**...***..*.*.....**.*.*...*.....*.*.*.....*....*...*...*..**.*..*.**......*... Rev 114 3.7-3 **...*.**.**...**.....*.*...*.**.***.*.....*..*......*.**.**.*.*..**...*..*...*.*.*..*.****..*.**...*...... Rev 114 3.7-4 ***...***.**.**.*.****......*..*.***.....***.*.**.*...*.**.****.***..*.**.***.*.*..*.**.***....**.**..****. Rev 114 3.7-5 .*.....***.*.*..*..*..*.*..*...* : .****.****. : *.**...*.*.*...*.*.*...**..**.**.****.*.**.**..*.....*...**.*. Rev 114 3.7-5a *..*.*..*.. .**.***.*.*...*..*.* : *.....**..*.***....*.**..*.*.*....*.**.***.*......**.*.*.*..**..*..**... Rev 114 3.7-5b *....**....*..*.**..*.******..******.**.*..*.***.**.**.***.***.*..*.*********..*.*..*.**..**.**.***.*.*.. Rev 114 3.7-6 .*...*****.*.*..*...**..**....****..*...*.*.*.*..*.*.*.**.**.*.*...*..*........*.*. : ..**...*........*.**.*.... Rev 4 3.7-7 .*..*...*..*.*.**.*......*..*....*.***.*.*.**..*.*.*..**********.*..*.*.*..*.**.*.*...***...**.*.*...*.****. Rev 109 3.7-8 : **...*.**.*..*.***..*.*.*.*..****.****.**.*..***.*.*.*..**.**..***.....*.*...*.*.*..*.**.*...*****....**.. Rev 109 _3.7-9 ***....**.***..*..*.***.*.*.**.*.* : **.**...*..****.*..**..**.**.*.*...*.*...**.*.***..*.**..**..****.....*.*. Rev 109 3.7-10 *.. : ******.**..*.*.....* , *..**.***...**..*.*.**.....*...**.***.*...*....**..*.*..*.*..*.*...*.......**.***. Rev 86 3.7-11 ; .*.*.. , ....****..*....*.....*..**.. ; *.....*... ;;.* ...**.***.*.*.....**..... * ......*....* : ......*...... , ....* Rev 67 3.7-12 ***.****.*****.**.*.**.*.***....**.... : .**.*.*.*.*.*..*..**...*..*****.*..*.*... * .*.**.*.*..*.*.*.....*....* Rev 92 PBAPS UN_IT 2 3.7-13 *. : ............................................ , *.*...* ..*..*..*.*......*****.*****... * .*.**....********* : *.*.** Rev *1 * . 3.7-14 .** ; **.*.*****...*..*.*.* : *..**...** .**.*..***...*..**....*.*.*.. ; ....*.**.*.*.**.*..*.*....**..**.* : .*..* Rev 86 * ** -3.7*15 *.******..*..**...*.*.*...*.**.****.******.*****. : **..**..*.***..*..**.*..*...**.*.*..*.....*..***..**.*. Rev 116 3.7-16 *...**.** : **.**.*.*.****.**.*.****.****.*..** ; *.*. : *** ; .*** : **...*.*.*...*........******...*.****..*..*.. Rev -116 *3.7-16a ...**.*.**........***.* ;.: ..******* .*** : *.....*.*.*.** : *.*.*......*..*... ; ........................... Rev 116 3:7-16b .***..*..*.**......*.**....*.* ; ***..**.*******.*.*.***.**....**....*..* ; **.*...*..**...***......**.*..** Rev 121 3.7-17 .*...**.*****.*.* : .*..**.**.**.*.**.*.*** ; *..*** .-**.. ; ***.*...*..*..*** * .*.**...*.*..*.*.....**.*.......** Rev 116 3.7-18 ., .*.*****.*..*.*..*...*.*.***. : ............................... .-***.*.*.*******.*.* ,* .*.*.**..***....*.*... Rev .1*16 ** 3.7-19 .*...****.***.*.*......*...* : *..*.*. , .**.*...** **.**..*.**.****.*.*.*..*....*.*.*.. * ** , .**...*.*...* : ....** Rev *5a *3.1-20 ****.**.*******..*..*..*.*.*.*.**.*.*.* : **.*.*****.**.*****.*.*.****.*.**.**...*.****.*.**...**....*....*.. Rev 86 3.7-20a .*..*.******* ; ****.*.***************.***.*.*. .-: *****.***.*.* *...*.**.*****.**.**... :; **.*.**.*.*.**..* Rev 116 3.7-21 .*...****. .-******..*...*.*.*.*.***..**.*.*.... *.*..*...*..*.****..*.*.***.*...*.*...*.** : .*......*.*.*.. Rev 121 3.7-23 .******.*.**.**....*...***********.****..*.*........***.********..****..*.**.***.**.*..**.****.....**...**. Rev 66 3."(-24 .*...**.**.******..***.***...*******.**.*.**.*.*****.******.**.*****. * ............ : ***********.*************. Rev 86 3.7-25 **.***..*.**..****..****.*...*.*****..**....* : *.**....******..*.*. ; .****.*..*.*....*..**.*..**.......*.*.** Rev -136 3.7-26 **.*.*. * ....... : .***.... *** ; *.*** : *.*.**. ;; *****..*.*..*.*.*.*..*...**...*..*...*..*..****.**..*....*.*..* Rev 114 .* 3.7-27 .................................. : ........ ;*.,: ...... ;., ..*.**.**..*..***.*....*.*...*.*..**....*...*.*.*.. Rev 11_4 3.7-28 *.*.*..*****.**.****.*..**********..*.**..*..***... .-***.**.*.**..*..*.*****..*.***.*..*.*****......*.*... 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• ix Revision Nb. 139 PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.8 ELECTRICAL POWER SYSTEMS p3ge(s) 3.8-1 .*.....**.**.*.**....*.*..*.....******.*.*........**..**.**...***..*....********...*******....***.*..*.**.*... Rev 82 PBAPS UNIT 2 3.8-2 .**.*.**...*.*****..**....*.*....*.**....*.......*....**..*.*...*..*....*..**.....***.*****...**....*.**....*. Rev 90 3.8-23 .....**.*...*......*.........*.*....*..*..*.***.*.******..*.*.*.*......*..*..**..*...**.***..*....***.*...*. Rev 90 3.8-3 **..**..*.*..**......*..**********....*.*.....*.*...*..*...*...***..**........*.**...*.**...**..*........... 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.. _:, ' PBAPS UNIT 2 LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING 8 3.8 ELECTRICAL POWER SYSTEMS (continued) page(s) 3.8-64 ........................................................................................................... Rev 66 3.8-65 ........................................................................................................... Rev 86 3.8-66 ........................................................................................................... Rev 86 3.8-67 ............................................................................................................ Rev 86 3.8-69 ........................................................................................................... Rev 86 3.8-71 ........................................................................................................... Rev 66 3.8-79 ........................................................................................................... Rev 86 3.8-80 ........................................................................................................... Rev 86 3.8-89 ........................................................................................................... Rev 85 3.8-90 ........................................................................................................... Rev 85 3.8-91 ........................................................................................................... Rev 85 3.8-92 ............................... , ........................................................................... Rev 86 3.8-97 ***..**..*.**....*.*..*.*..*..*.**..**....*.***.***.*.*.*.*...**.*.*..*.***.*...*.****.....*.......**...*** Rev 86 8 3.9 REFUELING OPERATIONS page(s) 3.9-1 ................................... ; .. , ...................................................................... Rev 29 3.9-3 .............................. ; .*.* ............................................. ; ........................... Rev 29 3.9*4 ............................................................................................................. Rev 86 3.9*7 ............................................................................. ; ................... , ........... Rev 86 3.9-8 .............. : .... *.*. *.*....*.** ; *...* : .................................................................. Rev 24 3.9*9 ........................................... ................................................................... Rev. 86 ** 3.9-10 .; ............. : ..................... : ..... : ................... ........................................... Rev 24 3.9-14 .*. ; .* : ............................. : .. : ...................................... * ............................. Rev 24 * .... : ............. ; ..................................... ..... ; ..... * ........ : ................................ Rev 86 3.9-17 ......... ;.: ........ : .................................. ; ............................................. : ...... Rev 75 * . *.3.9-19 .. * ....... : ....... : ... ........... ;; .......... ...... ....... ; ........ ........................ : .............. ,Rev 86 .3.9-21-........... ;.-.... ; ........................... ;., ................... : ...................................... Rev 126 3.9-23* ............... ,; .. ..................... : ...... .".; ...................... ; ....... ; ....................... Rev 126 -3.9-23a .......... -." .............. ........ : ................................................................... Rev 127 3.9-23.b .............. ,.: *.**.*..*. ; *.*.*** ; .. *; .......... ; ........ : .*. :* **. : ................ ; ............. *...* ,.; ** Rev 126 3.9-25 ........... ; .. , .... ; ................. ; ..... * .............. : ....... : .. ; ...... ; ...... ;; ....................... Rev 126 *. 3.9-21 ....... ;: ............ :.* ............ ....... , ... :.: ........ : ....... : .................... _ ....... : ......... : .. Rev 126 -3.9-28 ..................... : ...................... *: ........ : ... :* ..................................... ............ Rev*121 . . . . . 3.9-29 **. ..................... , ...... : *.. : ... , ............. ;-........... : ........... : ............................ Rev 126 B 3.10

• SPECIAL 3.10*1 ..... , ........ : ..... ,_ .... ... :: ...... : ................ :., ..................... .' ........ ; ...................... Rev 129: 3;10-2 ........ ......... , .. ". .... '. .......... , .. : ........... ,.; .... ; ............... ; ................. * ............... Rev 129 3.10-2a .......... _ ....... : .... _ ............ , ... ................. : ...... ;.: ............................... , ..... Rev 129 3.10 .. 3 .... ........ ... : ............... ;; .... ; .. ....*... :; .................... : ......................... Rev 129 3.10-4 .: .. .. : .......... :.L .... ; .................... ..... ; ...... ,.:; ....... : .......... ............... Rev 129 . * ::::: ::::::: :: --.......... :; ...... ; ........ :; .... ; .. ; ....................... ; .. ; ............................................ Rev 86 PBAPS UNIT2 xi -Revision N.o. 139 PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.10 SPECIAL OPERATIONS (continued) page(s) 3.10-13 ................................*.....................................*...*.............................. Rev 86 3.10-18 ...*.........*.*................*....*..............*.*..........*....*.* : .....*.*..*.............*.*.... Rev 86 3.10-22 .**. ; .............*...............*.....................*...........................*.................... Rev 86 3.10-26 .................*........................................*...**..........*.*............................ Rev 86 3.10-30 .......*.....................................*..................*........................................ Rev 72 3.10-31 -.............*.*......................................................................................... Rev 24 3.10-32 ..........*.*................*.....................*.................*................................... Rev 36 3.10-33 ...........*.*........*.....*.**.*.............*...*...............*.*.*..***..*......................... Rev 63 3.10-35 ...............................*.....................................*.**.*......................... : .... Rev 86 3.10-36 ..........*...............................................................*.............................. Rev 86 All remaining pages are Rev O dated 1/18/96. PBAPS UNIT2 Revision No. 139 .

TABLE OF CONTENTS B 2.0 SAFETY LIMITS CSLs) ......................................... B 2.0-1 B 2.1.1 B 2.1.2 Reactor Core SLs .................................... B 2.0-1 Reactor Coolant System (RCS) Pressure SL* ........... B B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION CLtO) APPLICABILITY ........ B 3.0-1 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ................. B 3.0-10 B 3.1 B 3.1.1 B 3.1.2 B 3.1.3. B 3.1.4 B 3.1.5 B 3.1.6 B3.1.7 B 3.1.8 B 3.2 B 3.2.1 B 3.2.2 B 3.2.3 B 3.3 B 3.3.1.1 B 3.3.1.2 B 3 .. 3.2.l B 3 . .3.2.2 B 3.3.3.l B 3.3.3.2 B 3.3.4.1 B 3.3.4.2 B 3.3.5.1.

• B 3.3.5.2 B 3. 3 .. 6 .1 B 3.3.6.2 B 3.3.7.1 B 3.3*.8.l B 3.3.8.2 REACTIVITY CONTROL SYSTEMS .............................. B 3.1-1 SHUTDOWN MARGIN CSDM) ............................... B 3.1-1 Reactivity Anomalies ................................. B 3.1-8 Control Rod OPERABILITY ............................. B 3.1-13 Control Rod Scram Times ............................. B 3.1-22 Control Rod Scram Accumulators ..................... B 3.1-29 . Rod Pattern Control ................................. B 3.1-34 Standby Liquid Control CSLC) System ................. B 3.1-39 Scram Discharge Volume CSDV) Vent and Drain Valves .. B POWER DISTRIBUTION LIMITS ............................... B 3.2-1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE CAPLHGR) ......................................... B 3.2-1 MINIMUM CRITICAL POWER RATIO CMCPR) .. , .............. B 3.2-6 LINEAR HEAT GENERATION RATE CLHGR) ................. B 3.2-11 INSTRUMENTATION ......................................... B 3.3-1 Reactor Protection System (RPS) Instrumentation ......... B 3.3-1 Wide Range Neutron Monitor CWRNM) Instrumentation ...... *. B 3.3-36 Control Rod Block Instrumentation ....................... B 3.3-45 Feedwater and Turbine High Water Level Trip Instrumentation .................................. B 3.3-58 Post Accident (PAM) Instrumentation .... ; .... ; B 3.3-65 Remote Shutdown System .................... ; .............. B 3. 3-76 Anticipated Transient Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation .. .. .... B 3.3,83. End.of Pump Trip CEOC-RPT) Instrumentation . . . B 3.3-9la thru B .3.3-9lj Emergency Core Cooling System CECCS) Instrumentation ........................ ......... B 3.3-92 Reactor Core Isolation Cooling CRCIC) System Instrumentation .................................. B 3.3-130 Primary Cbntainment Isolation Instrumentation ........... B 3.3-141 Secondary Containment Isolation Instrumentation ......... B 3.3-169 Main Control Room Emergency Ventilation CMCREV) System Instrumentation ........................... B 3.3-180 Loss of Power CLOP) Instrumentation ..................... B 3.3-187 Reactor Protection System (RPS) Electric Power Monitoring ................................. '. ...... B 3.3-199 (continued) Rev i s fo n No . 2 5 TABLE OF CONTENTS (continued) B 3.4 B 3.4.1 B 3.4.2 B 3.4.3 B 3.4.4 B 3.4.5 B 3.4.6 B 3.4.7 B 3.4.8 B 3.4,9 B 3.4.10 B 3.5 B 3.5.l B 3.5.2 B 3.5.3 B 3.6 B 3.6.1.1 B 3.6.1.2 B 3.6.1.3 B.3.6.1.4 B 3.6.1.5. B 3.6.1.6 B3.6:2.1 B 3.6.2.:2 B 3.6.2;3 B 3.6.2.4 B 3.6.2.5 .. B 3.6.3.1. B 3.6.3.2 B 3.6:4.1 B 3.6.4.2 B 3.6.4;3 B 3.7 B 3.7.1 B 3.7.2 B 3.7.3 B 3. 7.4 B 3.7.5 REACTOR COOLANT SYSTEM (RCS) ............................ B*3.4-1 Recirculation Loops Operating ................. * ...... B 3.4-1 Jet Pumps ........................................... B 3.4-11 Safety Relief Valves (SRVs) and Safety Valves (SVs). B 3.4-15 RCS Operational LEAKAGE ............................. B 3.4-19 RCS Leakage Detection Instrumentation ............... B 3.4-24 RCS Specific Activity ............................... B 3.4-29 Residual Heat Removal ( RHR) Shutdown Cooling System-Hot Shutdown ............................. B 3.4-33 Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown ............................ B 3.4-38 RCS Pressure and Temperature (PIT) Limits ........... B 3.4-43 Reactor Steam Dome Pressure ......................... B 3:4-52 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR.CORE I SOLA TI 0 N C 0 0 LI N G ( RC I C ) SYS T EM . . . . . . . . . . . . . . . . . . . . . . . . . B 3 . 5 -1 . ECCS-Operating ..................................... B 3.5-1 ECCS-Shutdown .................... , ................. B 3.5-18 RCIC System ......................................... B 3.5-24 CONTAINMENT SYSTEMS .................... , ................ B 3.6-1 Primary Containment ..................................... B 3.6-1 Primary Containment Air Lock ............................ B 3.6-6 Primary Containment Isolation Valves (PCIVs) ............ B 3.6-14 Drywell Air Temperature* ................................. B 3.6-31 Reactor Building-to-Suppression Chamber Vacuum Breakers .... * .........*........................... B 3.6-34 Chamber-io-Drywell Vacuum Breakers .......... B 3.6-42 Suppression Pool Average Temperature.; .......... ...... B 3.6-48 Suppression Pool Water Level ............................ B 3.6-53 Residual Heat Removal (RHR) Suppression Pool
• Co.oling ................................... * ..........
• B 3*.6-56 Residual Heat Rem.oval (RHR) Suppression Pool Spray ...... B 3.6-60 Residual Heat Removal CRHR) Drywell Spray ............... B 3.6-63a Deleted.* .. ; .. * ...................................... : ....... B .3.6-64 Primary tonfainment Oxygen C6ncentration .. * ..... : ...... B 3.6-70 Sec6ndary .... , ....*...................... B 3.6-73 Secondary Containment Isolation Valves*(sCIVs) ...*...... B 3.6-78 Standby Gas Treatment (SGT) System ...................... B PLANT SYSTEMS ........................................... B 3. 7-1 High Pressure Service Water (HPSW) System ........... B 3. 7-1 Emergency Service Water (ESW) System and Normal Heat Sink .... : ..............*................... B 3.7-6 Emergency Heat Sink .............. ; .......... ; ....... B 3.7-11 Main Control Roo_m Emergency Ventilation (MCREV) System .. * ............ * ... * .............. ; ...... * ... ........ B 3. 7-*15 Main Condenser Off gas ...*..... ; ...................... B 3. 7-22 continued PBAPS UNIT 2 . Revision No. 106 ii .. 11:---TABLE OF CONTENTS (continued) B 3.7 B 3.7.6 B 3.7.7 B 3,8 B 3.8.1 B 3.8.2 B 3.8.3 B_3.8.4 B 3.8.5 B 3.8.6 B 3.8.7 B 3.8.8 B 3.9 B 3.9.1 B 3.9.2 B 3.9.3 B 3.9A B 3.9.5 -B 3.9.6 B 3.9.7 B 3.9.8 B 3.10 B 3.10.1 B 3.10.2 B 3.10,3 B 3.10.4 B 3.10:5 B 3.10.6 B 3.10.7 B 3:10.8 :, .. PBAPS UNIT 2.-PLANT SYSTEMS (continued) Main Turbine Bypass System .......................... B 3.7-25 Spent Fuel Storage Pool Water Level ........ .-........ B 3. 7-29 ELECTRICAL POWER SYSTEMS.'" .............................. B 3.8-1-AC Sources-Operating ........... ; ................... B 3.8-1 AC Sources -Shutdown .............. ; ................ B 3. 8-40 Diesel Fuel Oil, Lube Oil, arid Starting Air ......... B 3.8-48 DC Sources-Operating ............................... B 3.8-58 DC Sources -Shutdown . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3. 8-72 Battery Cell ........*.................... B 3.8-77 Distribution Systems-Operating ........ : ... ........ B Distribution Systems-Shutdown ...................... B 3.8-94 REFUELING OPERATIONS .................................... B 3.9-1 Refueling Equipment_ Interlocks ........*.............. B 3. 9-1 -Refuel Position One-Rod-Out Interlock ............... B 3.9-5 Control Rod Position ................................ B 3.9-8 Control Rod Position Indication ..................... B 3.9-10 Control Rod OPERABILITY-Refueling .................. B 3.9-14 Reactor Pressure Vessel (RPV) Water Level ; .......... B 3.9-17 Residual Heat Removal (RHR)-High Water Level ....... _B 3.9-20 Residua 1 Heat Remova 1 ( RHR) -Low Water Leve 1 _; . . . . . . . B 3. 9-24 ' . . . ' . . "' . SPECIAL OPERATIONS ........ ............................. B 3.10-1 Inservice Leak _and Hydrostatic Testing Operation .... B 3.10-1 Reactor Mode Switch Interlock Testing ............... B 3.10-5 -Single Control Rod Withdrawal-Hot Shutdown ......... B 3.10-10 Single Control Rod Withdrawal.,.-Cold Shutdown ..... ; .. B 3.10-14 Single Control Rod Ori ve' (CRD) --Removal -Refueling-.......... ,; ..... : ............. B 3.10-19 Muhiple Control Rod Withdrawal-Refueling ........... B 3.10-24 Control .Rod Testing-Operating .. : ............... -.... B 3.10-27 SHUTDOWN-MARGIN (SOM) Test-Refueling ............... B 3.10-31 iii Revision No. O Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS (SLs) B 2.1.1 Reactor Core SLs BASES BACKGROUND PBAPS .UNIT 2 SLs ensure that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and abnormal operational transients. The fuel cladding integrity SL is set such that no fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that 99.9% of the fuel rods avoid transition boiling. Meeting the SL can be demonstrated by analysis that confirms no more than 0:1% of fuel rods in the core are susceptible to transition boiling or by demonstrating that the MCPR is not less than the limit specified in Specification 2.1.1.2 for General Electric (GE) Company fuel. MCPR greater than the specified limit represerits a conservative margin relative to the conditions required to maintain fuel cladding integrity. The fuel cladding one of the physical that separate the radioactive from the environs. The integrity of this cladding is related to its
• freedom from perforations or cracking. Although some corrosion or use cracking may occur during the life of .the cladding, fission product migration from this source 'is cumulative and continuously measurable .. Fuel cladding perforations, however, can result from thermal stresses, which occur from reactor above destgn conditions. While. fission. pr.oduct migration.from. cladding' perforation is just that from use related cracking, the caused ciadding' perforations signal a threshold beyond*Which.st.ill greater therinal stresses may cause gross,. rather than incre.ment'al, cladding deterioration, Therefore, . the*fue'l .. claddfog S[ .is define.d with a margin to the . .. c'onditions that would produce, onset of tra-nsition boiling ' (i.e., MCPR = These conditions tepresent a depirture the condition intended by design for planned' operation.. The MCPR fuel cladding integrity SL ensures ,that during'nqr.mal operation and during abnormal -operati bnal b"ansi ents, at 1 east 99. 9% of the fuel rods in the core a6 not experience transiti6n boiling. (continued). : .,.. Revision No. 98
• BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES Reactor Core Sls B 2.1.1 Operation above the boundary of the nucleate boiling regime could result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding water (zirconium water) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant. The reactor vessel water level SL ensures that adequate core cooling capability is maintained during all MODES of reactor operation. Establishment of Emergency Core Cooling System initiation setpoints higher than this safety limit provides margin such that the safety limit will not be reached or exceeded. The fuel cladding must not sustain damage as a result of normal operation and abnormal operational transients. The reactor core SLs are established to preclude violation of the fuel criterion that a MCPR limit is to be established, such that at least 99.9% of the fuel rods in the core would not be expected to the onset of transition boiling. The Reactor Protection sYstem setpoints (LCO 3.3.1.1, "Reacto*r Protection Systeni (RPS) Instrumentation"), in combination with other LCOs, are designed to prevent any anticipated combination of transient conditions for Reactor Cool ant _System water -level, pressure, and THERMAL POWER level that result_ in reachirig the MCPR limit.
• 2.1.1.1 Fuel Cl*addind Iriteqrity _GE, crit-i cal_ power correlations are applicable for all critical power 700 psi a and flows 10% of rated-operation at.low pressures or low flows, another basis is used, as follows: Th e p re s s u re d r op i n t h e by p a s s reg j on i s e s s en t i a lJ y all elevation head with a value_> 4.5 psi; therefore, the core pressure dr,op at 1 ow power and flows wi 11 be> 4.5 -psi. At head insirje continued B Revision No. 128 BASES APPLICABLE SAFETY ANALYSES -.
• PBAPS UNIT 2 Core SLs B 2.1.1 2.1.1.l Fuel Cladding Integrity (continued) the bundle is less than the static head in the bypass region because the addition of heat reduces the density of the water. At the same time, dynamic head loss in the bundle will be greater than in the bypass region because of two phase flow effects. Analyses show that this combination of effects causes bundle pressure drop to be nearly independent of bundle power when bundle flow is 28 X 103 lb/hr and bundle pressure drop is 3.5 psi. Because core pressure drop at low power and flows will always be> 4.5 psi, the bundle flow will be> 28 X 10 3 lb/hr. Full scale ATLAS test data taken at pressures from 14.7 psia (0 psig) to 800 psia (785 psig) indicate that the fuel assembly critical power with bundle flow at 28 X 103 lb/hr is approximately 3.35 MWt. This is equivalent to a THERMAL POWER> 50% RTP even when design peaking factors -a-re considered. Therefore, a THERMAL POWER limit of 23% RTP for reactor pressure < 700 psia is conservative. Additional information on low flow conditions is available in Reference 4. 2.1.1.2 MCPR The fuel cladding integrity SL is set such that fuel damage is calculated to occur if the limit is not violated. the that result in fuel damage are not di rect.l y observable during .reactor operation, the thermal and* hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur. Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power. Therefore, continued Revisicin Nb. 128 *1:'.

.. / BASES APPLICABLE SAFETY ANALYSES PBAPS UN IT 2. 2.1.1.2 MCPR (continued) Core SLs B 2.1.l the fuel cladding integrity SL is defined as the critical power ratio in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition, considering the power distribution within the core and all uncertainties. The *MCPR SL is determined using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined the approved General Electric Critical Power correlations. Details of the fuel cladding integrity SL talculation are given in Reference 1. Reference 1 also includes a tabulation of the uncertainties used in the determination of the MCPR SL and of the nominal values of the parameters used in the MCPR SL statistical analysis. 2.1.1.3 Vessel Water Level During MODES 1 and 2 the reactor vessel water level is to be above the top of the active fuel to provide core cooling capability. With fuel in the reactor vessel during periods when the reactor is shut down, consideraticin must be given to water level requirements due to the effect of decay heat. If the water should drop below the top 0 f the act i v e i r rad i ate d fuel du r i n g th i s p.e r i 0 d ' the . ability to remove decay is reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation. The core can be adequately cooled as long as water level is above 2/3 of the c o re h e i g h t . Th e r e a ct or v e s s e l w a t e r l e v e l S L h a s been established at the top of the active irradiated fuel to *provide a point that cari be monitored and to also adequate margin for effec!ive action. (conti_nued} B 2.0-4 Revision No. 47 11: :* BASES *(continued) SAFETY LIMITS. APPLICABILITY SAFETY* LIMIT VIOLATIONS . PBAPS UNIT 2 Reactor Core SLs B 2 .1 .1 The reactor core SLs are established to protect the integrity of the fuel clad barrier to the release of materials to the environs. SL 2.1 .1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria. SL 2.1.1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations; SLs 2.1.1.1, 2.1.1.2, and are applicable in all MODES. Exceeding an SL may cause fuel damage and create a potential for radioactive releases in of 10 CFR 100, "Reactor Site Criteria," limits (Ref. 2) and 10 CFR 50.67, "Accident Source Term,>> for analyzed using AST (Ref 3). Therefore, it is to insert all insertable control rods and restore with the SLs within 2 hours. The 2 hour.Completion Time ensures.that the operators take prompt* action and also ensures that the probability of an accident occurring during this period is minimal. (continued) B 2.0-5 Revision 75 *. BASES REFERENCES PBAPS UN IT 2 Reactor Core Sls B 2.1.1 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," la test approved revision. 2. 10 CFR 100. 3. 10 CFR 50.67. 4. SIL No. *516 Supplement 2, January 19, 1996. *'. *, B 2.0-6 Revision No. 128 I I, RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs) B 2 .1: 2 Reactor Cool ant System (RCS) Pressure SL BASES BACKGROUND I -. --* . . . SAFETY ANALYSES * **< . * ;:* *** . --'.-PBAPS-JJNIT_ 2 The SL on reactor steam dome pressure protects the RCS against overpressurizati6n. In the event of fuei cladding failure, fission are released into the reactor coolant. The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere. Establishihg an upper limit on reactor steam dome pressure ensures continued RCS integrity with regard to pressure excursions. Per the UFSAR (Ref. 1), the reactor coolant pre!)sure boundary (RCPB) shall be designed with sufficient margin to ensure that the design conditions.are nc:it*exceeded during norrrial operation and abnormal operational transierits:

• During hormal operation and abnormal operational transients, RCS pressure is limited from exceeding the design pressure by more thari 10%,. in accordance with Section III of the ASME Code (Ref. 2) ; To ensure system integrity., . al 1 RCS components are hydrostaticall y tested at 125% of design pressure; i:naccordance with ASME Code requirements, prior to i ni ti al operation when there is no fuel in the core. Any further: hydrostatic testing. with 'fuel 'in the core may be *' done under :LCD. 3.1o. f,* ."Inservice Leak* and Hydrostatic** . Testing Operation." FolloiN.irig inception of u.nit operation, RCS cqmpoherits shall be pressure tested i ri.* 'accordance with the. requirements of ASME *code,. Section XI (Ref. 3). . Overpres$urization bf t.he RCS could result* in. a breach of * **.the *RGPB>reduci ng the, number of protective barriers designed 'to .prevent: releases from exceeding the limits specified in :*10 CFR 50;*67*; *"Accident.Source Term," (Ref. 4f. If *this occurrecf1n<coil]unction with .a,.fuel cladding
• prod.ucts' could enter the c6nh1inment * * * -,***.' ' The RCS_ and _the, React:o:r Systeif{ :f{0aGtor -FUncti a*n set"ti n*g*s * * * -* established . to etisure that the RCS pr_e*ssure. wi 1 T
• not be 'exceeded.' * . .,, . (continued) * .. r*. . . ' . . . . . -. . ., ... *,... Revi siori No:.*. 75 ,,-* J BASES APPLICABLE SAFETY ANALYSES (continued) SAFETY LIM ITS APPLICABILITY SAFETY LIMIT V IO LAT I 0 NS . PBAPS UN IT 2 RCS Pressure SL* B 2.1.2 The RCS pressure SL has been selected such that it is at a pressure below which it can be shown that the integrity of the system is not endangered. The reactor pressure vessel is designed to Section III, 1965 Edition of the ASME, Boiler and Pressure Vessel Code, including Addenda through the winter of 1965 (Ref. 5), which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig. The SL of 1325. psi g, as measured in the reactor steam dome, is equivalent to 1375 psig at the lowest elevation of the RCS. The RCS is designed to the ASME Section III, 1980 Editiori, including Addenda through winter of 1981 (Ref. 6), for the reactor recirculatfon piping, which permits a maximum pressure transient of 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes. The maximum transient pressure allowable in the RCS pressure vessel under the ASME Code, Section III, is 110% of design pressure. The maximum transient pressure allowable in the RCS piping, valves, and fittings is 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The most of.these is the 110% of design pressures of 1250 psig; therefore, the .SL on maximum allowable RCS pressure is established at 1325 psig, measured at the steam dome. SL 2.1.2 applies in all MODES. continued B Revision No. 57 BASES SAFETY LIMIT VIOLATIONS (continued) REFERENCES PBAPS UNIT 2 RCS Pressure SL B 2.1.2 Exceeding the RCS pressure SL may cause immediate RCS failure and create a potential for radioactive releases in excess of 10 CFR 50.67, "Accident Source Term," limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours. The 2 hour Completion Time ensures that the operators take prompt remedial action and also assures that the probability of an accident occurring during the period is minimal. 1 . UFSAR, Section 1.5.2.2. 2. ASME, Boiler and Pressure Vessel Code, Section III,
• Article NB-7000. (continued) 'B 2.0-9 .** Revision No. 75 BASES REFERENCES (continued) PBAPS UNIT 2 3. RCS Pressure SL B 2.1.2 ASME, Boiler and Pressure Vessel Code, Section XI, Article IW-5000. 4. 10 CFR 50.67. 5. ASME, Boiler and Pressure Vessel Code, Section III, 1965 Edition, including Addenda to winter of 1965. 6. ASME, Boiler and Pressure Vessel Code, Section III, 1980 Edition, Addenda to winter of 1981. B 2.0-10 Revision No. 75 LCD Applicability B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION CLCO) APPLICABILITY BASES LC Os LCD 3.0.1 LCD 3.0.2 . P.BAPS UNIT 2 LCD 3.0.1 through LCD 3.0.8 establish the general requirements applicable to all Specifications in Sections 3.1 through 3.10 and apply at all times, unless otherwise stated. LCD 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when the. LCD is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of. each Specification). LCD 3.0.2 establishes that upon discovery of a failure to meet an LCD, the associated ACTIONS shall be met. The Completioh Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered .. The establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCD are not met. This establishes that: a. Completion of the Required Actions within the specif{ed times constitutes compliance with a Specification; and .b.* Completion of the Required Actions is not required when*an LCD is met within the specified_ Completion ynless *There .,are two basfrtype:s of Required Actions. The fit st type bf spetifies a limit in which the LCD must be met. -This time lirri1t is the Completion lime to restore an inoperable.system or component to.OPERABLE status or to restore var.iables to within specHied Ji_mits .. If.this type of Requi rect Action is i;oLcompl eted within the specif1ed-Completion a may be required to place th*e unit 1n a MODE or condition in whi.ch the is not applicable. (Whether stated as a RequiredcAction or not, correction of the entered Condition is an action* that may always be considered entering .... ACTIONS:) *The* second type of 'Required Action specifies the . (continued) Revision No. 100 ; .

I . BASES LCO 3.0.2 (continued) PBAPS -UN IT 2 LCO Applicability B 3.0 remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation. Completing the Required Actions is not required when an LCO is met or is no longer applicable, unless otherwise stated in the individual Specifications. The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Condition no longer exists. The individual LCO's ACTIONS specify the Required Actions where this is the case. An example of this is in LCO 3.4.9, "RCS Pressure .and* Temperature The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The reasons for intentionally relying -0n the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, or investigation of operational problems .. ***Entering ACTIONS for these reasons must be done in a manner that does not compromise safety._ Intentional entry into ACTIONS should not be made for ()perational convenience. Alternat.ives that would not result in -redµndarit equipment being inoperable should be used instead. Doing so limits the time both subsystems/divisions of a safety function are inoperable and limits the time other conditions exist which result in LCO 3;0.3 being entered. Individual Specifications may specify a time 1 imit for

• performing an SR when equipment is removed from service or -bypassed for testing. In this case, the Completion Times of the Required Ac_tions are. applicable when this time limit* expires, if the equipment remains removed from service or bypassed. -When a*change in MODE or.other specified condition is required to comply with Required Actions, the unit may enter a MODE other specified condition in which another Specification becomes applicable. In this case, the Completion Times of the associated Required.Actions would -apply from the potnt in time that the new Specification . becomes ap*plicable and the ACTIONS Condition(s) are entereQ. (continued) B 3. 0-2 * -Revision No. o LCO Applicability B 3.0 BASES (continued) LCO 3.0.3 PBAPS UNIT 2 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and: a. An associated Required Action and Completion Time is not met and no other Condition applies; or b*. The condition of the unit is not specifically addressed by the associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Sometimes, possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the_ACiIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately. This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. It is not .intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being i nop.erab 1 e.
• Upon entering LCO 3.0.3, 1 hour is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the. load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to reach lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times. (continued) B Revlsion No.O BASES LCO 3.0.3 (continued} PBAPS *UN.IT 2 LCO Applicability 8 3.0 A unit shutdown required in accordance with LCO 3.0.3 may be terminated and LCO 3.0.3 exited if any of the following occurs: a. The LCO is now met. b. A Condition exists for which the Required Actions have now been performed. c.. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited . . The time limits of Specification 3.0.3 allow 37 hours for the unit to be in MODE 4 when a shutdown is required during MODE I operation. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for reaching the next lower MODE applies. If a lower MODE is reached in less time than allowed, however, the total allowable time to reach MODE 4, or other applicable MODE, is not reduced. For example, if MODE 2 is reached in 2 hours, then the time allowed for reaching MODE 3 is the next II hours, because the total time for reaching MODE 3 is not reduced from the allowable limit of I3 hours. Therefore, if remedial measures are co.mpleted that would permit a return
• to MODE I, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed. In MODES I, 2, and 3, LCO 3.0.3 provides for
• Conditions not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 4 and 5 because the unit is already in the most restrictive Condition required by LCO 3.0.3. The requirements of *
• LCO 3.0.3 do not apply in othet specified conditions of the Applicability (unless in MODE I, 2, or 3) because the ACTIONS of individual Specifications sufficiently define the .remedial measures to be taken. Exceptions to LCO 3.0.3 are provided in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the. associated condition of the unit. An example of this is. in LCO 3.7.7, "Spent Fuel Storage Pool Water Level." LCO 3.7.7 has ari Applicability of "During .movement of fuel assemblies (continued) B 3.0-4 Revision No. o BASES LCD 3.0.3 (continued) LCO 3.0.4 .PBAPS UNIT 2 LCO Applicability B 3.0 in the spent fuel storage pool." Therefore, this LCD can be. applicable in any or all MODES. If the LCD and the Required Actions of LCD 3.7.7 are not met while in MODE 1, 2, or 3, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCD 3.7.7 of "Suspend movement of fuel assemblies in the spent fuel storage pool" is the appropriate Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications. LCO 3.0.4 establishes limitations on changes .in MODES or other specified conditions in the Applicability when an LCD is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when unit conditions are such that the requirements of the LCD would not be met, in accordance with LCD 3.0.4.a, LCD 3.0.4.b, or LCD 3.0.4.c. LCD 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the LCO not met when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Compliance* with Required Actions that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the MODE change. Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made in accordance with the provisions of the Required Actions. LCD 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the LCD not met after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the and establishment of risk management actions, if appropriate. The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities be assessed and managed. The risk assessment, for the purposes of LCD 3.0.4.b, must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidarice in Section 11 of NUMARC 93-01, "Industry (continued) B 3.0-5 Revision No. 52 BASES LCD 3.0.4 (continued) PBAPS -UN IT 2 LCD Applicability -B 3.0 Guideline for Mon1toring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing such that the of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability. LCD 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and The reiults of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified in the Applicability, and any corresponding risk actions. The LCD 3.0.4.b risk assessments do not have to be documented. The Specifications allow continued operation with equipment in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified cond_iti ons in the Appl i ca bi l ity of the the.use of the* LCD 3.0.4.b allowance should be generally ac_ceptable; as Jong as the risk is assessed and managed as above. H6wevef there is a small subset of *systems and-components that have determined to be more important to risk and use of the LCD 3.0.4.b allowance is The:LCOs* governing these system and components contain Notes prohjbiting the use of LCO 3.0.4.b __ by stating that L.CO 3_.0.4.b is not applicable. -LCD .3 0 .4, c:: .. a llciws entry i ntb a MODE or other specified* coridition in the the lCO met based on Note in the Specification which states LCD 3.0.4.c is applicable. __ These_ specific allowances permit entry into MODES or other conditions in the Applicability when the __ associated ACTIONS to be entered do not provide for operation an unlimited period of time and a assessment has -not been This allowance may apply to_ the ACTIONS or to i specific Required Action of a .Specjficati on. The risk assessments performed to justify the: use of LCO usually only consider systems and component? .. For this reason, _LCO 3.0.4.c is typically to Specifications describe values ahd (continU.edJ _ B 3.0-5a Revision No. 52* I* ;

BASES LCO 3.0.4 (continued) LCO 3.0.5 . PBAPS UN IT 2 LCO Applicability B 3.0 parameters (e.g., Reactor Coolant System specific activity), and may be applied to other Specifications based on NRC plant-specific approval. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE

• status before entering an associated MODE or other specified condition in the Applicability. The provisions of LCO 3.0.4. shall not. prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4. Upon entry into a MODE or other condition in the Applicability with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry into the applicable Conditions* and Required Actions until the Condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification. do to be performed bn the equipment (or on variables the specified limits), as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of* SR 3.0.1 SR 3.0.4 for any Surveillances that have not beeti performed on inoperable eq8ipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or Nari able within limits) and restoring compliance with the LCO; * * . . . . LCO 3.0;5 the ai1owance for equipment to service under tontrols it has removed from service or declared inoperable to comply with ACTIONS. *The sole purpose of this Specification is. to provide ari exception to,*LcO 3.0.2 (e.g., *to. not comply with the applicable Action(s)) to al the performante
• of SRs t6 demonstrate:
• a. *The OPERABILITY of the equipment being to* ser.vice; *.or* ,,*. b. The OPERABILITY of other equipment. continued
• B*J.0-6 Re vi s'fon 52 BASES LCO 3.0.5 (continued) LCO 3.0.6 PBl\PS UNIT 2 LCO Applicability B 3.0 The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the allowed SRs. This Specification does not provide time to perform any other preventive or corrective maintenance. An example of demonstrating the OPE.RABILITY of the equipment bei*ng returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the SRs. An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occur.ring during the performance of an SR on another channel in the other trip system. A similar example of . demonstrating the OPERABILITY of other equipment is taking inoperable channel or trip system out of the tripped condition to permit the logic to function and indicate the appropriate response during the performance of an SR on another channel in the same trip system. LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that have an LCO specified in the Technical Specifications (TS). This ex*ception is provided because LCO 3.0.2 would require that the Conditions.and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support systems' LCO's Required Actions. These Required Actions may include entering the supported system's Conditions. and Required Actions or may specify other Required Actions. When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support. and supported (continued) B 3.0-7 Revision No.* 0 BASES LCO 3 .0. 6 . (continued) LCO 3. 0. 7 .. PBAPS UNIT 2 LCO Applicability B 3.0 systems' LCOs' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the support system's Required Actions. However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system. This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's . Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2 . . Specification 5.5.11, "Safety Function Determination Program (SFDP),11 ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6,. an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding . exception to entering supported system Conditions and
• Required Actions. The SFDP implements the requirements of. LCO 3.0.6. Cross division checks. to identify a loss of safety function for those support systems that support safety systems *are required. The cross division check verifies that the
• supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained. If this evaluation determines that a loss of safety function exists, the appropriate Conditions and.Required Actions of the LCO in which the loss of safety function exists are required to be entered. There are certain special tests and operations required to be performed at .various times over the life .of the unit. These special tests and. operations are necessary to demonstrate select unit performance characteristics, to performspecial maintenance activities, and to perform (continued) B 3.0-8 RevisionNo. 0 BASES LCO 3.0.7 (continued) LCO 3,0.8 PBAPS UNIT 2 LCO Applicability B 3.0 special evolutions. Special Operations LCOs in Section 3.10 allow specified TS requirements to be changed to permit of these special tests and operations, which otherwise could not be performed if required to comply with the of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect. The Applicability of a Special Operations LCO represents a condition not necessarily in compliance with the normal requirements of the TS. Compliance with Special Operations LCOs is optional. A special operation may be performed either under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Special Operations LCO, the requirements of the Special Operations LCO shall be followed. When a Special Operations LCO requires another LCO to be met, only the requirements of the LCO statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other LCO not be met, the ACTIONS of the Special Operations LCO apply, not the ACTIONS of the other LCO). However, there are instances where the Special Operations LCO's ACTIONS may direct the other LCO's ACTIONS be met. The Surveillances of other LCO are not required to be met, unless specified in the Special Operations LCO. If conditions exist such that the Applicability of any other LCO is met, all the other LCO's requirements (ACTIONS and SRs) are required to be concurrent with the requirements of the Special Operations LCO. LCO 3.0.8 establishes conditions under which systems are considered to remain capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more snubbers not capable of performing their associaied support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or repair of one or more snubbers not capable of performing their associated support function(s) and. appropriate compensatory measures are specified in the continued B 3.0-9 Revision No. 100 BASES LCO Applicability B 3.0 LCO 3.0.8 (continued) snubber requirements, which are located outside of the Technical Specifications CTS) under licensee control. The snu.bber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for* control by the licensee. If the allowed time expires and the snubber(s) are unable to perform their associated support function(s), the affected supported system's LCO(s) must be declared not met and the Conditions and Required Actions entere9 in accordance with LCO 3.0.2. LCO 3.0.8.a applies when one or more snubbers are not capable of providing thei.r associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system. LCO 3.0.8.a allows 72 hours to restore the snubber(s) before declaring the supported system inoperable. The 72 hour Completion Time is reasonable based,nn the low probability of a seismic event concurrent with an that require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the of the redundant train cif the supported system. LCO 3.0.8.b.applies or more snubbers are not capable of provi4ing their support function(s) to more 'than one train or subsystem 6f. a multiple train or subsystem supported LCO 3.0.8.b allows 12 .hours to restore the before declaring the system inoperable. The 12 hoDr Completion Time is reasonable based on the low probability of a seismic event co.ncurrent with an event that would r-equi re* opera ti on *of the supported system occurring* while the is Care)* n6t capable of performing their support function(s). *
• When applying 3.0.8.a or LCO 3.*o.8:b one *of the following *
• two means o.f heat removal must be available 1} at least one *hi.gh pressure*ma.keup *path (i.e., using high pressure coolant * *.* injection CHPCir or reactor core isolation cooling (RCIC)) *
• and heat.removal capability (i.e., suppressi.on pool cooling), a minimDm of *supporting equipment required for success, 'not associated with the inoperable snubber(s), or 2)
• ai .pressure path Ci low coolant CLPCI) or core spray (CS)) and heat removal capabi-lity* Ci .e., suppressiqri pool cooling or shutdown_* cooliyig); including a minimum set of supporting*equipment, not assdciated with the snubber(s).
• continued PBAPS UN)T 2 B 3.0-9a. Revision No. 100 BASES LCO 3.0.8 (continued) --:<'-;. *PBAPS UNH 2 LCO Applicability B 3.0 LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated* into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of and components when one or more snubbers.are not able to perform their associated support fund ion. LCO 3:0.8 does not apply to non-seismic functions of snubbers; Prior to using LCO 3.0.8.a for seismic snubbers that may also have non-seismic functions, it must be confirmed that at least one train of each system that is by the inoperable snubber(s) would remain capable of petforming the system's required safety or support for postulated design loads other than seismic loads, LCO 3.0.8.b is not to be applied to seismic snubbers that also *have non-seismic functions. B 0-9b .Revision No. 107 SR Applicability . B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 . . . PBAPS. UNIT 2 SR 3.0.l through SR 3.0.4 establish the general requirements applicable to all Specifications in Sections 3.1 through 3.10 and apply at all times, unless otherwise stated. SR*. 3. 0. I es tab 1 i shes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. _This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.
• Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is -to be construed as implying that systems or components are OPERABLE when: a. The* systems or components are known to be inoperable, although still meeting the SRs; or b. The requirements of the *surveillance(s) are known to be not met between required.Surveillance performances. Surveillances do not have to be performed when the unit is in a* MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise The SRs associated with a . . Special Operations LCO are only applicable when the Special Operations LCO is used as an allowable exception to the requirements of a Specification. Survei 11 ances, inc 1 udi ng Survei 11 ances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status. * (continued) B 3.0-10. Revision No ... o BASES SR 3. 0.1 (continued) SR 3.0.2 PBAPS UNIT. 2 SR Applicability B 3.0 Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed. Some examples of this process are: a. Control Rod Drive maintenance during refueling that requires scram testing at> 800 psi. However, if other appropriate testing is satisfactorily completed and the scram time testing of SR 3.1.4.3 is satisfied, the control rod can be considered OPERABLE. This allows startup to proceed to reach 800 psi to perform other necessary testing. b. High pressure coolant injection (HPCI) maintenance during shutdown that requires system functional tests at a specified pressure. Provided other appropriate testing is satisfactorily completed, startup can proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary µost maintenance testing . . SR 3.0.2 establishes the requirements for meeting the . specified Frequency for Surveillances and any Required Action with*a Completion Time that requires the periodic performance of the Re qui red Action on a "once per ... 11
• interval.
• SR 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities). (continued) B 3.0-Il Revfaitin No. *o BASES SR 3.0.2 (continued) SR 3.0.3 .. PBAPS UNIT 2 SR Applicability B 3 .0 The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply. These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. Therefore, "hen a test interval is specified in the regulations, the test interval cannot be extended by the TS, and the SR include a Note in the Frequency stating, "SR 3.0.2 is not applicable." An example of an exception when the test interval is not specified in the regulations is the Note in the Primary Containment Leakage Rate Testing Program, "SR 3.0.2 is not applicable." This exception *is provided because the program already includes extension of test intervals. As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per ... " basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedfal action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner. The provisions of SR 3.0.2 are not intended to be used repeatedly merely as an operational convenience to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified. SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Frequency. A delay period of up to 24 hours or up to the limit of the specified (continued) B 3.0-12 Revision No. 6 J f BASES SR 3.0.3 (continued) ... .-PBAPS UN IT 2 SR Applicability B 3.0 Frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met. This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance. The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a* Surveillance with a Frequency based not* on time intervals, but upon specified unit conditions, operating situations, br requirements of regulatiDns (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved
• exemptions1 etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillarice. Howeverr there is not a interval specified, the missed Surveillance should be performed at the first dpporturiity. * *
• SR 3.0.3 a time limit for, arrd allowances for the of, Surveillances that become applicable as a consequence of MODE changes imposed by Requifed Actions. Failure lo comp.ly with specified 'Frequenci*es for SRs is *.expected. to be an infrequent occurrence. Use of the delay period established by, SR is .a flexibility which is not intended t_o be as. *an operational convenience to extend* . Surveillance intervals. While up to 24* hours or the li1T1it . of the is provided to the missed it ii the"missed *surveillance will be performed at.the first reasonabl'e Qpportun1ty. The determination of the fi-rst reasonable opportunity should include consideration of the.impact on plant risk (from delaying the Surveillance .as well as any plant changes or the plant t6 the *surveill ahce) and -imp(lct on (:lny analysis assumptions, in addition to unit conditions, planning, availability of and the time.required the
• Surv.ei ll (:lnce: .* This.risk imp act should be managed throDgh continued B 3.0-13 Revision No. 1 BASES SR 3.0.3 Ccont1nued) SR 3.0.4 PBAPS UN IT 2 -SR Applicability B 3.0 the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, 'Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants.' This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The *missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the licensee's Corrective Action Program. If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Ccinditions begin immediately upon expiration of the delay If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the* Required Actions for the applicable LCO Conditions begin immediately _upon the failure of the Surveillance. Completion of the Surveil_lance within the delay period allowed by this within the Completion Time of the ACTIONS, restores compliance with _SR 3.0.1. SR-3.0.4-the requirement that all ?PPlicable SRs must be met before into a MODE or specified condition *;n the Applicabi.lity. -Thi_s Speci fl ca ti on ensures that system and component OPERAB IUTY requirements and. -va ri ab 1 e 1 i mi ts a re niet before entry into MODES or other specified conditions in the Applicability for wh_ich these systems and components ensure safe opera ti on of the _unit. -The -provisions. of this -_ Specification should not be interpreted as endorsing the _ failure to-exercise the good practice of restoring systems or to OPERABLE status before an MODE or other specified condition the Applicability.'. A provis\on is in.eluded to_ allow entry into a.MODE_ or.other specified condition in the Applicability when an LCO is not met du*e to Survei 11 a nee not being met i"n accordance with LCD 3.0.4. ' continued B 3.0:14 Revision No. 52 I BASES SR 3.0.4 (continued) PBAPS UN IT 2 SR Applicability B 3.0 However, in certain circumstances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in* an SR 3.0.4 restriction to changing-MODES or other specified conditions of the Applicability. However, since the LCD is not met in this instance, LCD 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3. The provisions of SR 3.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or bther specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4. The'.precise requirements for performance of SRs are specified such that exceptions to SR 3.0.4 are not -necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or specified condition in the Applicability of the associated LCD prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO's _ Applicability, would have its Frequency specified such that it is not "due" until the specific conditions needed are met. Alternately, the Surveillance may be stated in the form of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency. B 3.0,15 Re vision -No. 52 SOM B 3.1.1 B 3. I REACTIVITY CONTROL SYSTEMS B 3.1.1 SHUTDOWN MARGIN (SOM) BASES BACKGROUND SOM requirements are specified to ensure: a. The reactor can be made subcritical from all operating conditions and transients and Design Basis Events; b. The reactivity 'transients associated with postulated accident conditions are controllable within acceptable limits; and c. The reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition. These requirements are satisfied by the control rods, as described in the UFSAR Section 1.5 (Ref. 1), which can compensate for the reactivity effects of the fuel and water temperature changes experienced during all operating conditions. APPLICABLE The control rod drop accident (CRDA) analysis (Refs. 2 SAFETY ANALYSES and 3) assumes the core is subcritical with the highest worth control rod *withdrawn. Typically, the first control rod withdrawn has a very high reactivity worth and, should the core be critical during the withdrawal of.the first control rod, the consequences of a CRDA could exceed the PBAPS UNIT 2 -fuel damage limits for a CRDA (see Bases for LCO 3.1.6, "Rod Pattern Control"). Also, SOM is assumed as an initial **. condition for the control rod removal error during refueling. (Ref. 4) and fuel assembly insertion error during refueling -(Ref. 5) The analysis of these reactivity insertion assumes the interlocks are OPERABLE when the reactor is in the refueling mode of operation .. These interlocks prevent the withdrawal of more than one control rod from the core during refueling. (Special consideration and requirements for multiple control rod withdrawal during refueling are covered in Special Operations LCO 3.10.6, "Multiple Control Rod Withdrawal-Refueling.") The analysis assumes this. condition is acceptable since the core will be shut down with.the highest worth control rod withdrawn, if adequate (continued) B 3. l-1 . Revision No. 0 BASES APPLICABLE SAFETY ANALYSES (continued} LCD APPLICABILITY
• ACTIONS PBAPS UNIT 2 SDM B 3.1.1 SOM has been demonstrated. Prevention or mitigation of reactivity insertion events is necessary to limit energy deposition in the fuel to prevent significant fuel damage, which could result in undue release of radioactivity . . Adequate SOM ensures inadvertent criticalities and potential CRDAs involving high worth control rods (namely the first control rod withdrawn) will not cause significant fuel damage. SOM satisfies Criterion 2 of the NRC Policy Statement. The specified SOM limit accounts for the uncertainty in the demonstration of SOM by testing. Separate SOM limits are provided for testing where the highest worth control rod is determined analytically or by measurement. This is due to the reduced uncertainty in the SOM test when the highest worth control rod is determined by measurement. When SDM is demonstrated by calculations not associated with a test (e.g., to confirm SDM during the fuel loading sequence), additional margin is included to account for uncertainties in the calculation. To ensure adequate SOM during the design process, a design margin is included to account for uncertainties in the design calculations (Ref. 6). In MODES 1 and 2, SOM must be provided because subcriticality with the highest worth control rod withdrawn is assumed in the CROA analysis (Ref. 2). In MODES 3 and 4, SOM is required to ensure the reactor will be held subcritical with margin for a single withdrawn control rod. SOM is required in MODE 5 to prevent an open vessel, inadvertent criticality during the withdrawal of a single control rod from a core cell containing one or more fuel assemblies (Ref. 4) or a fuel assembly insertion error (Ref. 5). With SOM not within the limits of the LCO in MODE 1 or 2, SOM must be restored within 6 hours. Failure to meet the specified SOM may be caused by a control rod that cannot be inserted. The allowed Completion Time of 6 hours is (continued) B 3 .* 1-2 Revision No .. 0 BASES ACTIONS PBAPS UNIT 2 A.I (continued) SOM B 3.1.1 acceptable, considering that the reactor can still be shut down, assuming no failures of additional control rods to insert, and the low probability of an event occurring during this interval. B .1-If the SOM cannot be restored, the plant must be brought to MODE 3 in 12 hours, to prevent the potential for further reductions in available SOM (e.g., additional stuck control rods). The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3
• from full power conditions -in an orderly manner and without challenging plant systems. C.l With SOM not within limits in MODE 3, the operator must immediately initiate action to fully insert all insertable control rods. Action continue until all insertable control rods fully inserted. This action results in the least reactive condition for the. core.
• D.l, 0!2; D.3, and D.4 With withtn limits in MODE 4, the operator must . immediately initiate action to fully insert all insertable control rods. Action must contintie until all insertable control *rods are fully inserted. This action results in the *
• least reactive condition for the core.
• Action must also be initiated within 1 hour tri means for control of potential radioactive releases.
• This incltides secondary containment is OPERABLE; at least one Standby Gas Treatment (SGT) **subsystem for Unit 2 is OPERABLE; and *
• se'condary containment isolation t:apabil ity *(i.e., at least .. one secondary .containment isolation valve and associated instrumentation are OPERABLE, or other acceptable to assure isolation capability}, in each assodated secondary containment penetration fl ow path not isolated that is . assumed to be isolated to mitigate radioactivity releases. This be performed_as .* (continued) B 3.1-3. *Revision No. O*

BASES ACTIONS D.l, D.2, D.3, and D.4 (continued) SOM B 3.1.1 an administrative check, by examining logs or other information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the surveillances needed to demonstrate the OPERABILITY. of the components. If, however, any required component is inoperable, then it must be restored to*-OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE. E.1. E.2, E.3, E.4, and E.5 With SDM not within limits in MODE 5, the operator must immediately suspend CORE ALTERATIONS that could reduce SDM, e.g., insertion of fuel in the core or the withdrawal of control rods. Suspension of these activities shall not preclude completion of movement of a component to a safe condition. Inserting control rods or removing fuel from the core will reduce the total reactivity and are therefore exc 1 uded from the suspended actions.

• Action must be immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies have been fully inserted. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and therefore do not have to be inserted. . . . Action must also be initiated within 1 hour to provide means for control of potential radioactive releases. This includes* ensuring secondary* containment is .. OPERABLE; at least one SGT subsystem for Unit 2 is OPERABLE; and secondary* containment isolation capability (i.e.,. at least one secondary containment isolation valve and associated instrumentation are OPERABLE, or other acceptable * . *administrative controls to assure i sol at ion capabi 1 ity), in each associated secondary containment penetration flow path not isolated that is assumed to be isolated to mitigate * * *radioactive releases. This may be performed as an* administratiVe ch_eck, by _examin.ing logs or other (continued) PBAPS UNIT 2 Revision No. O BASES ACTIONS SURVEILLANCE REQUIREMENTS *. PBAPS ,UNIT 2 E.l, E.2, E.3, .E.4, and E.5 '(continued) SDM B 3.1.1 information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the SRs needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this ca:se, SRs may need to be performed to restore the component to OPERABLE status. Action must continue until all required. components are OPERABLE. SR 3 .1.1.1 Adequate SDM must be verified to ensure that the reactor can be made subcritical from any initial operating condition. This can be accomplished by a test, an evaluation, or a combination of the two. Adequate SDM is demonstrated before or during the first startup after fuel movement or shuffling within the reactor pressure vessel, or control rod replacement. Control rod replacement refers to the decoupling and removal *of a control rod from a core location, and subsequent replacement with a new control rod or a control rod from another core location. Since core ieactivity will vary during the cycle as a function of fuel and poison burnup, the beginning of cycle (BOC) test must also account for changes in core reactivity during the cycle. Therefore, to obtain the SDM, the initial measured value must .be increased by an adder, "R'.', which is the difference between the calculated value of maximum core reactivity during the operating cycle and the calculated BOC core reactivity. If the value of R is is, BOC is the most reactive point in. the no correction to the BOC measured value is required (Ref. 3). For the SDM demonstrations that rely solely on calculation of the highest worth control rod, additional margin (0.10% Ak/k) must be added to the.SDM limit of 0.28% Ak/k to account for uncertainties in the calculation. The SDM may be demonstrated during an in sequence control rod withdrawal, in which the highest worth control rodis analytically determined, or during local criticals, where the highest worth cont.rol rod is determined by testing. Local critical tests require the withdrawal of out of (continued) B 3.1-:-5 Revision No.* 72*

BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 SR 3 .1.1.1 (continued) SDM B 3.1.l sequence control rods. This testing would therefore require bypassing of the Rod Worth Minimizer to allow the out of sequence withdrawal, and therefore additional requirements must be met (see LCO 3.10.7, "Control Rod Operating"). The Frequency of 4 hours after reaching criticality is allowed to provide a reasonable amount of time to perform the required calculations and have appropriate verification. During MODES 3 and 4, analytical calculation of SDM may be used to assure the requirements of SR 3.1.1.l are met. During MODE 5, adequate SDM is required to ensure that the reactor does not reach criticality during control rod withdrawals. An evaluation of each in vessel fuel movement during fuel.loading (including shuffling fuel within the core) ip required to ensure adequate SDM is maintained during refueling. This evaluation ensures that the intermediate loading patterns are bounded by the safety analyses for the final core loading pattern. For example, bounding analyses that demonstrate adequate SDM for the most reactive configurations during the refueling may be performed to demonstrate acceptability of the entire fuel movement sequence. These bounding analyses include additional margins to the associated uncertainties. Spiral offload/reload sequences,. including modified.quadrant spiral offload/reload sequences, inherently satisfy the SR, provided the fuel* assemblies are reloaded in the same con.figuration analyzed for the new cycle. Removing fuel _from the core will always result in*an increase in SDM. ,1. UFSAR, Secti.ons 1. 5. 1. 8 and 1. 5. 2 . 2: 7. 2. UFSAR, Section 3. NEDE-24011-P-A, "General Electric Standard Applic.ation. for Reactor Fuel," latest approved revision. 4. UFSAR, Section 14.5.3.3. 5. UFSAR, Section 14.5.3.4. (continued) B 3.1-6 Revision No. 72 BASES REFERENCES (continued) PBAPS UNIT 2 6. UFSAR, Section 3.6.5.4. B 3.1-7 SDM B 3.1.l Revision No. 72 Reactivity Anomalies B 3.1.2 B 3.1 REACTIVITY. CONTROL SYSTEMS B 3.1.2 Reactivity Anomalies BASES BACKGROUND PBAPS *UN IT .2 In accordance with the UFSAR (Ref. 1), reactivity shall be controllable such that subcriticality is maintained under cold tonditions and acceptable fuel design limits are not exceeded during normal operation and abnormal operational transients. Therefore, reactivity anomaly is used as a measure of the predicted versus measured Ci .e., monitored) core reactivity during power operation. A large reactivity anomaly could be the resuJt of unanticipated changes in fuel reactivity or control rod worth or operation at conditions not consistent with those assumed in the predictions of core reactivity, and could potentially result in a loss of SOM or violation of acceptable fuel design limits. Comparing predicted versus measured core reactivity supports the SOM demonstrations (LCO 3.1.1, "SHUTDOWN MARGIN (SOM)") in assuring the reactor* can be brought safely to cold, subctitical_conditions. Wh.en the reactor core is critical or in normal power operation, a reactivity balance exists and the net is zero. A comparison of predicted and measured reactivity is convenient uhder such a balance, since being relatively stable under power conditions. The positive reactivity in*the core design is balanced by the negative reactivity of the control components, ther.mal feedback, materials in the core absorb neutrons,* such as burnable producing *zero net reactivity. In order to fuel energy output, the uranium enrichment in the. new fuel loading and the fuel loaded in the previous cycles pro vi de excess positive reactivity beyond that requi r:ed to sustain steady .state *operation .at the beginning of cycle CHOC) .. Wh_en the reactor critical at RTP and temperature,. the excess p6sitive is by absorbers (e.g., gadolinia), control rods, and whatever neutron pbisons (mainly xenon and samarium) are present in the The predicted core r,eacti vity, as represented by continued B*3.l-8 Re.vision No. 113 .. * .i I I I BASES BACKGROUND (conti.nued) APPLICABLE SAFETY ANALYSES LCO PBAPS UNIT 2 Reactivity Anomalies B 3.1.2 core kemctive ( kett), is calculated by ,a 30 core simulator code as a function of cycle exposure. This calculation is performed for projected operating states and conditions throughout the cycle. The monitored core kett is calculated by the core monitoring system for actual plant conditions and is then compared to the predicted value for the cycle exposure. Accurate prediction of core reactivity is either an explicit or implicit assumption in the accident analysis evaluations (Ref. 2). In particular, SOM and reactivity transients, such as control rod withdrawal accidents or rod drop accidents, are very sensitive to accurate prediction of core reactivity. These accident analysis evaluations rely on computer codes that have been qualified against available test data, operating plant data, and analytical benchmarks. reactivity anomaly provides additional assurance that the nuclear methods provide an accurate representation of the core reactivity. the comparison between measured and predicted initial core reactivity provides a normalization for the calculational models used to predict core reactivity. If the measured and predicted core kettcs> for identical core condi_tions at BOC do not reasdnablj agree, then the used in the reload cycle design analysis or the calculation models used to predict core kett may not be accurate. If reasonable between measured predicted core reactivity exists at BOC, then the predictidn may be to the measured value. Thereafter, any significant deviations in the measured core k.tt from the.predicted core kett that duriTig fuel may be an indication that the of the OBA .and transient are no longer valid' or that an unexpected change in core con di t_i ons has occurred. Reactivlty anomalies satisfy.Criterion 2 of the NRC Policy Statement*: Large differences between monitored and predicted core reacttvity may indicate that the of the OBA and transient analyses are no longer valid, or that the continued B 3.1-9 *Revision No. 113. BASES LCD (continued) APPLICABILITY ACTIONS PBAPS UN IT 2 Reactivity Anomalies B 3.1.2 uncertainties in the "Nuclear Design Methodology" are larger than expected. A limit on the between the monitored and the predicted core keff of +/- 1% ilk/k has been I established based on judgment. A> 1% in reactivity from that predicted is larger than expected for normal operation and should therefore be evaluated. A deviation as large as 1% would not exceed the design conditions of the reattor and is on the safe side of the postulated transients. In MODE 1, most of the control rods are withdrawn and steady state operation is typically achieved. Under these conditions, the compajison between predicted and monitored tore reactivity provides *an effective measure of the reactivity anomaly. In MObE control rods are typically being withdrawn during a startup. In MODES 3 and 4, all control rods are fully inserted and therefore the reactor is* in the least reactive state. where monitoring core reactivity is not necessary. In MODE 5, fuel loading results in a continually changing core reactivity. SOM requirements (LCD 3,1.1) ensure that fuel movements are performed within the bounds of the safety and an SOM demonstration is required during the first star_tup following operations that could have altered core reactivity (E.g., fuel movement, control rod replacement, shuffling). The SDM test, required by LCO 3.1.1, provides a direct comparison of the predicted and monitored core reactivity at *cold-conditions; therefore, reactivity anomaly is not required during these conditions. Shaul d an anomaly develop between measured and pr.edi cted core reactivity, the core reactivity difference must be restored to within the limit to ensure continued operation is within the core design assumptions. to within the limit could be performed by an evaluatiDn of the core design and safety analysis to the reason for the anomaly. *This evaluation normally reviews the core conditions to determine their consistency with input to design Measured core and process parameters are also nprmally evaluated to determine that they are within.the bounds of the safety and safety

• calculational models may be reviewed to that they are adequate for representation of the core conditions. continued B 3 .. 1-10 . Revision No. 94 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT -2 A.1 (continued) Reactivity Anomalies B 3:1.2 The required Completion Time of 72 hours is based on the low probability of a OBA occurring during this period, and allows sufficient time to assess the physical condition of the reactor and complete the evaluation of the core design and safety analysis. If the core reactivity cannot be restored within the 1% limit, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion. Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging _plant systems. SR 3.1.2.1 The core monitoring system cal cul ates the core keff for the I
• reactor conditions* obtained from instrumentation. A comparison of the monitored core keff to the predicted core at the same cycle exposure is used to the reactivity difference .. The comparison is required when the reactivity has potentially changed by amount. This may occur following a refueling in which new fuel assemblies are loaded, fuel assemblies are shuffle"d within the core, or* control rods are replaced or shuffled.
• Control rod replacement refers to the decoup_l i ng and removal of a control rod from a core location, and subsequent replacement with a new rod or a rod from *another core location. Also, core reactivity changes during the cycle. The 24 hour after reaching equilibrium conditions following a is based on the need for equilibrium xenon .concentrations in the core, such that an accurate comparison between the monitored and predicted core k.t; can be made. For the"purposes of this SR, the reactor is assumed to be at equilibrium conditions when steady operatiOns (no control rod movement or core continued No. 113 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 SR 3.1.2.l (continued) Reactivity Anomalies 83.1.2 flow changes) 75% RTP have been obtained. The . 1000 MWD/T Frequency was developed, considering the relatively slow change in core reactivity with exposure and operating experience related to variations in core reactivity. The comparison requires the core to be operating at power levels which minimize the uncertainties and measurement errors, in order to obtain meaningful results. Therefore, the comparison is only done when in MODE 1. 1. UFSAR, Section 1.5. 2. UFSAR, Chapter 14. B 3.1-12 Revision No. 0 Control Rod OPERABILITY B 3.1.3 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.3 Control Rod OPERABILITY BASES BACKGROUND Control rods are components of the Control Rod Drive (CRD) System, which is the primary reactivity control system for the reactor. In conjunction with the Reactor Protection System, the CRD System provides the means for the reliable control of reactivity changes to ensure under conditions of normal operation, including abnormal operational transients, that specified acceptable fuel design limits are not exceeded. In addition, the control rods provide the capability to hold the reactor core subcritical under all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the CRD System. The_CRD System is designed to satisfy the requirements specified in Reference I. The CRD System consists of 185 locking piston control rod drive mechanisms (CRDMs) and a hydraulic control unit for each drive mechanism. The locking piston type CRDM is a double acting hydraulic piston, which uses condensate water as.the operating fluid. Accumulators provide additional energy for scram. An index tube and piston, coupled to the control rod, are locked.at fixed increnients by a collet mechanism. The co 11 et fi ngerS engage notches in the index, tube to.prevent unintentional withdrawal of the control rod, but without jnsertioh. *
• Specification, along with LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control.Rod Scram Accumulators," ensure that the performance of the. co_ntrol rods in the event of a Design.Basis Accident (DBA)or transient meets the assumptions used in the safety analyses of References 2, .3, . . APPLICABLE * . The analytical methods .and a*ssumptions used *in. the SAFETY ANALYSES.
• evaluations involving control .rods are presented in References 2, 3," and 4. The control rods provide the* primary means for rapid reactivity control (reactor scram), for maintaining the reactor subcritical and for limitihg the* potent;aT effects of inserti(>n events' caused by* . malfunctions in the CRD System.* .. (continued) PBAPS UNIT 2 ***Revision No. O*

BASES APPLICABLE SAFETY ANALYSES (continued) LCO . PBAPS UN IT 2 Control Rod OPERABILITY B 3.1.3 The capability to insert the control rods provides assurance that the assumptions for scram reactivity {n the OBA and transient analyses are not violated. Since the SOM ensures the reactor will be subcritical with the highest worth control rod withdrawn (assumed single failure), the

• additional failure of a second control rod to insert, if required, could invalidate the demonstrated SOM and potentially limit the ability of the CRO System to hold the subcritical. If the control rod is stuck at an inserted position and becomes from the CRO, a control rod drop accident CCROA) can possibly occur. Therefore, requirement that all control rods be OPERABLE ensures the CRO System can perform its intended function. The control rods also protect the fuel from damage which £ould result in release of radioactivity. The limits protected are the MCPR Safety Limit CSL) (see Bases for SL 2.1.1, "Reactor Core SLs" and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)"), the 1% cladding plastic strain foel design limit (see Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)"), and the fuel damage limit (see Bases for LCO 3.1.6, "Rod Pattern Control") during reactivity insertion events.* The negative reactivity insertion (scram) provided by the CRO System provides the analytfral basis for determination of plant thermal and provides protection against fuel damage limits during a CROA. The Bases for LCO 3.1.4, LCD 3.1.5, and LCD 3.1.6 discuss in more detail how the SLs are profected by the CRD System. Control r6d OPERABILITY satisfies Criterion 3 of the NRC The of an indiyidual is based combinatiorr of primarily, the scram ti riies' contra l rod coupling integrity' 'and the ability to determfrie. the contro.l rod position. Accumulator OPERABILiTY is addressed by LCO 3.1.5. The'associated accumul at6r status for a control r*od only affects the scram i nserli.ori times; therefore, an inoperable accumulator does not immediately require declaring a control rod inoperable. Although not .all control rods ar_e_ required to be OPERABLE to satisfy' the' intended reactivity control requirements, strict' continued ' -' B-3 :l-14 . 'Revision No. 49 BASES LCO {continued) APPLICABILITY ACTIONS PBAPS UNiT 2 Control Rod OPERABILITY B 3.1.3 control over the number and distribution of inoperable control rods is required to satisfy the assumptions of the OBA and transient analyses. In MODES 1 and 2, the control rods are assumed to function during a OBA or transient and are therefore required to be OPERABLE in these MODES. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod OPERABILITY during these conditions. Control rod requirements in MODE 5 are located in LCO 3.9.5, "Control Rod OPERABILITY-Refueling." The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable control rod. Complying with the Required Actions may allow for continued operation, and subsequent inoperable control rods are governed by subsequent Condition entry and application of associated Required Actions.
• A.I. A.2. A.3, and A.4 A control rod is considered stuck if it will not insert by either CRD drive water or scram pressure (i.e., the control rod cannot be inserted by CRD drive water and cannot be inserted by scram .pressure.) With a fully inserted control stuck, only those actions specified in Condition C required as long as the control rod remains fully inserted .. The Required Actions are modified by a Note, which allows
• the rod worth minimizer {RWM) to be bypassed if required to allow continued operation. LCO 3.3.2.1, "Control Rod Block Instrumentation," provides additional requirements when the RWM is bypassed to ensure compliance with the CRDA analysis. With one withdrawn control rod stuck, the local scram reactivity rate assumptions may not be met if the stuck control rod separation criteria are not met. Therefore, a verification that the separation criteria are met must be performed immediately. The separation criteria are not met if a) the stuck control rod occupies a location adjacent to two "slow" control rods, b) the stuck control rod occupies a location adjacent to one "slow" control rod, and the one "slow" control rod is also adjacent to another "slow" control rod, or c}_ if the stuck control rod occupies a* {continued). B 3.1:-15 Revision No. 2 BASES ACTIONS . PBAPS UNIT 2 . A.1. A.2. A.3. and A.4 (continued) Control Rod OPERABILITY B 3.1.3 location adjacent to one "slow" control rod when there is another pair of "slow" control rods adjacent to one another. The description of "slow" control rods is provided in LCO 3.1.4, "Control Rod Scram Times." In addition, the associated control rod drive must be disarmed in 2 hours. The allowed Completion Time of 2 hours is acceptable, considering the reactor can still be shut down, assuming no additional control rods fail to insert, and provides a reasonable time to perform the Required Action in an orderly manner. The control rod must be isolated from both scram and normal insert and withdraw pressure. Isolating the control rod from scram and normal insert and withdraw pressure prevents damage to the CROM. The control rod should be isolated from scram and normal insert and withdraw pressure, while maintaining cooling water to the CRO. Monitoring of the in&ertion capability of each withdrawn control rod must also be performed within 24 hours from discovery of Condition A concurrent with THERMAL POWER greater than the low power setpoint CLPSP) of the RWM. SR 3.1.3.3 performs periodic tests of the control rod insertion capability of withdrawn control rods. Testing each withdrawn control rod ensures that a generic problem not exist. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." The Required Action A.3 Completion Time only upon discovery of Condition A concurrent with THERMAL POWER greater than the actual LPSP of the RWM, since the notch insertions may not be compatible with the requirements of rod pattern control* (LCO 3.L6) and the (LCO 3.3.2.1). The allowed Complet.ion Time of
• 24 hours from discovery of Condition A.concurrent with THERMAL POWER than the LPSP of the RWM provides a reasonable time to test tbe control rods, considering the for a. need to power to perform the tests'. To allow continued operation with a control stuck, an evaluation of adequate SOM is also required within 72 hours. Should a OBA or transient require a shutdown; to preserve the single failure criterion, an additional control rod would have to be assumed to fail to insert when required. Therefore, the original SOM demonstration may not be SOM must be (by measurement or analysis) with the stuck control rod at its continued B *3.i-16 Revision No.* 79 BASES ACTIONS PBAPS UN IT 2 A.1. A.2. A.3. and A.4 (continued) Control Rod OPERABILITY B 3.1.3 stuck position and the highest worth OPERABLE control rod assumed to be fully withdrawn. The allowed Completion Time of 72 hours to verify SOM is adequate, considering that with a single control rod stuck in a withdrawn position, the remaining OPERABLE control rods are capable of providing the required scram and shutdown reactivity. Failure to reach MODE 4 is only likely if an additional control rod adjacent to the st0ck control rod also fails to insert during a required scram. Even with the postulated additional single failure of an adjacent control rod to insert, sufficient reactivity control remains to reach and maintain MODE 3 conditions (Ref. 5 and 6). With two or more withdrawn control rods stuck, the plant must be brought to MODE 3 within 12 hours. The occurrence of more than one control rod stuck at a withdrawn position increases the probability that the reactor cannot be shut down if required. Insertion of all insertable control rods eliminates the possibility of an additional failure of a control rod to insert. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. C.1 and C.2 With one or more control rods inoperable for reasons other than being stuck in the withdrawn position, (including a control rod which is stuck in the fully inserted position) operation may continue, provided the control rods are fully inserted within 3 hours and disarmed (electrically or hydraulically) within 4 hours. Inserting a control rod ensures the shutdown and scram capabilities are not adversely affected. The control rod is disarmed to prevent inadvertent withdrawal during subsequent operations. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. The control rods can be electrically disarmed by disconnecting power from all four directional control valve solenoids. Required Action C.1 is modified by a Note, which allows the RWM to be bypassed if required to allow insertion of the inoperable continued B 3.1-17 Revision No. 63 BASES ACTIONS
• PBAPS UN IT 2 C.1 and C.2 (continued) Control Rod OPERABILITY B 3.1.3 control rods and continued operation. LCO 3.3.2.1 provides additional requireme.nts when the RWM is bypassed to ensure compliance with the CRDA analysis. The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control in an orderly manner and without challenging plant systems. D.l and D;2 Out of sequence control rods may increase the potential reactivity worth of a dropped control rod during a CRDA. At s 10% RTP, the analyzed rod position sequence (Ref. 5 and 6) requires ihserted control rods not in compliance with the analyzed rod position sequence to be separated by at least two OPERABLE control rods in all directions, including the diagonal: Therefore, if two or more inoperable control rods are not in compliance with the analyzed rod position sequence and not separated' by at least two OPERABLE control rods, action must be taken to restore compliance with the analyzed rod position.sequence or restore the control rods to OPERABLE .status. Condition Dis modified by a Note indicating that the Condition is not applicable when > 10% RTR, the analyzed rod position sequence is not followed under conditions, as described in the Bases for LCO 3.1.6, .* The allowed Completion Time of 4 hours .is acceptable, considering the low probability *of a CRDA occurrjng . .Ll. If any Required Action and associated Completion Time of ConditiDn Ck or D are hot-met, or there are nine or more . inoperable co.ntrol rods, the pl ant must be br.ought to a MODE *.in which .the .LtO does t:iot apply_. To.achieve this status,
• t he p l a n t mus t be b r o u g ht to M 0 DE 3 wit h i n .12 h 0 u r s . Th i s ensures all inse'rtable control rods are* inserted and places* the reactor a condition that does not require the. active function (i.e., scram) of the control rods.* The number of contrql rods permittep tobe. iroperable when, operating above 10% RlP (e.g., no CRDA considerati.ons)* could be more than . ihe yalue but occurrence of. a number of continued ... . B 3. 1-_18 Revision No* .. 63 '*

BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 L1 (continued) Control Rod OPERABILITY B3.l.3 inoperable control rods could be indicative of a generic problem, and investigation and resolutiDn of the potential problem should be undertaken. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems. SR 3.1.3.l The position of each control rod must be determined to ensure adequate information on control rod position is .available to the operator for determining control rod OPERABILITY and controlling rod patterns.

• Control rod may be determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, or by the use of other appropriate methods. The Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.1.2 DELETED SR 3.1.3.3 Control rod insertion capability is demonstrated by inserting each partially tir fully withdrawn control rod at least one notch and observing that the control rod moves. The control rod may then be returned to its original -position. This the control rod is not stuck and is free to insert on.a scram signal. This Surveillance is not required when THERMAL POWER is.less than or equal to the* actual 'LPSP of the RWM, insertions may not be with of the analyzed rod. position sequence (LCQ 3-.L6) and the RWM CLCO 3.3.2.1}. Suryeillance Frequency is controlled under the Control' At time, if a control ro*d is immovable, a continued B. 3. 1-19 Rev.i sj on No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.1.3.3 (continued) Cont ro 1 Rod OPERABILITY B 3.1.3 determination of that control rod's trippability (OPERABILITY) must be made and appropriate action taken. For example, the of the Reactor Manual Control System does not affect the OPERABILITY of the rods, provided SR 3.1.3.3 is current in accordance with SR 3.0.2. SR 3.1.3.4 Verifying that the scram time for each control rod to notch position 06 is s 7 seconds provides reasonable assurance that the control rod win insert when required during a DBA or transient, thereby completing its shutdown function. This SR is performed in conjunction with. the contrbl rod time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," and the functional testing of SDV vent and drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlap this Surveillance to provide testing of the* assumed safety function. The Frequencies are acceptable, considering the more frequent testing performed to demonstrate other aspects of control rod OPERABILITY and operating expertence, which shows scram times do not significantly change an operating cycle. SR 3.1.3.5 Couplirig verification is performed to ensure the control rod is connected to the CROM and will perf9rm its intended function when necessary. The Surveillance requires verifying a control rod does not go to the withdrawn overt ravel position. The overt ravel position feature a positive check on the coupling integrity since only an uncoupled CRD can reach the overtravel position. The verification is required to be performed any time a control rod is withdrawn to the "full out" position (notch 48) or prior to declaring the control rod OPERABLE after work on th*e control rod or CRD System that could affect coupling (CRD changeout and blade replacement or complete cell disassembly, i.e., guide removal). This includes control rods inserted one notch and then returned continued B .RevisionNo. 79.

BASES SURVEILLANCE REQUIREMENTS RE FERENC ES . PBAPS UNIT 2 SR. 3.1.3.5 (continued) Control Rod OPERABILITY B 3.1.3 to the "full out" position during the performance of SR 3.1.3.2. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not being moved and operating experience related to uncoupling events. 1. UFSAR, Sections 1.5.1.1 and 1.5.2.2. 2; UFSAR, Section 14.6.2. 3. UFSAR, Appendix K, Section VI. 4. UFSAR, Chapter 14. 5 . N ED 0 -2 12 3 1 , " B a n k e d Po s it i o n W it h d r aw a l Seq u en c e , " 7.2, January 1977. 6. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision. B 3.*1-21 Revision No. 63 . Control Rod Scram Times B 3.1.4 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.4 Control *Rod Scram Times BASES BACKGROUND The scram function of the Control Rod Drive (CRD) System controls reactivity changes during abnormal operational transients to ensure that specified acceptable fuel design limits are not exceeded (Ref. 1). ,The control rods are scrammed by positive means using hydraulic pressure exerted on the CRD piston. When a scram signal is initiated, control air is vented from the scram valves, allowing them to open by spring action. Opening the exhaust valve reduces the pressure above the main drive piston to atmospheric pressure, and opening the inlet valve applies the accumulator or reactor pressure to the bottom of the piston. Since the notches in the index tube are tapered on the lower edge, the collet fingers are forced open by cam action, allowing the index tube to move upward without restriction because of the high differential pressure across the piston. As the drive moves'upward and the accumulator pressure reduces below the reactor pressure, a ball check valve opens, letting the reactor pressure complete the scram action. If the reactor pressure is low, such as during the accumulator will fully insert the control rod in the required time without assistance from reactor pressure. APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the control rod scram function are presented in . PBAPs* UNIT 2 References 2, 3, and 4. The Design Basis Accident (OBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. The resulting negative scram reactivity forms the basis for the determination of plant thermal limits (e.g., the MCPR). Other distributions of scram times (e.g., several control rods scramming slower than the average time with several control rods scramming faster than the average time) can also provide sufficient scram reactivity. Surveillance of each individual control rod's scram time ensures the scram reactivity assumed in the OBA and transient analyses can be met. (continued) B 3.1-22 Revision No. 0 BASES APPLICABLE SAFETY ANALYSES (continued) LCD PBAPS UN IT 2 Control Rod Scram Times B 3.1.4 The scram function of the CRD System protects the MCPR Safety Limit CSU (see Bases for SL 2.1.1, "Reactor Core and LCD 3.2.2, CRITICAL POWER RATIO CMCPR)") and the 1% cladding plastic strain fuel design limit (see Bases for LCD 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)"), which ensure that no fuel damage wi 11 occur if these limits are not exceeded. AbDve 800 psig, the scram function is designed to insert negative reactivity at a rate fast enough to prevent the actual MCPR from becoming less than the MCPR SL, during the analyzed limiting power transient. Below 800 psig, the scram function is assumed to perform during the control rod drop accident (Ref. 5) and, therefore, also provides protection against violating fuel damage limits during reactivity insertion accidents (see Bases for LCD 3.1.6, Pattern Control"). For the reactor vessel overpressure protection analysis, the scram function, *along with the safety/relief valves, ensure that the peak vessel pressure is within the applicable ASME Code limits. Control rod scram times satisfy Criterion 3 of .the NRC Policy Statement. The scram times specified in Table (in the LCD) are. required to ensure that the scram reactivity aisumed in.the OBA and transient analysis is met (Ref. 6).

• To account for single failures and "slow" scramming control rods, thecscram times specified in Table 3.1.4-1 are faster tha,n those .assumed in: the desigribasis*analysis. The scram t.iriles a margin .that all ()WS up to* approximately 7% of . the contrOl rods (e.g., 185 x 7% :'=i 13) to have scram times **.exceeding the specified limits (i.e., "slow" control rods) assuming a single stud contra l rod (as al lowed by LCD 3.1.'3; "Coritrol Rod OPERABILITY") and a.n a.dditional . control rod faili.ng to scrarri* per the single fa.i lure . .. cr5ter.1o'n>.The scram times are*specff{ed as a function of react6r steam dome to account for the dependence of the scram times .. The scram times are specified relative to based on *reed switch which provide the control rod. position i ndi cation:*. The reed s.witch closes ("pickup") when the continued B 3.1-23 Revision No. 49 BASES LCO (continued) APPLICABILITY . ACTIONS* PBAPS UNIT 2 Control Rod Scram Times B 3.1.4 index tube passes a specific location and then opens ("dropout") as the index tube travels upward. Verification of the specified scram times in Table 3.1.4-1 is accomplished through measurement of the "dropout" times. To ensure that local scram reactivity rates are maintained within acceptable liinits, no more than two of the allowed "slow" control rods may occupy adjacent locations. Table 3.1.4-1 is modified by two Notes, which state that control rods with scram times not within the limits of the table are considered "slow" and that control rods with scram times > 7 seconds are considered inoperable as required by SR 3.1.3.4. . This LCO applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed (LCO 3.1.3). Slow scramming control rods may be conservatively declared inoperable and not accounted for as "slow" control rods. In MODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these plant conditions. These events are assumed to occur during startup and power operation; therefore, the scram function of the control rods is required during these MODES. In MODES 3 and 4, the control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod scram capability during these conditions. Scram requirements in MODE 5 are contained in LCO 3.9.5, . "Control Rod OPERABILITY-Refueling." A. I When the requirements ofth1s LCO are nof met, the rate of . negat1ve reactivity insertion during' a scram may. not be . within *the.assumptions of the safety analyses. Therefore, the plant must be brought to a MODE in which the LCO does not apply._ To achieve this status, the plant must be .brought to MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable, based on operating . experience, to reach MODE 3 from full power conditions in an orderly manner and without challeng1ngplant systems. (continued) B 3.1-24 Revision No. 0 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT. 2 Control Rod Scram Times B 3. 1.4 The four SRs of this LCD are modified by a Note stating that during a single control rod scram time surveillance, the CRD pumps shall be isolated from the associated scram accumulator. With the CRD pump isolated, Ci .e., charging valve closed) the influence of the CRD pump head does not affect the single control rod scram times. During a full core scram, the CRD pump head would be seen by all control rods and would have a negligible effect on the scram insertion times. SR 3.1.4.1 The scram reactivity used in OBA and transient analyses is based on an assumed control rod scram time. Measurement of the scram times with reactor steam dome pressure 800 psig demonstrates acceptable times for the transients in References 3 and 4. Maximum scram insertion times occur at a reactor steam dome pressure of approximately 800 psig because of the competing effects of reactor steam dome pressure and stored accumulator energy. Jherefore, demonstration of adequate scram times at reactor steam dome pressure 800 psig ensures that the measured scram times will be within the specified limits at higher pressures. Limits are specified as a function of reactor pressure to account for the sensitivitY of the scram insertion times with pressure and to allow a range of pressures over which scram time testing can be performed. To ensure that scram time testing is performed within a time after a shutdown 120 days or longer, all control rods are required to be tested before exceeding 40% RTP. This Frequency is acceptable considering the additional surveillances performed for control rod OPERABILITY, the frequent verification of adequate accumulator pressure, and the required testing of control rods affected by fuel movement within the associate core cell and by work on control rods or the CRD System. SR 3.1.4.2 Additional testing of a sample of control is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. The sample remains representative continued . B 3.1-25 Revision No. 57 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.1.4.2 (continued) Control Rod Scram Times B 3.1.4 if no more than 7.5% of the control rods in the sample tested a re determined to be "slow".. With more than 7. 5% of the sample declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 7.5% criterion (i.e., 7.5% of the active sample size) is satisfied, or until the total number of "Slow" control rods (throughout the core, from all Surveillances) exceeds the LCD limit. For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the.control rods with data may have been previously tested in a sample. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.4.3 When work that .could affect the scram insertion time is performed on a control rod or the CRD System, testing must be done to demonstrate that each affected control rod retains adequate scram performance over the range of reactor pressures from zero to the
• permissible pressure. This surveillance can be met by performance of either scram time testing or Alternative Response Time (DART) testing, when it is concluded that DART testing monitors the performance of all affected components.* The testing must be performed once before the control rod The required testing must demonstrate the affected control rod is still acceptable The limits for reactor < 800 psig are established based on a high probability .of meeting the acceptance criteria at reactor pressures 800 psig. Limits 800 psig are found in Table 3.1.4-1. If testing the control rod does not meet these limits, but is within the 7 second limit of Table. Note 2; the rod can be declared OPERABLE' and "slow." continued B 3.1-29 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 .. SR 3.1.4.3 (continued) Control Rod Scram Times B 3.1.4 Specific examples of work that could affect the scram times are (but are not limited to) the following: removal of any CRD for maintenance or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator, isolation valve or check valve in the piping required for scram. The Frequency of once prior to declaring the affected control rod OPERABLE is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY. SR 3.1.4.4 When work that could affect the scram insertion time is performed on a control rod or CRD System, or when fuel movement within the reactor vessel occurs testing must be done to demonstrate each affected control rod is still within the limits of Table 3.1.4-1 with the reactor steam dome pressure 800 psig. Where work has been performed at high reactor pressure, the requirements of SR 3.1.4.3 and SR 3.1.4.4 can be satisfied with one test. For a control rod affected by work performed.while shut downi however, a zero pressure and high pressure test may be required. This testing ensures that, prior to withdrawing the control rod for continued operation, the control rod scram performance is acceptable for operating reactor pressure conditions. Alternatively, a control rod scram test during hydrostatic pressure testing could also satisfy both criteria. When fuel movement occurs within the reactor pressure vessel, only those control rods associated with the core cells affected by the fuel movement are required to be scram time tested. During a routine refueling outaie, it is expected that all control rods will be affected. The Frequency of once prior to exceeding 40% RTP is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other of control rod OPERABILITY. 1. UFSAR, Sections 1.5.1.3 and 1.5.2.2. 2. UFSAR, Section 14.6.2. continued B 3.1-27 Revision No. 57 ---*--------

BASES REFERENCES (continued) PBAPS UNIT 2 3. UFSAR, Appendix K, Section VI. 4. UFSAR, Chapter 14. Control Rod Scram Times B 3.1.4 5. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision. 6. Letter from R. E. Janecek (BWROG) to R. W. Starostecki (NRC), "BWR Owners Group Revised Reactivity Control System Technical Specifications," BWROG-8754, September 17, 1987. B 3.1-28 Revision No. 72 Control Rod Scram Accumulators B 3.1.5 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.5 Control Rod Scram Accumulators BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UN IT 2. The control rod scram accumulators are part of the Control Rod Drive CCRD) System and are provided to ensure that the control rods scram under varying reactor conditions. The control rod scram accumulators store sufficient energy to fully insert a control rod at any reactor vessel pressure. The accumulator is a hydraulic cylinder with a free floating piston. The piston separates the water used to scram the control rods from the nitrogen, which provides the required energy. The scram accumulators are necessary to scram the control rods within the required insertion times of LCO 3 .1. 4, "Contra l Rod Scram Ti mes." The analytical methods and assumptions used in evaluating the control rod scram function are presented in 1, 2, and 3. The Design Basis Accident CDBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. OPERABILITY of each individual control rod scram accumulator, along with LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.4, ensures that the scram reactivity in the OBA and analyses can be met .. The existence of an inoperable accumulator may invalidate prior scram time measurements for the associated control rod. The scram function of the CRD System, and therefore the OPERABILITY of the accumulators, protects the MCPR Safety Limit (see Bases for SL 2.1.1, "Reactor Core SLs" and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)") and 1 % c_ l a d di n g p l a s ti c s tr a i ri fu e f d e s i g n 1-i 111 it ( s e e B a s es fo r LCO "LINEAR HEAT GENERATION RATE CLHGR)"), which ensure that no fuel damage occur if these limits are not exceeded (see Bases for LCO 3.1.4). In add.itiqn, the scram funct'-1on *at .low reactor vessel pressure ,*startup . provides protection violating fuel -design limits reactivity (see Bases for

• LCD 3.1.6, Ro_d Pattern Control"). Control rod. scram accumulators satisfy Criterion 3 of the NRC Policy Statement. (continued) B 3.1-29 'Revision No. 49 Control Rod Scram Accumulators . B 3.1.5 BASES (continued) LCO The OPERABILITY of the control rod scram accumulators is required to ensure that adequate scram insertion capability exists when needed over the entire range of reactor pressures.* The OPERABILITY of the scram accumulators is based on maintaining adequate accumulator pressure. APPLICABILITY ACTIONS PBAPS UNIT 2 In.MODES I and 2, the scram function is required for mitigation of DBAs and transients, and therefore the scram accumulators must be OPERABLE to support the scram function. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod scram accumulator OPERABILITY during these conditions. Requirements for scram accumulators in MODE 5 are contained in LCO 3.9.5, "Control Rod* The ACTIONS Table is modifi.ed by a Note indicating that a separate Condition entry is allowed for each control rod scram accumulator. This is acceptable since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable accumulator. Complying with the Required Actions may allow for continued operation and subsequent inoperable accumulators governed by subsequent Condition entry and application of associated Required Actions.
• A.I and A.2 With one control rod scram.accumulator inoperable and the reactor steam dome pressure 900 psig, the control rod may be declared "slow," since the control rod will still scram at the reactor operating pressure but may not satisfy the required scram times in Table 3.1.4-1. Required Action A.I is modified by a Note indicating that declaring the control rod "slow" only applies if the associated control scram time was within the limits of Table 3.I.4-I during the last scram test. Otherwise, the control rod would already be considered "slow" and the further degradation of scram performance with an inoperable accumulator could result in excess.ive scram times. In this event, the associated (continued) B 3.I-30 Revision No. Jl.

BASES ACTIONS PBAPS UN IT 2

• A.I and A.2 (continued) Control Rod Scram Accumulators B 3.1.5 control rod is declared inoperable (Required Action A.2) and LCO 3.1.3 is entered. This would result in requiring the affected control rod to be fully inserted and disarmed,* thereby satisfying its intended function, in accordance with ACTIONS of LCO 3.1.3. The allowed Completion Time of 8 hours is reasonable, based on the large number of control rods available to provide the scram function and the ability of the affected control rod to scram only with reactor pressure at high reactor pressures. B.l, B.2.1. and B.2.2 With two or more control rod scram accumulators inoperable and reactor steam dome pressure 900 psig, adequate pressure must be supplied to the charging water header. With inadequate charging water all of the accumulators could become inoperable, resulting in a potentially severe degradation of the scram performance. Therefore, within 20 minutes from discovery of charging water header pressure < 940 psi9 concurrent with Condition B, adequate charging water header pressure must.be restored. The allowed Completion Time of 20 minutes is reasonable, to place a CRD pump into service to restore the charging water header pressure, if required; This Completion Time is based on the ability of the reactor pressure alone to fully insert all control rods.* control rod may be declared "slow," since the control rod wil 1 st i 11 scram using on 1 y reactor pressure, but may not satisfy the times in Table 3.1.4-1. Required Action B.2.1 is modified by a Note indicating that declaring the control rod "slow" ohly applies if the associated control scram time is within the limits of Table 3.1.4-1 . during the last scram time test. Otherwise, rod would already be conside.red "slow" and the further degradation of scram performance with an inoperable accumulator could result in excessive. scram times. In this event, the associated control rod is declared. inoperable (Required Action and LCO 3.1.3 entered. This would (continued) B 3.1-,31 Revision No. 2 BASES ACTIONS PBAPS UNIT 2 . Control Rod Scram Accumulators B 3.1.5 8.1, B.2.1. and B.2.2 (continued) result in requiring the affected control rod to be fully inserted and disarmed, thereby satisfying its intended function in accordance with ACTIONS of LCO 3.1.3. The allowed Time of 1 hour is reasonable, based on the ability of only the reactor pressure to scram the control rods and the low probability of a OBA or transient occurring while the affected accumulators are inoperable. C.1 and C.2 With one or more control rod scram accumulators inoperable and the reactor steam dome pressure < 900 psig, the pressure supplied to the charging water header must be adequate to ensure that accumulators remain charged. With the reactor steam dome pressure < 900 psig, the function of the accumulators in providing the scram force becomes much more .important since the scram function could become severely degraded during a depressurization event or at low reactor pressures. Therefore, immediately upon discovery of charging water header pressure < 940 psig, concurrent with Condition C, all control rods associated with inoperable* accumulators must be verified to be fully inserted. Withdrawn control rods with inoperable accumulators may fail to scram under these low pressure conditions. The rods must also be declared inoperable .within l hour.* The allowed Completion Time of 1 hour is reasonable for Required Action C.2, considering the low probability of a OBA. or transient occurring during the time that the is. 0.1
• The reactor mode switch must be immediately*placed in* the shutdown position if either Required Action and associated Completion Time associated with the loss of the CRD charging pump (Required Actions B.1 and C.1) cannot be met. This ensures that all insertable control *rods are inserted and that the reactor is in a condition that does not require the (continued} B 3.l-,32 Revision No. 2 BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 D.1 (continued) Control Rod Scram Accumulators B 3.1.5 a c ti v e fun ct i on C i. e . , s c r am ) o f t he co n t r o l rod s . Th i s Required Action is modified by a Note stating that the action is not applicable if all control rods associated with the inoperable scram accumulators are fully inserted, since the function of the control rods has been performed. SR 3.1.5.1 SR 3.1.5.1 requires that the accumulator pressure be perindically checked to ensure adequate accumulator pressure exists to provide sufficient scram force. The primary indicator of accumulator OPERABILITY is the accumulator pressure. A minimum accumulator pressure is specified, below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is inoperable. The minimum accumulator pressure of 940 psig is well below the expected pressure of approximately 1450 pstg (Ref. 1). Declaring the accumulator inoperable when the minimum is not maintained.ensures that sigriificant degradation in times d9es not occur. The frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 3.4.5.3 and Figure 3.4.10. 2. UFSAR, Appendix K, VI. 3. UFSAR, Chapter 14. B 3.1-33 Revision No. B6

"' I Rod Pattern Control B 3.1.6 B

• 3. 1 '
• REACTIVITY CONTROL SYSTEMS B 3.1.6 Rod Pattern Control. BASES. BACKGROUND APPLICABLE . SAFETY ANALYSES . ' .. ,. PBAPS UNIT 2 Control patterns.during. startup conditi6ns are controlled by the operator and the rod worth minimizer (RWM) (LC0*3.3.2.1, "Control Rod Block Instrumentation"), so that only specified control rod and relative positions are all owed over the operating range of all control rods inserted to 10% RTP. The seq*uences 1 i mi t the potent i a 1 amount of reactivity addition that could occur in the event of a Control Rod Drop Accident (CRDA). This Specification that the control rod patterns are consistent with the assumpti oris. of the CRDA analyses of References 1 and 2: ** ***
• The analytical methods and assumptions used in evaluating the CRDA are summarized in References 1 and 2. CRDA analyses that the readtor operator withdrawal sequences. These sequences define the potential initial 'conditions for the CRDA analysis: The RWM (LCO 3 .. 3. 2. 1) provides backup to operator control of the .withdrawal. sequences to ensure that the initial conditions of *the CRDA analysis are not violated. Prevention or mitigation of.positive reactivity insertion events is tQ limit the energy deposition in the thereby preventing fuel damage ch result in the undue release of Since the fai 1 ure consequences for U02 have been shown . to be * . insignificant below fuel energy depositions of 300 cal/gm (Ref. 3), the fuel-damage l.imit bf 280 bal/gm provides a *margin of safety from significant core. damage which would resuli in release of radioaritivity 5). Generic evaluati.ons (Refs. 1 arid* 6) of a design basis CRDA (i.e., a _CRDA resulting in a peak *fuel energy deposition cif 280 cal/gm) have shown that if the peakfuel enthalpy remains below 280,cal/gm, then the maximum recictor pressure wi 11 be 1 ess than the required ASME Code 1 imits (Ref. 7) and *the calculated offsite doses will be well within the required limits (Ref. 5). (continued) -Revision No. 75.

BASES APPLICABLE SAFETY ANALYSES (continued) PBAPS UN IT 2. Rod Pattern Control B 3.1.6 Control rod patterns analyzed in Reference 1 follow the analyzed rod position sequence. The analyzed rod position is applicable from the condition of all control rods fully inserted to 10% RTP (Ref. 2). For the analyzed rod position sequence, the control rods are required to be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions. The banked positions are established to minimize the maximum incremental control rod worth without being overly restrictive during normal plant operation. Generic of the analyzed rod position sequence (Ref. 1) has demonstrated that the 280 cal/gm fuel damage limit will not be violated during a CRDA while following the analyzed rod position sequence mode of operation. The generic analyzed rod position sequence analysis (Ref. 8) also evaluates the effect of fully inserted, inoperable control rodi not in compliance with the sequence, to allow a limited number Ci .e., eight) and distribution of fully inserted, inoperable control rods. When performing a shutdown of the plant, an optional rod position sequence (Ref. 9) may be used provided that all withdrawn control rods have been confirmed to be coupled. The rods may be inserted without the need to stop at intermediate positions since the possibility of a CRDA is eliminated by the confirmation that withdrawn control rods are coupled. When using the (Ref. 9) control rod sequence for shutdown, the RWM may be reprogrammed to enforce the requirements of the control rod insertion process; o r may be by pa s s e d-a n d t h e a n a l y z e d rod p o s i t i on s e q u en c e implemented under LCO 3.3.2.1, Condition D controls. In order to use the 9 shutdown process, an extra *check is required in order to a control rod t6 be. "confirmed" to be coupled. This extra check ensures that no single operator error can result in an incorrect coupling . check.* For purposes of {his shutdown process, the method for confirming that control rods are coupled varies depending on t-h e p o s i t i on of th e cont r o l rod i n t h e co r e . De t a i l on t h i s confirmation are provided in

• Reference 9. If* the requirements for use of the control rod insertion-process contained in Reference.9 are followed, the plant is considered in with the rod position. sequence as required by LCO 3.1.6. Rod patterh control satisfies 3 -of the NRC Statement. (continued) B Revision No. 114 BASES (continued) Rod Pattern Control B 3.1.6 LCO Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limtting the initial conditions to those consistent with the analyzed rod position sequence. This LCO only applies to OPERABLE control rods. For inoperable control rods required to be inserted, separate requirements are specified in LCO 3.1.3, "Control Rod OPERABILITY," consistent with the allowances for inoperable control rods in the analyzed rod position sequence. APPLICABILITY PBAPS *UNIT 2 In MODES 1 and 2, when THERMAL POWER is 10% RTP, the CRDA is a Design Basis Accident and, therefore, compliance with the assumptions of the safety analysis is required. When THERMAL POWER is > 10% RTP, there is no credible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Ref. 2). In MODES 3, 4, and 5, since the reactor is shut down and only a single control rod can be withdrawn from a core cell containing fuel adequate SOM ensures that the consequences of a CRDA are acceptable, since the reactor will remain subcritical with a single control rod withdrawn. (continued) B 3.1-35a . Revision No. 63 Rod Pattern Control B 3.1.6 BASES (continDed) ACTIONS A.l and A.2 PBAPS UN IT 2 With one or OPERABLE control rods not in compliance with the analyzed rod position sequence, *actions may be taken to either correct the control rod pattern or declare the associated control rods inoperable within 8 hours. Noncompliance with the prescribed sequence may be the result of "double notching," drifting from a control rod drive cooling water transient, leaking scram valves, or a power reduction to s 10% RTP before establishing the correct control rod pattern. The number of OPERABLE control rods not in compliance with the prescribed sequence is limited to eight, to prevent the operator from attempting to correct a control rod pattern that significantly deviates from the prescribed sequence. When the control rod pattern is not in compliance with the prescribed sequence, all control rod movement must be stopped except for moves needed to correct the rod pattern, or scram if warranted. Action A.1 is modified by a Note Which allows the RWM to be bypassed to allow the affected control rods to be returned to their correct position. LCD 3.3.2.1 requires Verification of control rod movement by a second licensed operator or a qualified member of the technical staff (i.e., personnel trained in accordance with an approved training program). This ensures that the control rods wi 11 be moved to the correct A control rod in compliance with _the prescribed sequence is not considered inoperable except as required by Required Action A.2. The allowed Completion Time of 8 hours is cbnsidering the restrictions oh the.number of allowed out of sequence contr6l rods and the low probability of a CRDA occurring __ during the time.the control rods are out of sequence. _B.1 and B.2 If more OPERABLE rods are not in compliance with analyzed rbd pbsftion sequence; the crintrol rod_ -pattern_ si gni fi cantly deviates from the prescribed sequence. Control r*od withdrawal should be suspended i.mmediately to the potential for further deviation from.the _ prescribed sequence; Co_ntrol rod insertion .to correcf" contro-_i. rods withdrawn beyond their a 11 owed position iS allowed since, in:general, insertion of control rods has continued * -B 3. 1-36 Revisi6n No. 63 -

BASES ACTIONS SURVEILLANCE REQUIREMENTS _REFERENCES PBAPS UNIT 2 8.1 and B.2 (continued) Rod Pattern Control B 3.1.6 impact on control rod worth than withdrawals have. Required Action B.1 is modified by a Note which allows the RWM to be bypassed to allow the affected control rods to be returned to their correct position. LCO 3.3.2.1 requires verification of control rod movement by a second licensed operator or a qualified member of the technical staff. When nine or more control rods are not in compliance with the analyzed rod position sequence, the reactor mode switch must be placed in the shutdown position within 1 hour. With the mode switch in shutdown, the reactor is shut down, and as such, does not meet the applicability requirements of this LCO. The allowed Completion Time of 1 hour is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability of a CRDA occurring with the control rods out of sequence. SR 3.1.6.l The control rod pattern is periodically verified to be in compliance with the analyzed rod position sequence to ensure the assumptions of the CRDA analyses are met. The Surveillance Frequency controlled under the Surveillance Frequency Control Program. The RWM provides c6ntrol rod blocks to enforce the required sequence and is required to be OPERABLE when operating at s 10% RTP. -1. NEDE-24011-P-A, "General Electric Standard -for Reactor Fuel," la test approved revision. 2. Letter CBWROG-8644) from T. Pickens CBWROG) to G. C. Lainas CNRC), "Amendment 17-to General Electric Li c en s i n g Top i c a l Re po rt N ED E -2 4 0 11 -P -A ." 3. UFSAR, Section 14.6.2.3. 4. Deleted. 5. 10 CFR 50.67. continued B 3.1-37 Revision No. 86 BASES REFERENCES (continued) PBAPS UN IT 2 6. Rod Pattern Control B 3.1.6 NED0-21778-A, "Transient Pressure Rises Affected Fracture Toughness Requirements for Boiling Water Reactors," December 1978. 7. ASME, Boiler and Pressure Vessel Code. 8. NED0-21231, "Banked Position Withdrawal Sequence," January 1977. 9. NED0-33091-A, "Improved BP\.JS Control Rod Insertion Process," Revision 2, July 2004. B 3.1-38 Revision No. 61 SLC System B 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BASES BACKGROUND PBAPS UNIT 2 The SLC System is designed to provide the capability of bringing the reactor, at any time in a fuel cycle, from full power and minimum control rod inventory (which is at the peak of the xenon transient) to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement. The SLC System satisfies the requirements of 10 CFR 50.62 (Ref. 1) on anticipated transient without scram using highly enriched boron. Using highly enriched boron in the SLC System increases the rate of Boron-10 injection and functions to shutdown the reactor core faster. This limits the heat generated that is transferred to the suppression pool during an ATWS event. Limiting the heat transferred to the suppression pool maintains the pool below design limits, which ensures adequate net positive suction head CNPSH) is for the emergency core tooling system CECCS) pumps without credit for containment accident pressure. The SLC System is also used to maintain suppression pool pH at or above 7 following a loss of coolant accident (LOCA) involving significant fission product Maintaining suppression pool pH levels at or above 7 following an accident ensures that sufficient iodine will be retained in the suppression pool water. Reference 1 requires a SLC System with a minimum flow capacity and boron content equivalent in control capacity to 86 gpm of 13 weight percent sodium pentaborate solution. Natural sodium pentaborate solution is 19.8% atom Boron-10. Therefore, the system parameters of concern, boron concentration (C), SLC pump flow rate (Q), and Boron-10 enrichment (E), may be expressed as a multiple of ratios. The expression is as follows: c Q E x 13% weight 86 gpm atom If the product of this expression 1, then the SLC System satisfies the criteria of Reference 1. As such, the product of this expression at the minimum B 3.1-39 Revision No. 114 BASES BACKGROUND (continued) AP PU CABLE SAFETY ANALYSES PBAPS UNIT 2 SLC System B 3.1.7 c rite ri a, for the s u rvei 11 a nces of con cent ration, fl ow rate and boron enrichment is > 1.69, which reflects that the SLC . System exceeds the criteria of Reference 1. The SLC System consists of a boron solution storage tank, two positive displacement pumps, two explosive valves that are provided in parallel for redundancy, and associated piping and valves used to transfer.borated water from the storage tank to the reactor pressure vessel CRPV). The borated solution is near the bottom of the core shroud, where it then mixes with the cooling water rising through the core. A smiller tank containing demineralized water is provided for testing purposes. The SLC System is manually initiated from the main control room, as ijirected by the emergency operating procedures, if the operator believes the reactor cannot be shut down, or kept shut down, with the control rods. The SLC System is used in.the event that enough control rods cannot be inserted to accomplish shutdown and cooldown in the normal manner. The SLC Systeni borated water into the core to add negative reactivity to compensate f6r all of the various reactivity effects that could occur p1aot operations. *To meet this objective, it is necessary to inject a quantity of boron, which produces a . concentration of.660 ppm of'natural boron, in the reactor coo la n t at 6 8 ° F . To a 1 l ow f o r pot en t i a 1 1 ea k a g e a n d imperfect miXing in the reactor iystem: an additional amount of bor6n equal to 25%.of the amount cited above is added as a minimum (Ref. 2).: The minimum: level of sodium pentaborate in solution in theSLC tank.(i.e., SR 3.1.7.1, 52%) and t h e temp e r a t u re v e r s u s con c e n t r a t i on 1 i m it s i n F i g u re 3 . 1.. 7 -i* are calculated such that the _required concentration 1s achieved*, with additional margin asso.ciated with using .. *highly enriched.boron to increase the* rate of Boron-10 . injection, accounting for dilution .in the RPV with normal ,water leve'l and incli.rding the water volume in the residual heat removal shutdciwn coo}inci piping and in the recirculation io6p piping. This of borated soluti.on* is the amount that is above the pump suction shutoff le.\/el in the boron .solution storage tank; No credit is taken 'for the por.ticin of the; :ta.nk volume that cannot be 1njected. -The rriaxinium allo'wable concentration of sodium pentaborate depicted in Fi_gure 3.1. 7-1 has been established the soluti6ri does not exceed 43°F .. Using highly enriched boron (i .e;, *sR 3.l.J.10, 92:0%) in the SLC System increaies the rate of I' I .(continued) . B 3.1-40 Revision No. 114 BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICA.SI LITY -PBAPS UNIT. 2 SLC System B 3.1.7 Boron-10 injection and functions to shutdown the reactor core faster. This limits the heat generated that is transferred to .t.he suppression pool during an ATWS event. Limiting the heat transferred to the suppression pool maintains the pool below design limits, which ensures adequate NPSH is available for the ECCS pumps without credit fbr containment accident pressure. The sodium pentaborate solution in the SLC System is also used, post-LOCA, to maintain suppression pool pH at or above 7. The system parameters used in the calculation are the minimum allowable volume, Boron-10 enrichment, and concentration of sodium pentaborate in solution in the SLC tank. These minimum allowable values are required to maintain suppression pool 7.0 post-LOCA. This prevents radioactive iodine from re-evolving, which limits the iodine release to the plant environs and minimizes the radiological consequences to comply .with 10 CFR 50.67 limits (Ref. 3). The SLC System satisfies Criteria 3 and 4 of the NRC Policy Statement. The OPERABILITY of the SLC System provides backup capability f6r reactivity control independent of normal reactivity

• control provisions provided by the control rods. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank arid the availability of a flbw path to RPV, including the OPERABILITY of the ahd valves. Two SLC are required to be OPERABLE; each contains an OPERABLE pump, an explosive valve, and asso£iated piping, valves; and instruments and controls to ensure an OPERABLE fltiw path.
• In MODES 1 and 2, shutdown .capability is reqL,ti red. In MODES 1, 2, and 3, SLC *System injection capability is required in order to ma1ntain post OBA LOCA suppression pool pH. In MODES 3 and 4, control rods not able to be withdrawn s.i nee the reactbr mode switch is in shutdown and a control
• rod is .. This provides :adequate contr6ls to. that the remains subcrjtical .. In MODE 5,
• orily a*single control rod can be withdrawn from cell fuel rif adequate SDM. CLCO 3.Ll, "SHUTDOWN MARGIN (SOM)") ensures that the reactor wi 11 not become criti ca 1 . Therefore, the sLc System is riot required to be OPERABLE when only a single control rod can be withdrawn. * * (continued) B 3. I-41 Revi,sioh No. 114
• BASES APPLICABILITY (continued) ACTIONS PBAPS UNIT 2 SLC System B 3.1.7 In MODES 1, 2, and 3, the SLC System must be OPERABLE to ensure that offsite doses remain within 10 CFR 50.67 (Ref. 3) limits following a LOCA involving significant fission product releases. The SLC System is designed to maintain suppression pool pH at or above 7 following a LOCA involving significant fission product releases to ensure that iodine will be retained in the suppression pool water. A.l and A.2 If the boron solution concentration is> 9.82% weight but the concentration and temperature of boron in solution and pump suction piping temperature are within the limits of Figure 3.1.7-1, operation is permitted for a limited period since the SLC subsystems are capable of performing the intended function. It is not necessary under these conditions to declare both SLC subsystems inoperable since the SLC subsystems are capable of performing their intended* function. The concentration ahd temperature of boron in solution and pump suction piping temperature must be verified to be within the limits of Figure 3.1.7*1 within 8 hours and once per 12 hours thereafter (Required Action A.1). The temperature versus concentration curve of Figure 1* for concentrations > 9.82% weight, ensures a 10°F margin will be maintained above the saturation temperature. This Verification ensures that boron does not precipitate out of solution in the storage tank or in the pump suction piping due to low boron solution temperature (below the saturation temperature for the given The Completion *.Time for performing Required Action A.1 is considered acceptable given the low probability of a Design Basis . Accident (OBA) or transient occurring concurrent with the failure of the control rods to shut down the reactor and* operating experience which has there are relatively *slow variations in the measured parameters of concentration and temperature these time periods. Continued operation is only permitted for 72 hours before boron solution concentration must be to s 9.82% weight. Taking into consideration that the SLC_System design capability still exists for vessel injection under these conditions and the low probability of the temperature and concentration limits of Figure 3.1.7-1 not being met, the allowed Completion Time of 72 is acceptable and provides adequate time to concentration to .limits. * (continued). B 3.1-42 Revisioh N6. 114

1. BASES ACTIONS (continued) PBAPS *UN IT 2 SLC System B 3 *. 1. 7 If one SLC subsystem is inoperable for reasons other than Condition A, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this condition, the remaining OPERABLE subsystem is adequate to perform the shutdown function. However, the overall reliability is reduced because a single failure in. the remaining OPERABLE subsystem could result in the loss of SLC System shutdown capability. The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the intended SLC System function and the low probability of a OBA or severe transient occurring concurrent with the failure of the Control Rod Drive (CRD) System to shut down the plant. If both SLC subsystems are inoperable for reasons other than Condition A, at least one subsystem must be restored to OPERABLE status within 8 hours. The allowed Completion Time of 8 hours is considered given the low probability of a OBA or transient occurring concurrent with the failure of the control rods to shut down the reactor. 0.1 and D.2 If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be , brought to MODE 3 within 12 hours and MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required MODES from full power conditions in an orderly manner and without challenging .Plant systems. (continued) B 3.1-43 Revision No. 114 SLC System B 3.1.7 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.1.7.1. SR, 3.1.7.2. and SR 3.1.7.3 SR 3.1.7.1 through SR 3.1.7.3 verify certain characteristics of 'the SLC System (e.g., the level and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure that the proper borated solution level and temperature, including the temperature of the pump suction piping, are maintained. Maintaining a minimum specified borated solution temperature is important in ensuring that the boron remains in solution and does precipitate out in the storage tank or in the pump suction piping. The temperature limit specified in SR 3.1.7.2 and SR 3.1:7.3 and the maximum sodium pentaborate concentration specified in Figure 3.1.7-1 ensures that a l0°F margin will be maintained above the saturation temperature. Control room alarms for low SLC storage tank temperature and low SLC System piping temperature are and are set at 55°F. As such, SR 3.1.7.2 and SR 3.1.7,3 may be satisfied by verifying the absence of low alarms for the SLC storage tank and SLC System piping. The Surveillance Frequency is controlled under the Frequency Control Program. SR 3.1.7.4 and SR 3.1.7.6

• SR verifies the of the explosive charges i n t h e i ii j e ct i 6 n v a l v e s t o en s *u re t h a t p r o p e r op e r a t i on w i 11 occur if. required. Other controls, such as those that limit the shelf life 9f the explosive charges, must be FfeqGency is controlled un.der Uie s*urvei l lance Frequency Confrol * .. Program. SR thaf each Valve in the system is in its correct. position, but do.es not apply to the squib (i ;e., *explosive) valves. Verifying the correct alignment for manual and _power**.operated va.lves in the SLC System flow path ,. provides*' as'surance that the proper fi ow paths wi 11 exist' for system operation. A valve is *also allowed to be in the nonaccident p*osition provided it can be aligned to the acci.dent position from the control room, or.locally by a dedicated qperator at .. the*.valve control. This is acceptable since .the SLC System.is a manually initiated system. This Surveillance also does not apply to valves that are locked; sealeq, or. otherwise secured in position since they are vertfied to tn the position prior to s ea l i rig .: or s e u r i n g . Thi s v e r if i ca ti on of v a l v e. al i g nm e ri t continued *. B 3. 1-44 . .Revision No, 114 BASES SURVEILLANCE REQUIREMENTS
• PBAPS UN IT 2 SR 3.1.7.4 and SR (continued) SLC System B 3.1.7 does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.7.5 This requires an examination of the sodium pentaborate by using chemical analysis to ensure that the proper concentration of boron exists in the storage tank .. Having the proper concentration of boron in the storage tank ensures the SLC subsystems will perform their intended function of no less than the minimum quantity of Boron-10 and amount of sodium pentaborate required by ATWS analyses. The SLC subsystems function to quickly the reactor in the event of an ATWS. This limtts the heat generated that is transferred to the suppression pool an ATWS eveni. limiting the heat to the suppression pool maintains the pool below limits, ensures adequate Js available for the ECCS without.credit for containment accident pressure. The SLC subsystems also function to maintain
• suppression pool pH ;;::: 7. b under post-LOCA tonditi ons. SR 3.1.7.5 must be anytime boron or water is added to the storage tank solution to determine that the boron solution concentration is;;::: 8.32% ahd s 9.82% weight. 1* SR.3.1.7.5 must also be performed anytime the temperature is to. within limits to that nci significant boron occurred., .The Surveillance Frequency ls control led under the SurveU lance Frequency Control Program. SR J.1.7;7 Deleted SR. Demonstrating that each SlC system pump.develops .a flow . rate ;;::: 49 .1 gpm at a discharge pressu're ;;::: r215 psi g ensures . I that pump performance has not degraded below desi gri values.** during the fuel cy.cle. This minimum pump flow rate .*.
• requirement ensures t.hat, when combined with the sodium (continued) B 3.1-45 Revisi6n No. )14 I I I BASES SU RV EI LLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.1.7.8 (continued) SLC System B 3.1.7 solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. The rate of negative reactivity insertion is increased by using highly enriched boron in the SLC System that increases the rate of Boron-10 injection and functions to shutdown the reactor core faster. This limits the heat generated that is transferred to the suppression pool during an ATWS event. Limiting the heat transferred to the suppression pool maintains the pool below design limits, which ensures adequate NPSH is available for the ECCS pumps without credit for containment accident pressure. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections conftrm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program. SR 3.1.7.9 This Surveillance ensures that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured as the one fired or from another batch that has been certified by having one of that batch successfully fired. The Surveillance may be. performed in separate steps to prevent injecting boron into the RPV. *An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued No.

1*. ! BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UNIT 2 SR 3.1.7.10 SLC System B 3.1.7 Enriched sodium pentaborate solution is made by mixing granular, enriched sodium pentaborate with water. Isotopic tests on the granular sodium pentaborate to verify the actual B-10 enrichment must be performed prior to addition to the SLC tank in order to ensure that the proper B-10 atom percentage is being used. The tests may use vendor certification documents. 1. 10 CFR 50.62. 2. UFSAR, Section 3.8.4. 3. 10 CFR 50. 67. B 3,1-47 Revision No. 130

.. *: I :*,' ' . . . SDV Vent and Drain Valves B 3.1.8 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves BASES. BACKGROUND . APPLICABLE. . SAFETY* *ANALYSES . ... : .. ,' .:-: *. *-. *_, * .. ;.-: '.* .. * .... . . . *' . : -. . .

• PBAPS UNIT 2* The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that sufficient volume is available at all times to allow a complete scram. During a scram, the SDV vent and drain valves close to contain reactor water. As discussed in Reference 1, the SDV vent and drain valves need not be coniidered primary containment isolation valves (PCIVs) for the System. (However, at PBAPS, these valves* are considered. PCIVs.) The SDV is a volume of header connects to each hydraulic control unit (ttCU) and drains into an i volume ..
• There are two SDVs (headers) and a common instrument volume that receives all *of the controi rod drive (CRD) disch;;irges. The instrument volume is connected to a common_drain line with twq valves in seties. Each header is connected to a common vent lirie with two valves in series for a total .of four v.eht. valves .. The header pi pi'ng is s.i zed to r:ecei ve and cqntai n a 11 the water discharged by the* CRDs during a scram. The design and . functions of the SDV -*are described in Reference 2. -The Design Basis Accident-. and transient analyses assume all bf the c;ont'rol rpds are capab1 e of.scramming.-. The. -acceptance cr-fteri a for the_ SDV vent and drain valves are thet 6perate automatically tq close scram t;o limlt the.amount* of .reactor coolarit discharged so that cooling. is maintained and offs;te doses remain '.within the limits of 1o CFR 50.67 .. (Ref. 3) :. * * * * * * , < *. ,. > ** * * * * * * '* * * : * -** lso:l of *the SDV can sb be accomplished.: by manual closure. of the SDV vaiveso 'Addltionally, the discharge of * .. reactor coolanf-*to the sov .can be by scram reset. ! dr closu're :of ttie HCQ. manuaf i soiati cm .val For a .. *-* ..
• _bo,undirigleakage**case\;theoffsit;e doses are w.ell within.the_ . limits of to CFR 5'.o :67 (Ref.-3),' and adequate core cooling . -is mairitai ned 1) . The $DV vent arid dr:ai n va.l ves al lOw continuous of-theSDV during normal -plant.operation to that the s'ov ha_s *sufficient capaciot;y to contain the reactor coolant di.scharge during.*a full core scram .*.
• To . C_l:il\y ,:ensure _.this capacity; . a reactot *--1*;1, "ReactorProtecfiori System (RPS)* Ins:trumentatior1"} is ihiti ated _ ;'f* the water. level i 11 the *.*' .' . .. ; *:*:..**.:.' :(continued) ._Revision No.. 75: *' ' . .... ' f "* ...

BASES APPLICABLE SAFETY ANALYSES (continued) LCD APPLICABILITY ACTIONS PBAPS UN IT 2

• SDV Vent and Drain Valves B 3.1.8 instrument volume exceeds a specified setpoint. The setpoint is chosen so that all control rods are inserted before the SDV has insufficient volume to accept a full scram. SDV vent and drain satisfy Criterion 3 of the NRC Policy Statement. The OPERABILITY of all SDV vent and drain valves ensures that the SDV vent and drain valves will close during a scram to contain reactor water discharged to the SDV piping. Since the vent and drain lines are provided with two valves in series, the single failure of one valve in the open position will not impair the isolation function of the system. Additionally, the valves are required to be opened following scram reset to ensure that a path is available for the SDV piping to drain freely at other times. In MODES 1 and 2, scram may be required; therefore, the SDV vent and valves must be OPERABLE. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides controls to ensure that only a single control rod be withdrawn. Also, during MODE 5, only a single control rod can be withdrawn from a core eel l containing fuel assemblies. Therefore, the SDV vent and drain valves are not required to be OPERABLE in these MODES since the reactor is subcritical and only one rod may be withdrawn and subject to scram.
• The ACTIONS Table is modified by Notes indicating that a separate Condition entry is allowed for ea6h SDV vent and drain line. This .is acceptable, since the Required Actions for each Condition provide:appropriate compensatory actions for each inoperable SDV line. Complying with the Required .Actions may allow for continued operation, and SDV lines are *governed by Condition entry a.nd application of associated Requfred Actions .. When a line is isolated, the potential for an inadvertent scram due to high sov* level is increased, *During these periods; the line may be unisolated under administrative control. This allows any accumulated water i"n the line to b e . d r a in e d , to p re c l u de a. re act o r s c r a rri o n SD V h i g h 1 e v e 1 . ** This is acceptable sinc:e the aqminis.trative controls ens.ure* the valve can be closed qujckly, by a dedicated operator, if a s c r am b cc u r s wit h t h e v a 1 v e open .
• continued B 3.1-49 Revision No. 57 BASES SDV Vent and Drain Valves B 3.1.B ACTIONS A.l (continued) . PBAPS UN IT 2 When one SDV vent or drain valve is inoperable in one or more lines, the associated line must be isolated to contain the reactor coolant during a scram. The 7 day Completion Time is reasonable, given the level of redundancy in the and the low probability of a scram occurring during the time the valves are inoperable and the line is not isolated. The SDV ii still isolable since the redundant valve in the affected line is OPERABLE. During these periods, the single failure criterion may not be preserved, and a higher risk exists to allow reactor water but of the primary system during a scram. If both valves in a line are inoperable, the.line must be isolated to contain the reactor coolant during a scram. The 8 hour Completion Time to isolate the line is based on the low probability.of a scram occurring while the line is not fsolated and unlikelihood of significant CRD seal leakage.* C.l If any Required Action'and associated Completion Time is not met, the plant must be brought to a MODE in which the LCD does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable, on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without plant systems. (continued) B 3.1-50. Revision No. 57 SDV Vent and Drain Valves B 3.1.8 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.1.8.1 During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2 or SR 3.3.1.1.9 for Function 13, Manual Scram, of Table 3.3.1.1-1) to allow for drainage of the SDV piping. Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended functions during normal operation. This SR does not require any testing or valve manipulation; rather, it involves verification that the valves are in the correct position. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.8.2 During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping. Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function properly during a scram. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SDV vent and drain *valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of 15 seconds after receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis (Ref. 2). The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of control rods in LCO 3.1.3 overlap this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. (continued) B 3.1-51 Revision No. 86 BASES (continued) RE FERENC ES PBAPS UN IT. 2 1. SDV Vent and Drain Valves B 3.1.8 NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping," August 1981. 2. UFSAR, Sections 3.4.5.3.l and 7.2.3.6. 3. 10 CFR 50.67. B 3.1-52. Revision Nb. 86 "

APLHGR B 3.2.1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE CAPLHGR) BASES BACKGROUND A.PP LI CABLE SAFETY ANALYSES PBAPS UNIT 2. The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any a*xial location. Limits on the APLHGR are specified to ensure that the peak cladding temperature (PCT) during the postulated design basis loss of coolant accident CLOCA) d6es not exceed the limits specified in 10 C FR 50. 46. The analytical methods and assumptions used in evaluating Design Basis Accidents CDBAs) that determine the APLHGR l i m it s a re p re s en t e d i n Ref e re n c es 1 , 2 , 3 , 4 , 5 , an d 7 . continued B 3 .. 2-1 Revisioh No: 49 BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNIT 2 APLHGR B 3.2.1 LOCA analyses are performed to ensure that the APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR 50.46. The analysis is performed using calculational models that are consistent with the of 10 CFR 50, Appendix K. A complete discussion of the analysis code is provided in Reference 11. The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within an assembly. A conservative I* multiplier is applied to the LHGR assumed ih the LOCA analysis to account for the uncertainty associated with the measurement of APLHGR. For single recirculation loop operation, a conservative multiplier is applied to the APlHGR as specified in the COLR (Ref. 12). This is due to the conservative analysis assumption of an earlier from nucleate boiling with one loop available, resulting in a more severe cladding heatup during a LOCA. Power-dependent and flow-dependent APLHGR factors may also be provided per Reference 1 to that fuel design limits are not exceeded due to the occurrence of a postulated transient during operation at (less thari 100%) react6r or core flow conditions. factors are applied, if required, per the COLR and .decrease the allowable APLHGR value: The APLHGR Criterion 2 of the NRC Policy Statement. The APLHGR limits specified in the COLR are the result of the fuel design OBA analyses, The limits are developed as a function of exposure and are applied per the COLR. continued B 3.2-2

• No. 4g BASES LCO (continued) APPLICABILITY ACTIONS PBAPS UN IT 2 APLHGR B 3.2.1 With only one recirculation loop in operation, in conformance with the requirements of LCO 3.4.1, "Recirculation Loops Operating," the limit is determined by multiplying the exposure dependent APLHGR limit by a conservative factor. The APLHGR limits are primarily derived from LOCA analyses that are assumed to occur at high power levels. Design calculations (Ref. 6) and operating experience have shown that as power is reduced, the margin to the required APLHGR
• limits increases. This trend continues down to the power range of 5% to 15% RTP when entry into MODE 2 occurs. When in MODE 2, the wide range neutron monitor period-short scram function provides prompt scram initiation during any significant transient, thereby effectively removing.any APLHGR limit compliance concern in MODE 2. Therefore, at THERMAL POWER levels< 23% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCO is not required. If any APLHGR exceeds the required limits, an assumption regarding an initi.al condition of the OBA analyses may not be met. Therefore, prompt action should be taken to restore the APLHGR(s) to within the required limits such that the plant operates within analyzed conditions and within design limits of the fuel rods. The 2 hour Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a OBA occurring simultaneously with the APLHGR out of specification. If the APLHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 23% RTP within 4 hours. The continued B 3.2-3 Revision No. 114

. : -. BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 .8.......1 (continueq) APLHGR B 3.2.1 all.owed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly manner and without challenging plant systems. SR 3.2.1.1 APLHGRs are required to be initially calculated within 12 hours after THERMAL POWER is 23% RTP and then periodically thereafter. They are compared to the specified limits in the COLR to ensure that the reactor is operating within the of the safety analysis. The 12 hour allowance after THERMAL 23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. . . 1. "General Electric Standard Application for Reactor Fuel," la test approved revision. 2. UFSAR, Chapter 3. 3. UFSAR, 6.

• 4. UFSAR, Chapter 14. 5. NED0-24229-1, "Peach Bottom Atomic Power Station Units 2 and .3, Single Loop Operation," May 1980 .. 6.
• NEDC-32162P, "Maximum Exten*ded load Line Limit and ARTS Improvement Program Analyses for* Peach Bottom *.Atomic Power .2 and* 3*," Revision 2,_ March: )995 .. 7. "Safety Analysis Report for .Exelon Peach Bottom Atom i c P ciw e r St a t ion , U n i t s 2 a n d 3 , C o n st a n t Pressure* Power *upra.te," Revision o. 8. Deleted 9 .. *,,st'eady State Nuclear Methods' II Apr it 1985 .. . continued B3.2-4 No. 114 BASES RE FERENC ES (continued) PBAPS UNIT 2. 10. Deleted APLHGR B 3. 2 .1 11. NEDC-32163P, "Peach Bottom Atomic Power Sta ti on Units 2 and 3 SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis," January 1993. 12. Peach Bottom Unit 2 Core Operating Limits Report C COLR). B *
• Revisioh No. 49 MCPR B 3.2.2 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR) BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power. The MCPR Safety Limit (SL) is set such that of the fuel rods avoid boiling transition if the limit is not violated (refer to the Bases for SL 2.1.1.2). The operating limit MCPR is established to ensure that no fuel damage results during abnormal operational transients. Although fuel damage does not necessarily occur if a fuel rod actually experienced boiling transition (Ref. 1), the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion. The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs. Based on these experimental data, correlations have been developed to predict critical bundle power (i.e., the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling) .. Because plant operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures. due to inadequate cooling do not occur. The analytical methods and assumptions used in evaluating the abnormal operational transients to establish the operating limit MCPR are presented in References 2; 3, 4, 5,. 6, 7, 8, and 9. To ensure that the MCPR SL is not exceeded during any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR). The types of transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest change in CPR (&PR). When the largest &PR (corrected for analytical uncertainties) is added to the MCPR SL, the required operating limit MCPR is obtained.* (continued) Revision No.: 0 BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABifITY .... : PBAPS UN.IT .2 MCPR B 3.2.2 The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power state (MCPRt and respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Refs. 6, 7, 8, and 9). Flow dependent MCPR limits are determined by steady state thermal hydraulic methods with key physics response inputs benchmarked using the three dimensional BWR simulator code (Ref. 10) to analyze slow flow runout transients. The flow dependent operating limit, is evaluated based on a single .recirculation pump flow runout event (Ref. 9). _ Power dependent MCPR limits (MCPRP) are determined by the codes used to evaluate transients as described in Reference 2. Due to the sensitivity of the trarisient response to initial core flow levels at power levels below those at which the turbine stop valve cl6sure and turbine control valve fast closure scrams are bypassed, high and low flow limits .are provided for operating between 23% RTP and the mentioned bypass level .. The MCPR satisfies Criterion 2 of the NRC Policy Statement. The MCPR operafing limits specified. in the COLR are the result of the Design Basis Accident (OBA) and transient
• The operating limit MCPR is determined by the lar:ger of the MCPRf and MCPRP limits. The MCPR limits derived from transient analyses* fha:t *are assumed to occur at high power ow 23% the reactor is operating at a I.* minimum recirculation pump speed and the moderator void. ratfo is small .. Survei 11 ance of thermal limits below . 23% RTPcis unnecessa'ry due to the large inher,ent margin that
• 1 . ensures,.that'the-MCPl{SL is not exceeded eve.n if' a limiting *transient *occurs. Statistical a,nalyses 1 ndiCate that .the* nominal value of. the' initial MCPR expected at 23% RTP is > 3 . .5 . St u d-i e s : of t h e v a r i a t i on o f lim i t i n g t r a n s i en t behavior have been performed over the range of power and_ *continue **. B 3.2-7 Revision No. *114 .. * ;

BASES APPLICABILITY (continued) ACTIONS SU RV EI lLANC E REQU I PBAPS UNIT-2 MCPR B 3.2.2 flow conditions. *These studies encompass the range of key actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as power is reduced to 23% RTP. This trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs. When in MODE 2, the wide range neutron monitor period-short function provides rapid scram initiation for any significant power increase which effectively eliminates any MCPR compliance concern. Therefore, at THERMAL POWER levels < 23% RTP, the reactor is operating with margin to the MCPR limits and this LCO is not required. If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses not be Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed

• conditions. The 2 hour Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probability of a transient or OBA simultaneously with the MCPR out of s p e c i f ic a t i on . If the-MCPR cannot be restored to within 1ts -required limits within the assocfated:Cbmpletion Time, the plant must be brought to a MODE or other specified conditi.on in which the LCO does not apply. to this status, THERMAL POWER must be .reduced to < 23%-RTP w-ithin 4 hours. -The all owed I Comp.leti.on Time is r_easonable, based on operating experience-, to reduce THERMAL POWER to < 23% RTP in_ an_ -I orderly manner and wi_thout challenging pla_nt systems. --SR 3.2.2.1 The MCeR is-required to.be initial1y within .12 hours after THERMAL POWER* is*;::: 23% RTP _and period_ically -It is compared to specified limits --continued B 3.2-8 Revision No. 114 I BASES SURVEILLANCE REQUIREMENTS -REFERENCES PBAPS UNIT 2 SR 3.2.2.1 (continued) MCPR B 3.2.2 in the COLR (Ref. 12) to ensure that reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL 23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient analysis. SR 3.2.2.2 determines the value of T, which is a measure of the actual scram speed distribution compared with the assumed distribution. The MCPR operating limit is determined based on an interpolation between the applicable limits Option A (scram times of LCO 3.1.4,"Contrbl Rod Scram Times") and Option B (realistit scram times) analyses. parameter T must be determined once with.in 72 hours after each set of _scram time tests required by SR 3.1.4;1, SR 3.1.4.2, and SR 3.1.4.4 because the effective scram speed distribution may change during cycle .or after maintenance that could affect scram times. The 72 hour Time is acceptable due to the relatively minor Changes in T expected during the fuel cycle. -1. NUREG-0562, June 1979. 2. NED0-24011-P-A, "General Electric Standard Application for Reactor Fuel," la test approved revision. 3. UFSAR, Chapter 3. 4. UFSAR, Chapter 6. 5. UFSAR, Cha pte*r 14. -6. NED0-24229-1, "Peach Bottom Atomic Power Station Units 2 and 3, *single Loop Operat"ion," May 1980. continued B 3:2-9 Revision BASES REFERENCES (continued) .. . _,* PBAPS UN IT 2 7. MCPR B 3.2.2 NEDC-32162P, "Maxi-mum Extended Load Line Limit and ARTS Improvement Program Analyses for Peach Bottom Atomic Power Station Units 2 and 3," Revision 2, March 1995. 8. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 9. "Peach Bottom Atomic Power Station Unit 2 Cycle 11 ARTS Thermal Limits Analyses," December 1994. 10. NED0-30130-A, State Nuclear Methods," April 1985. 11. NED0-24154, "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors," October 1978. 12. Peach Bottom Unit 2 Core Operating Limits Report CCOLR)
• B 3.2-10
• Revision* *.114 /.

LHGR B 3.2.3 B 3.2 POWER DISTRIBUTION LIMITS B 3 .. 2.3 LINEAR HEAT GENERATION RATE (LHGR) BASES BACKGROUND APPLICABLE SAFETY ANALYSES . PBAPS UN IT 2 The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location. Limits on LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation, including abnormal operational transients. Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials. Fuel design limits are specified to ensure that fuel system damage, fuel rod failure, or inability to cool the fuel does not occur during the anticipated operating conditions identified in Reference 1. The analytical methods and assumptions used in evaluating the fuel design are presented in References l, 2, 3, 4, 7, 8, 11, and 12. The fuel is designed to I. ensure (in conjunction w1th the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release of radioactive materials in of the guidelines of iO Parts 20, 50, and 100, as applicable. The mechanisms that could cause fuel damage during operational transients and that are considered in fuel evaluations are: a. Rupture of the fuel rod cladding caused by strain from the relative expansion of the U02 pellet; and b. Severe overheating of the fuel rod cladding caused by .A value of 1% plastic strain of the fuel _cladding has been defined as the limit below which fuel damage caused bi oversfraini ng of the fuel .cladding is not expected to occur 'CRef. 9}, .. Fuel design eva1 uati_ons. have been per.formed and demonstrate that the 1% fuel cladding plastic strain design limit is not during c6ntinuous. operation with LHGRs up to .the operating lhnit specified in the COLR. The analysis also -.. ' continued B -3. 2-11 . Revisiqn No. 101 BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABILITY ACTIONS PBAPS UN IT 2 LHGR B 3.2.3 includes allowances for short term transient operation above the operating limit to account for abnormal operational transients, plus an allowance for densification power spiking. Power-dependent and flow-dependent LHGR adjustment factors may al so be 'provided per Reference 1 to ensure that fuel design limits are not exceeded due to the occurrence of a postulated event during operation at off-rated (less than 100%) reactor power or core conditions. These adjustment factors are applied, if required, per the COLR and decrease the allowable LHGR Additionally, for single recirculation loop operation, an LHGR multiplier may be provided per Reference 1. This multiplier is applied per the COLR and decreases the allowable LHGR value. This additional margin may be necessary during SLO to accbunt for the conservative analysis assumption of an earlier departure from nucleate boiling with only one recirculation loop available. The LHGR satisfies Criterion 2 of the NRC Policy Statement. The lHGR is a basic assumption in the fuel design analysis. The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to a 1% fuel cladding plastic strain. The operating limit to accomplish this. objective is specified in the COLR; The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions.* At core thermal power ievels < 23% RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore, Specification is only required when the is. operating at 23% RTP. If any LHGR exceeds its limit, an assumption an initial of the fuel design analysis is not Therefore, prompt action should be taken to restore the LHGR(s) to within its required.limits such that the plant is operating within analyzed conditions. The continued *B.3.2:-12 Revision Nb. 114 BASES ACTIONS I I PBAPS .UN IT 2 A.l (continued) LHGR B 3.2.3 2 hour Completion Time is normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the* low probability .of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification. If the LHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER is reduced to< 23% RTP within 4 hours. The allowed C6mpletion Time is reasonable, based on operating experience, to reduce THERMAL POWER TO < 23% RTP in an orderly manner and without challenging plant systems. (continued) B 3.2-12a Revision No. 114 LHGR B 3.2.3 BASES (continued) SURVEILLANCE REQUIREMENTS REFERENCES PBAPS*UNIT*2 .SR 3.2.3.1 The LHGR is required to be initially calculated within 12 hours after THERMAL POWER 23% RTP and periodically thereafter. It is compared to the specified limits in the COLR (Ref. 10) to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL 23% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. 2. 3. 4. 5. NED0-24011-P-A, "General Electric Standard Application for Reactor Fuel," late st approved revi sj on. UFSAR, Chapter 3. UFSAR, Chapter 6. UFSAR, Chapter 14. NED0-24229-1, "Peach Bottom Atomic Power Station Units 2 and 3, Single-Loop Operation," May 1980. 6. NEDC-32162P, "Maximum Extended Load Line Limit and ARTS Improvements Program Analyses for Peach Bottom *Atomic Power Station Units 2 and 3," Revision 2, March 1995. 7. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 8. NEDC-32163P, "Peach Bottom Atomic Power Station Units 2 and 3 SAFER/GESTRcLOCA Loss-of-Coolant Accident Analysis," January 1993. 9. NUREG-0800, Section 4.2, Subsection II.A.2(g), Revision 2, July 1981. 10. Peach Bottom Unit 2 Core Operating Limits Report (COLR). 11. G-080-VC-400, "Peach Bottom Atomic Power Station Units 2 & 3 GNF2 ECCS-LOCA Evaluation," GE Hitachi Nuclear Energy, 0000-0100-8531-Rl, March 2011. 12. "Peach Bottom Atomic Station ECCS-LOCA for GE14," General Electric .Company, GENE-Jll-03716-09-02P, July 2000. B 3 . .2-13 Revision No. 114 RPS Instrumentation B 3.3.1.1 B 3.3 INSTRUMENTATION B 3.3.1.l Reactor Protection System (RPS) Instrumentation BASES BACKGROUND *-* PBAPS UNIT 2 The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limits, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS) and minimize the energy that must be absorbed following a loss of coolant accident (LOCA). This can b_e *accomplished either automatically or manually. The protection and monitoring functions of RPS have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters and equipment performance. The LSSS are defined in this Specification as the Allowable Values, which, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits, Safety Limits (SLs) during Qesign Basis Accidents CDBAs).

• Jhe.RPS, as shown in the UFSAR Section 7.2, (Ref. 1), sensors, relays, bypass circuits, and switches that are necessary to cause initiation of a reactor scram .. Function al diversity i.s provided by monitoring a wide range of dependent and The input parameters-to *the scram logic are from.instrumentation that
• monitort vessel water level, vessel neutron flux, main steam Jihe isolation valve position, turbine control (TCV) fast trip oil turbine stqp valve (TSV) position, drywell pressure, scram discharge volume_ ( SDV) water level, . condenser vacuum,. as well .as reactor mode switch in shutdown posit.ion, manual scram signals, and RPS test switches. There fo0r redundant-input from -each 6f parameters the exception of scram sign.µl arid the. reactor.mode switch i.n shutdown scram *signal). Most chann_els include electronic equipment (e.g., trip units) that compares measured input signals with pre-establi-shed setpoints .. -When the setpoint is exceeded, the channel output relay actuates, which then-outputs an RPS trip sign(l_l the trip logic. * . (cont; nued) * .B 3. 3-1* Revision No. 134 BASES BACKGROUND (continued) PBAPS UNIT 2 RPS Instrumentation B 3.3.1.l The RPS is comprised of two independent trip systems (A and B) with three logic channels in each trip system (logic channels Al, A2, and A3; Bl, B2, and B3) as shown in the Reference 1 figures. Logic channels Al, A2, Bl, and B2 contain automatic logic for which the above monitored parameters each have at least one input to each of these logic channels. The outputs of the logic channels in a trip system are combined in a one-out-of-two logic so that either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram. This logic arrangement is referred to as a one-out-of-two taken twice logic. In addition to the automatic logic channels, logic channels A3 and B3 (one logic channel per trip system) are manual scram channels. Both must be depressed in order to initiate the manual trip function. Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is. received. This 10 second delay on reset ensures that the scram function will be completed. Two *scram pilot valves are located in the hydraulic control unit for each control rod drive (CRD). Each scram pilot valve is solenoid operated, with the solenoids normally energized. The scram pilot valves control the air supply-to the scram inlet and outlet valves for the associated CRD. When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to The scram valves control the supply and discharge paths for the CRD water during a scram. One of.the.scram pilot valve solenoids for *each CRD is controlled by trip system A, and the other solenoid is controlled by trjp system*e. Any trip of trip system A in conjunction with any trip in trip system B results in de-energizing both solenoids, air bleeding off, scram valves opening, and control rod scram.
• The scram valves, *which *Emergize .cm a scram signal to depressUrize the scram air header, are also controlled by the RPS. Additionally, the RPS controls the SDV vent and drain valves such that when logic channels Al and Bl are.
• deenergized or when logic channel A3. is deenergized (continued) ' ' Revision*No. O BASES BACKGROUND {continued) APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 2 RPS Instrumentation B 3.3.1.1 inboard SDV vent and drain valves close to isolate the SDV, and when logic channels A2 and 82 are deenergized or when logic channel 83 is deenergized the outboard SDV vent and drain *valves close to isolate the SDV. The actions of the RPS are assumed in the safety analyses of References 2 and 3. The RPS is required to initiate a reactor scram when monitored parameter values exceed the Allowable Values, specified by the setpoint methodology and listed in Table 3.3.1.1-1, to maintain OPERABILITY and to preserve the integrity of the fuel cladding, the reactor coolant pressure boundary (RCPB), and the containment, by minimizing the energy that must be absorbed following a LOCA.. . RPS instrumentation satisfies Criterion 3 of the NRC Policy Statement. Functions not specifically credited in the accident analysis are retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis. The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.1.1-1. Each Function must have a required number of OPERABLE channels per RPS :trip system, with their setpoints within the specified Allowable Value, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Allowable Values, where applicable, are specified for each RPS Function specified in the Table. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setting is not within its required Allowable Value. -Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of (continued) B 3.3-3 Revision No. o BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UNIT 2 RPS Instrumentation B 3.3.1.l the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic or design limits are derived from the limiting values of the process parameters obtained from the safety analysis or other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for calibration, process, and instrument errors. The trip set-points are determined from analytical or design limits, corrected for calibration, process,*and instrument errors, as well as instrument drift. In selected cases, the Allowable Values and trip setpoints are determined by engineering judgement or historically accepted practice relative to the intended function of the trip channel. The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environments during the operating time of the associated trip channels are accounted for. The OPERABILITY of scram pilot valves and associated solenoids, backup scram valves, and SDV valves, described in the Background section, are not addressed by this LCO. The individual Functions are required to be OPERABLE in the MODES or other specified conditions specified in the Table, which may require an RPS trip to mitigate the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to provide primary and diverse initiation The only MODES specified in Table 3.3.1.1-1 are MODES.I and 2, and MODE 5 with any-control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4, *since all control rods are fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow any control rod to be withdrawn. In MODE 5, control rods withdrawn from a* core ce 11 *contain i rig no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have the capability to scram. Provided all other control rods remain inserted, no RPS function is required. In this condition, the required SOM ,(LCO 3.1.1) and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS will occur. {continued) B 3;3-4 Revision No. O.

I BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UNIT 2 RPS Instrumentation B 3.3.1.l The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis. Wide Range Neutron Monitor CWRNM) I.a. Wide Range Neutron Monitor Period-Short The WRNMs provide signals to facilitate reactor scram in the event that core reactivity increase (shortening period) exceeds a predetermined reference rate-. -To determine the reactor period, the neutron flux signal is filtered. The period of this filtered neutroti flux signal is used to generate trip signals when the respective trip setpoints are exceeded. The time to trip for a particular reactor period is dependent on the filter time constant, actual period of the signal and the trip setpoints. This period based signal is available over the entire operating range from initial control rod withdrawal to full power operation. In the startup range, the most significant source of reactivity change is due to control rod withdrawal. The WRNM provides diverse protection from the rod worth minimizer (RWM), which monitors and controls the movement of control rods at low power. *The RWM prevents the withdrawal of an out of sequence control rod during startup that could result in an unacceptable neutron flux excursion (Ref. 2). The WRNM provides mitigation of the neutron flux excursion. To demonstrate the capability of the WRNM System to mitigate control rod withdrawal events, an analysis has been performed (Ref. 3) to evaluate the consequences of control rod withdrawal events during startup that are mitigated only by the WRNM period-short function. The withdrawal of a control rod out of sequence, during startup, analysis (Ref. 3) assumes that one WRNM channel in each trip system is bypassed, demonstrates that the WRNMs provide protection against local control rod withdrawal errors and results in peak fuel enthalpy below the 170 cal/gm fuel failure threshold criterion. The WRNMs are also capable of limiting other reactivity excursions during startup, such as cold water injection events, although no credit is specifically assumed. (continued) B 3.3-5 Revision No. 24 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY .. ,_,* PBAPS UNIT 2 RPS Instrumentation B 3.3.1.l I.a. Wide Range Neutron Monitor Period-Short {continued) The WRNM System is divided into two groups of WRNM channels, with four channels inputting to each trip system. The analysis of Reference 3 assumes that one channel in each trip system is bypassed. Therefore, six channels with three channels in each trip system are required for WRNM OPERABILITY to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The analysis of Reference 3 has adequate-conservatism to permit an Allowable Value of 13 seconds.

• The WRNM Period-Short Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential for criticality exists. In MODE 5, when a cell with fuel has its control rod withdrawn*, the WRNMs provide monitoring for.and protection against unexpected reactivity excursions. In MODE 1, the APRM System and the RWM provide protection against control rod withdrawal error events and the WRNMs are not required .. The WRNMs are automatically bypassed when the mode switch is in the Run position.
• Lb.* *Wide Range Neutron Monitor..:. Inop This trip signal provides assurance that aminimum number of WRNMs are OPERABLE. Anytime a WRNM mode switch is moved to
• any posltion other than "Operate," a loss of power occurs, or the self.:..test system detects a failure which would result in the loss of a safety-related function, an inoperative trip signal will be received by.the RPS unless the WRNM is bypassed. Since only one WRNM in each trip system may be only one WRNM in each RPS trip system may be inoperable without. result-ing'in an RPS trip signal. . . . : This _Fu*nction was not specific.ally credited in the accident analysis but it is retained for the. overall redundancy' and . d.iversity*.of Jh*e* required by the *NRC approved . licensing * * (continued) . ; . . B 3.3:...6 Revision No. 24
• BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UNIT' 2 RPS Instrumentation B 3.3.1.1 l.b. Wide Range Neutron Monitor-Inop (continued) Six channels of the Wide Range Neutron Monitor-Inop Function, with three channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. *Since this Function is not assumed the safety there is no Allowable Value for this Function. This is required to be OPERABLE when the Wide Range Neutron Monitor Period-Short Function is required. Average Power Range Monitor CAPRM) The APRM channels provide the primary indication of neutron within the core and respond almost instantaneously to neutron flux increases. The APRM channels receive input signals from the local power range monitors (LPRMs) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. Each APRM also includes an Oscillation Range Monitor (OPRM) Upscale Function which monit6rs small groups of LPRM signals to detect thermal-hydraulic instabilities. The,APRM System is into four APRM channels and four 2-out-of-4 voter channels. Each APRM.channel provides inputs to each of the four voter channels. The four voter . c h a n n el s are d i vi de d i. n to two g r o u p s of two ea ch , with ea c h group of two providing inputs to one RPS trip system. The is designed to allow APRM but no voter channels, to be bypassed. A triP, from any one unbypassed APRM will result in a "half-trip' in all four of the voter channels, but no trip inputs to. either RPS system. APRM trip Functions 2.a, 2.c, and 2.d* are voted i y from OPRM Upscale Funct1 on 2 .. f. Therefore, any Function 2.a, 2.b, 2.ci or 2.d trip from any two
• unbypassed APRM channels wnl in a full trir in each of the four voter channels, in turn results in two trip tnputsinto*each RPS trip system logic channel (Al, A2, Bl, and B2), thus resulting in a full scram signal. . Simi.lar. ly, a.Function 2rf trip.from two unbypassed APRM ch_annel s wi 11. result in a full trip from each of the four voter channels.* Three *of the four APRM channels and all four of the voter *channels are regui red to be. OPERABLE to *ensure t.hat no single failure wi 11 preclude a scram on a
• valid '.'i!gnal. . In ti on*, tq provide a9equate coverage of the entTre core, consistent with. the design bases for the APRM Functions 2.a, 2.b, and 2.c, at least 20 LPRM inputs, with. at .least three L_PRM inputs from each of the four axial *levels at which the LPRMs a re located, must be operable for each APRM channel, and the number of LPRM inputs that have become inoperable (and bypassed) since the last APRM * . CSR 3.3.1.1.2) must be less than ten for each . APRM channel. For the OPRM Upscale, Function 2.f., LPRMs are
• assigned to_"cells" of 3* or 4 detectors; A minimum 'of 8 **1 cells per channel, each with a>minimum Of 2 OPERABL:E LPRMs, must be OPERABLE for the* OPRM Upscale Function 2.f to be* OPERABLE. (continued) B 3.3-7 Revision.Nb. 124 BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY P_BAPS UN IT 2 RPS Instrumentation B 3.3.1.1 2.a. Average Range Monitor Neutron Flux-High CSetdown) (continued) For opera ti on at 1 ow power* (i.e., MODE 2), the Average Power Range Monitor Neutron Flux-High (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux-High (Setdown) *Function will provide a secondary scram to the Wide Range Neutron Monitor Period-Short Function because of the relative setpoints. At higher power levels, it is possible that the Average Power Range Monitor Neutron Flux-High (Setdown) Function will provide the primary trip signal for a corewide increase power.
• No specific safety analyses take direct credit for the
• Average Power Range Monitor Neutron Flux-High (Setdown) Function. this Function indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 23% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Therefore, it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER < 23% RTP. The Allowable Value is based cin preventing significant increases.in power when THERMAL POWER is< 23l RTP. -I The Average Power Range Monitor Neutron Flux-High (Setdown) Function must be OPERABLE during MODE 2 when rods may be withdrawn since the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux-High Function provides protection against reactivity transients and the RWM and rod block monitor protect against control rod withdrawal error events. 2.b. Average Power Range Monitor Simulated Thermal Power-High The Average Power Range Monitor Simulated Thermal Power-High Function monitors average neutron flux to approximate the THERMAL POWER being transferred to the reactor coolant. The APRM neutron flux is electronically filtered with a time constant representative of the fuel heat transfer dynamics to generate a signal proportional to the THERMAL POWER in the reactor. The trip level is varied as a function of recirculation drive flciw (i.e., at lower core flows, the setpoint is reduced proportional to the reduction in power experienced as core flow is reduced with a fixed control rod pattern) but is clamped at an upper limit that is always lower than the Average Power *Range Monitor Neutron Flux-High Function Allowable Value; A note is included, applicable when the plant is in single recirculation loop operation per* LCD which requires the flow value, used in the All-0wable Value equation, be reduced by AW: The value of.AW Cc o ntinued) B 3.3-8 R-evi si on No.-114

'*' : * .. BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UN IT 2 RPS Instrumentation B 3.3.1.1 2.b. Average Power Range Monitor Simulated Thermal (continued) is established to conservatively bound the inaccuracy created in the core flow/drive flow correlation due to back flow in the jet pumps associated with the inactive recirculation loop. The Allowable Value thus maintains thermal margins essentially unchanged from those for two loop operation. The value of plant specific and is defined in plant procedures. The Allowable Value equation for single loop operation is only valid for flows down to W = the Allowable Value does not go below 61.5% RTP. This is acceptable because back flow in the inactive recirculation loop is only evident with drive flows of approximately 35%. or greater (Reference 19). The Nominal Trip Setpoint CNTSP) and the as-found and as-left tolerances (Leave Alone Zone) were determined in accordance with Reference 10. The Average Power Range Monitor Simulated Thermal Power-High Function is not specifically credited in the safety analysis but is intended to provide an additional margin of protection from transient induced fuel damage during operation where recirculation flow is reduced to below the minimum required for rated power operation. The Average

• Power Range Monitor Simulated Thermal Power-High Function provides protection against transients where THERMAL POWER increases slowly (such as the loss of feedwater heating event) and protects the fuel cladding integrity by ensuring *that.the MCPR SL is not exceeded. During these events, the THERMAL POWER increase does not significantly lag the neutron flux scram. For rapid neutron flux increase events, the THERMAL POWER lags the neutron flux and the Average Power Range Monitor Neutron Flux-High Functi.on will provide a scram signal before the Average Power Range Monitor Simulated Thermal Power-High Function setpoint is exceeded .. *Each APRM thannel uses one total drive flow*signal .representative of total core flow .. The total drive flow signal is generated by the flow processing logic, part of the APRM channel, by up the flow .calculated from two flow signal one from each of the twci recirculation loop flows. The flow processing logic OPERABILITY is part of the APRM channel OPERABILITY requirements for this Function. The APRM flow processing logic is considered whenever it cannot deliver a flow signal less than or .equal to actual Recirculation flow conditions for all steady state and transient reactor
• tonditions while in Mode 1. Reduced or Dowriscale flow . conditions. due.to planned maintenance or testing activities . d ur i n g de rated pl ant con d it i on s C i . e . end .of cy cl e coast down) will in conservative setpoints for the APRM Simulated Thermal Power7High function, thus:maintaining that
• funttion operable. * * 'continued B 3.3-9 **.Revision No. 114.

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 2 RPS Instrumentation B 3.3.1.1 2.b. Average Power Range Monitor Simulated Thermal Power-High (continued} The Allowable Value is based on analyses that take credit for the Average Power Range Monitor Simulated Thermal High Function for the mitigation of non-limiting events. The THERMAL POWER time constant of < 7 seconds is based on the fuel heat transfer dynamics and provides a signal proportional to the THERMAL The Average Power Range Monitor Simulated Thermal Power-High Function is required to be OPERABLE in MODE 1 when there is the possibility of generating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR SL}. During MODES 2 and 5, other WRNM and APRM Functions provide protection for fuel cladding integrity. 2.c. Average Power Range Monitor Neutron Flux-High The Average Power Range Monitor Neutron Flux-High Function is capable of generating a trip signal to prevent fuel damage or excessive RCS pressure. For the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Neutron Flux-High Function is assumed to terminate the main steam isolation valve (MSIV) closure event and, along with the safety/relief valves (S/RVs}, limit the peak reactor pressure vessel (RPV} pressure to less than the ASME Code limits. The control rod drop accident (CRDA) analysis (Ref. 5) takes credit for the Average Power Range Monitor Neutron Flux-High Function to terminate the CRDA. (continued) B 3.3-10 Revision No. 36 I ' :* . . :,;' .**:. : *. i" " **' . '. BASES APPLICABLE SAFETY ANALYSES, LCO,. and APPLICABILITY :*.* -. ""' *' -'*: . **/* :**** ... .. !* . . *. " *-RPS Instrumentation B 3.3.1.1 2.c. Average Power Range Monitor Neutron Flux-High {contiriued) * * *

• The Allowable Value is based on the Analytital Limit assume.d in the CRDA analysis. *
• The Average Power Range Monitor Neutron Flux-High Function is required to be OPERABLE in MODE I where the potential consequences of the analyzed transients could result in the SL.s (e.g. , MCPR and RCS pres sure) being exceeded. . Al tho_ugh the Average Power Range Monitor Neutron Flux-High Function is assumed. in the CRDA analysis; which is applicable in MODE 2, the Average Power Range Monitor Neutron Flux-High {Setdown) Function conservatively bounds the assumed trip and, together with the assumed WRNM trips, provides adequate
• protection. Therefore; the Average Power Range Monitor .Neutron Ffox:..:HighFunction is not required in MODE 2. '. *. **. ,** ***. *.*. . ._;:*-.. -* ,, I . -.. -** ... *.,,* :**;-; .*' **,: *. ; ... *. , .... * ;y . . *_) ; . . . . . ' . *. (continued) . . . --: '* . . .. .. . . ' .. *: .. . *_: :-. ';*' -* .. _-,:.<:. ..:.'*. : I. . * ... * .. ' . . -..
• Nb. 36 * . *,* **. . -.. . -. -. ,,; .. .. . " . *. <

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UNIT 2 2.d. Average Power Range Monitor-Inop RPS Instrumentation B 3.3.1.1 Three of the four APRM channels are required to be OPERABLE for each of the APRM Functions. This Function (Inop) provides assurance that the minimum number of APRM channels are OPERABLE. For any APRM channel, any time its mode switch is not in the "Operate" position, an APRM module required to issue a trip is unplugged, or the automatic self-test system detects a critical fault with the APRM channel, an Inop trip is sent to all four voter channels. Inop trips from two or more unbypassed APRM channels result in a trip output from each of the four voter channels to it's associated trip system. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis. There is rio Allowable for this Function. This is required to be OPERABLE in the MODES where the APRM Functions are 2.e. 2-0ut-Of-4 Voter The Voter Function provides the interface between the APRM Functions, including the OPRM Upscale Function, and the final RPS trip system. logic. As such, it is required to be OPERABLE in the MODES where the APRM Functions are required and is necessary to support the safety analysis applicable to each of those Functions. Therefore, the 2c0ut-Of-4 Voter Function to be in MODES 1 and 2. A 11 four voter channels a re re qui red to be OPERABLE. Each voter channel includes self-diagnostic functions. If any voter channel detects a critical fault in its own proc*essi.ng, a.trip is issued from that voter channel to the associated trip -' -* The Log-ic .Module includes Voter hardware and the APRM -The Voter Function votes APRM Functions 2.a, 2.b, _2.c and 2.d independently cit Furiction 2 .. f. This voting is accomplished by the Voter hardware in the logic Module. Eath Voter includes redundant sets of outputs to RPS. two independent contacts; one contatt-for Functidns 2.a, 2.b, and 2:d, and the other : *contact for-Function 2.f .. The analysis in-Reference 12 took credit -for this redundancy in* the justification of the 12-hour Completipn Time for Condition A, so Function 2.e . must be.declared inoperable if any of its functionality is-. inoperab)e. However, the v*oter Function 2.e does not need to be inoperable due to fBilure affecting only the *plant iritetface portions of the Lbgic Module that are not necessary to pe.dorm the 2-0ut--Of-4 Voter function. -There is no Allowable Value for this -Functi9n. (c-ontioued) _ B 3.3cl2 Revision No. 50 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY * (continued) PSAPS UNIT 2 RPS Instrumentation B 3.3.1.1 2.f. Oscillation Power Range Monitor (OPRM) Upscale The OPRM Upscale Function provides compliance with 10 CFR 50, Appendix A, General Design Criteria (GDC) 10 and 12, thereby providing protection from exceeding the fuel MCPR safety limit (SL) due to anticipated thermal-hydraulic power oscillations. Reference 22 describes the Detect and Suppress-Confirmation Density (DSS-CD) long-term stability solution and the 11censing basis Confirmation Density Algorithm (CDA). Reference 22 also describes the DSS-CD Armed Region and the three additional algorithms for detecting thermal-hydraulic instability related neutron flux oscillations: the period based detection algorithm ( PBDA), the amplitude based algorithm (ASA), and the growth rate algorithm (GRA); All four algorithms are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the CDA. The remaining three algorithms provide defense-in-depth and additional protection against unanticipated oscillations. OPRM Upscale Function OPERABILITY based only on the CDA. The OPRM Upscale Function receives signals from the local power range monitors (LPRMs) within the reactor core, which are combined into cells for evaluation by the OPRM algorithms. OSS-CD operability requires at least 8 responsive OPRM cells per The DSS-CD software includes .a self-check for resp6nsive OPRM cells; therefore, no SR is necessary. The OPRM Upscale Function is required to be OPERABLE when ihe plant 18% RTP, which is established as a power level that is greater than or equal to 5% below the lower boundary of the Armed Region. This requirement is designed to encompass the region of power-flow operation where anticipated events could lead to thermal-hydraulic instability and related neutron flux oscillations. The OPRM Upscale Function is automatically eHabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 23% RTP corresponding to the MCPR monitoring threshold and reactor recirculation drive is less than of rated f1ow. This region is the OPRM Armed Region. Note (h) allows for entry into the DSS-CD Armed Region without automatic arming of DSS-CD prior to completely passing the DSS-CD Armed Region during the first startup and the first shutdown following DSS-CD (continued) B 3.3-12a Revision No. 123: '".*. .*.*, BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 2 2.f. Oscillation Power Range Monitor (OPRM) Upscale (continued) RPS Instrumentation B 3.3.1.l As described in Reference 22 and 24, the RTP values for the OPRM Upscale Function to be OPERABLE 18% RTP) and for the OPRM Upscale Function to be auto-enabled 23% RTP) are sufficiently conservative for protection of the plant against thermal-hydraulic instabilities. The basis for the 5% RTP difference between the OPRM Upscale OPERABLE (18% RTP) and OPRM Upscale auto-enable.value (23% RTP) is to ensure that no credible event, e.g., loss of feed water heating, could result in a plant power excursion where an irioperable OPRM channel entered into the OPRM Armed Region. Peach Bottom plant specific analyses performed these low power levels (Reference 24) have demonstrated that any power excursi-0n resulting from credible events is bounded by 5% RTP. In addition, both the core-wide and channel decay ratios the OPRM Upscale values are extremely low as documented in Reference 22, which demonstrates the low possibility of thermal-hydraulic instabilities at low power and confirms the conservatisms in the OPRM Upscale Function auto-enable RTP value. The conservatisms in the determination of the values for OPRM Upscale Function OPERABLE and the OPRM Upscale Function auto enabled sufficiently compensate for possible inaccuracy of the APRM simulated thermal power signal versus actual core thermal power at power levels< 23% RTP. Therefore, there is no need to perform any calibration of the APRM simulated thermal power signal to calculated power with RTP < 23% in order to determine the OPRM Upscale Function OPERABLE. If any OPRM auto-enable setpoint is in a .non-conservative i.e., the OPRM Upscale is not auto-enabled with RTP 23% and reactor drive flows 75% of rated, the channel is tonsidered inoperable for the OPRM Upscale function. Alternatively, the auto-enable setpoint may be adjusted to place the channel .in a conservative (armed). If placed in the armed conditton, the channel _is considered OPERABLE. Note (h) reflects the need for plant data collection in order to test the DSS"CD equipment. Testing the DSS-CD equipment its proper and prevents reactor -trips. Entry into the DSS-CD Armed Region without automatic arming of DSS-CD during this initial. testing phase also allows for changes in operations to address or other operational needs. However, during this initial testing period, the OPRM Upscale Function is OPERABLE.and 'DSS:CD operability and capability to automatically arm shall be at* rectrculation drive flow above the DSS-CD Armed Region flow boundary. (continued) B 3.3-12b Revision No. 123 BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UNIT 2 2.f. Oscillation Power Range Monitor (OPRM) Upscale (continued) RPS Instrumentation B 3.3.1.1 An OPRM Upscale trip is issued from an OPRM channel when the confirmation density algorithm in that channel detects osciilatory changes in the neutron flux, indicated by periodic confirmations and amplitude exceeding specified setpoints for a specified number of OPRM cells in the channel. An OPRM Upscale trip is al so issued from the channel if any of the defense-in-depth algorithms CPBDA, ABA, GRA) exceed their trip condition for one or more cells in that channel. Three of the four channels are required to be operable. Each channel is capable of detecting thermal-hydraulic instabilities, by detecting the related neutron flux oscillations, and issutng a trip signal before the SLMCPR is exceeded. There is no Allowable Value for this function. The OPRM Upscale Function is not LSSS SL-related (Ref. 22) and Reference 23 confirms that the OPRM Upscale Function settings based on DSS-CD also do not have traditional instrumentation setpoints determined under an instrument setpoint methodology. (continued) B 3.3-12c Revision No. 123 I BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY {continued) PBAPS UNIT 2. 3. Reactor Pressure--Hiqh RPS Instrumentation B 3.3.1.1 An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This causes the neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. No specific safety analysis takes direct credit for this function. However, the Reactor Pressure--High function initiates a scram for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core power. For the overpressurization protect1on*analysis of Reference 4, the . Reactor Pressure--High Function is credited as a backup Scram Function only. The analyses conservatively assume the scram occurs on the Average Power Range Monitor Scram Clamp signal, not the Reactor Pressure--High signal. The reactor scram, along with the S/RVs, limits the peak RPV pressure to less than the ASME Section III Code limits. High reactor pressure signals are initiated from four pressure transmitters that sense reactor pressure. The Reactor Pressure--High.Allowable Value is chosen to provide a sufficient margin to the ASME Section III Code limits . during the event . . Four channels o:f Reactor Pressure:--High Function, with two channels in each tri:P. system arranged in a one-out-of-two are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is required to be OPERABLE MODES*I and 2 when the RCS is and the potential for pressure increase exists. 4. Reactor Vessel Water Level :....:.Low °<Level 3)

• Low RPV level the capability to. cool the ** file l may be threatened *.
• Shotil RPV water -1 eve l decrease t.oo far, fuel damage.could result.* Therefore, a reactor scram is initfated at Level 3 to substantially reduce the heat generated in the fuel from fission. The Reactor Vessel Water LeVel-"Low(Level 3) _Function is assumed in the .analysis of events resulting in the decrease of reactor coolant inventory (Ref. 6).* This is credited as a backup scram .. function for large and intermediate break LOCAs iilside * *. (continued) *. B 3.3-13
• Revision No. 0 .i-.

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 2 .-. '. RPS Instrumentation B 3.3.1.l 4. Reactor Vessel Water Level -Low (Level 3) (continued) primary containment. The reactor scram reduces the amount of energy required to be absorbed and, along with the. actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Reactor Vessel Water Level-low (Level 3) signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of . water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four .channels of Reactor Vessel Water Level---Low (Level 3) Function., with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid si:gnal. The Reactor Vessel Water Level-Low (Level 3) Allowable Value is selected to ensure that during normal operation the separator skirts are not uncovered (this protects available recirculation pump net positive suction head (NPSH) from significant carryunder) and, for transients involving loss of all normal feedwater flow; initiation of the low pressure ECCS subsystems at Reactor Vessel Water-Low Low Low (Level I) will. not be required.

• The *Function is required in MODES 1 and 2 where considerable energy extsts in the RCS resulting in the limiting transients and accidents.
• ECCS initiations at Reactor Vessel Water Level-Low Low (Level 2) and Low Low Low (level 1) provide sufficient protection for level transients in all other MODES. 5. Main Steam Isolation Valve-Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the nuclear steam supply system and indicates a need to shut down the reactor to reduce heat generation. Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs are completely closed in anticipation of the complete loss bf the normal heat sink and subsequent overpressurization (continued) B 3.3-14 Revision No. O I. I BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS *UN IT 2 RPS Instrumentation B 3.3.1.1 5. Main Steam Isolation Valve-Closure (continued) transient. However, for the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Scram Clamp Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Section III Code limits. That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis. The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B *. Thus, each RPS trip system receives an input from eight Main Steam Isolation Valve-Closure* channels, each consisting of one position switch. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam lines must close in order for a scram to occur. In addition, certain combinations of valves closed in two lines will result in a half-scram. The Main Steam Isolation Valve.:.......closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam fl ow, thereby reducing the severity of the stibsequentpressure transient. . Eight channels of the Main Steam Isolation Valve-Closure Function, with four channels in each trip system, are * *required to be OPERABLE to ensure that no single instrument fail lire will prec 1-ude the scram from th i's Function on a
• va.lid This Function is only required in MODE 1 .since, with the MSIVs open and the heat generation rate high,. a pressurization transient can occur if the MSIVs close. In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection. (continued) B 3.3-15 *Revis-Ion No. O BASES APPLICABLE SAFETY ANALYSES, LCD, and
• APPLICABILITY *(continued) PBAPS UNIT 2 6. Drywell Pressure--High RPS Instrumentation B 3.3.1.l High pressure in the drywell could indicate a break in the RCPB. A reactor scram is initiated to minimize the possibility of fuel damage and to reduce the amount of energy being added to the coolant and the drywell. The Drywell Pressure--High Function is assumed to scram the reactor during large and intermediate break LOCAs inside primary containment. The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the .fuel peak cladding temperature remains below the limits of IO CFR 50.46. High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and indicative of a LOCA inside primary containment. Four channels of Drywell Pressure--High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single* instrument failure will preclude a scram from this Function on a valid signal. The Function is required in MODES I and 2 where considerable energy exists in the RCS, resulting .in the limiting transients and accidents. 7.
• Scram Discharge Volume Water level--High The SDV receives* the water displaced by the motion of the CRD pistons during a reactor scram. Should this volume fill to a point where there is insufficient volume to accept the displaced water, control rod insertion would be hindered. Therefore, a reactor scram is initiated while the remaining free volume is still sufficient to accommodate the water from a full core scram. No credit is taken for a scram initiated from the Scram Discharge Volume Water level--High Function for any of the design basis accidents or transients analyzed in the UFSAR. However, this function is retained to ensure the RPS remains OPERABLE. (continued) B 3.3..:16 Revision No. 0 BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UN IT 2 RPS Instrumentation B 3.3.1.1 7. Scram Discharge Volume Water Level-High (continued) SDV water level is measured by two diverse methods. The is measured by two float type level switches and two thermal probes for a total of four level signals. The outputs of these devices are arranged so that one switch provides input to one RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference 8. The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accommodate the water from a full scram. FOur high water level inputs to the RPS from four switches are required to be OPERABLE, with two switches in each trip system, to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required in MODES 1 and 2, and in MODE 5 with any tontrol rod withdrawn from a core cell containing one or more fuel since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed. 8. Turbine Closure. of the TSVs results in the loss of a heat sink that produces reactor neutron flux, and heat flux that.must be limited. Therefore, a reactor scram is initiated at the start of TSV *closure in anticipation Of tr?nsients result from the closure of these valves. The Turbine Stop Valve-Closure Function is the trip event analyzed tn Refetence 7 and the feedwater cohtroller .event. *For these _events, the-reactor scrarri reduce_s the amount of energy requ.i red to 'be absorbed and* ensures that the MCPR SL is not exceeded.* ' . *. . .. . . Turbine:Stop Valve-Closure signals are initiated from four p o s it i on s wit c he s ; on e *l o c _a t e d on e a c h of* t-h e fo u r TS V s . Each swttch provides _two"input signali; one to RPS trip . system A and the other, To .RPS trip system B; Thus, each .*. RPS. fri p system receives an. input from four Turbine Stqp Valv*e....,.Cl6sure channeis .. The 109i,c for the Turbine Stop* continued B 3.3-17 Revision No. 87 I BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY -PBAPS UNIT-2 RPS Instrumentation . B 3.3.1.1 8. Turbine Stop Valve-Closure (continued) Valve-Closure Function is such *that three or more TSVs must be closed to produce a scram. In addition, certain combinations of two valves closed will result in a scram. This Function must be enabled at THERMAL POWER 26.7% RTP as measured at the turbine first stage pressure. This is normally accomplished automatically by pressure sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function. The Turbine Stop Valve-Closure Allowable VAlue is selected to be high enough to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient. Eight channels of Turbine Stop Valve-Closure Function, with four channels in each trip system, are required to be to ensure that no single instrument failure will preclude a scram from this Function if any three TSVs should close. This Function is required, consistent with analysis whenever THERMAL POWER is RTP. This I. Function is not required when THERMAL POWER is < 26.7% RTP . since the Reactor Pressure-High and the Average Power Range Monitor Scram Clamp Functions are adequate to maintain the _necessary safety margirisi 9. Turbine Control Valve Fast Closure. *Trip Oil Pressure-Low Fast TCVs results in the of a heat sink that produces reactor pres'sure-, neutron *flux, and heat flux transients that.must be limited. Therefore, a reactor scram . is initiated on TCV in anticipation of the transients that would result from the closure of these valves.<-The Turbine* control Valve.Fast Closure, .Trip-oi*l Pressure-Low Function ts.the primary scram signal for.the g*enerator load rejection event analyzed in Reference 7 an*d the load rejection-with bypass failure event. For these even-ts, the reactor scram reduc.es _the amount of_ energy -required to be absorb.ed and ensures that the MCPR. SL is not -*exceeded.
• continued -B 3.;J-18 _Revision No. 114 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UN IT 2 RPS Instrumentation B 3.3.1.1 9. Turbine Control Valve Fast Closure. Trip Oil Pressure-Low (continued) Turbine Control Valve Fast Closure, Trip Oil Pressure-Low signals are initiated by the relayed emergency trip supply oil pressure at each control valve. One pressure switch is associated with each control valve, and the signal from each switch is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL 26.7% RTP. This is normally accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function. The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure. Four channels of Turbine Control Valve Fast Closure, Trip Oil Pressure-Low. Function with two channels in each trip system arranged in a logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required, consistent with the analysis assumptions, whenever THERMAL POWER is 26,7% RTP. This* Function is not required when THERMAL POWER is < 26.7% RTP, since the Reactor Pressure-High and the Average Power Ringe Monitor Scram Clamp Functions are adequate to maintain the necessary safety margins;*
• lD. Turbine Condenser-L6w Vacuum . . **The Turbine Condenser-low Vacuum Function protects the' integrity of the condenser by scramming the reactor thereby the severity of the low condenser vacuum transient on the This function also integrity of reactor due to loss of its normal heat: s:ink. The reactor scram on a Turbine Condenser-Low Vacuum*** signal will occur prior to a reactor scram.from a Turbine Stop Valve-Closure $ignal. This function is not specifically credited in any accident analysis but is being retained fbr the overall redundancy and diversity of the RPS as by the NRC approved licehsing basis. continued 8 3.3-19 Revision No. 114 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 2 RPS Instrumentation B 3.3.1.1 10. Turbine Condenser-Low Vacuum (continued) Turbine Condenser-Low Vacuum signals are initiated from four vacuum pressure transmitters that provide inputs to associated trip systems. There are two trip systems and two channels per trip system. Each trip system is arranged in a one-out-of-two logic and both trip systems must be tripped in order to scram the reactor. The Turbine Condenser-Low Vacuum Allowable Value is specified to ensure that a scram occurs prior to the integrity of the main condenser being breached, thereby limitirtg the damage to the normal heat sink of the reactor. Four channels of the Turbine Condenser-Low Vacuum Function with two channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from th1 s function on a valid signal. This Function is only required in MODE 1 where considerable energy exists which could challenge the integrity of the main condenier if vacuum is low. In MODE 2, the Turbine Condenser-Low Vacuum Function is not required because at low power levels the transients are less severe. 11. Deleted con inued B 3.3-20 Revision No. 134 BASES APPLICABLE SAFETY ANALYSES, LCO, and . APPLICABILITY .. _,--* *.. ' . . PBAPS 2 RPS Instrumentation B 3.3.1.1 12. Reactor Mode Switch-Shutdown Position The Reactor Mode Switch-Shutdown Position Function provides signals, via the manual scram logic channels, directly to the scram pilot solenoid power circuits. These manual scram logic channels are redundant to the automatic protective instrumentation and provide manual reactor trip capability. This Function was not specifically credited in the analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis. The reactor mode switch is a keylock four-position, bank switch. The reactor mode switch is capable of scramming the reactor if the mode switch is placed in the shutdown position. Scram signals from the mode switch are input into each of the two RPS manual scram logic channels. There no Allowable Value for .this Function, since the channels are mechanically actuated based solely on reactor mocte switch position.* * * . . -. *Two channels of Reactor Mode Switch-Shutdown Position Function, with 'one channel in each scram trip_ system, are available and required to be OPERABLE. The Reactor Mode Switch*7Shutdowri Pcisiti on Function is required to be OPERABL[ in MODES 1 and 2, and MODE 5 any control rod core tell containing 6ne or more fuel assemblies, since these are the MODES and other specified conditions* when control rods withdrawn
• B 3.3-21. . *** ,* <continued) Revision No. 134 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UNIT 2 13. Manual Scram RPS Instrumentation B 3.3.1.1 The Manual Scram push button channels provide signals, via the manual scram logic channels, directly to the scram pilot solenoid power circuits. These manual scram logic channels are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis. There is one Manual Scram push button channel for each of the two RPS manual scram logic channels. In order to cause a scram it is necessary that each channel in both manual scram trip systems be actuated. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons. Two channels of Manual Scram with one channel in each manual scram trip system are available and* required to be OPERABLE in MODES I and 2, and in MODE 5 with any.control rod withdrawn from a core cell containing one or more fuel these are the MODES and other specified conditions when control rods are withdrawn. 14. RPS Channel Test Switch There.are four RPS Channel Test Switches, one associated with each of the four automatic scram logic channels (Al, A2, Bl, and 82). These keylock switches allow the operator to test the OPERABILITY of each individual logic channel without the necessity of using a scram function trip. This is accomplished by placing the RPS Channel Test Switch in test, which will input a trip signal into the associated RPS logic channel. The RPS Channel Test Switches were not specifically credited in the accident analysis. However, because the Manual Scram Functions at Peach Bottom Atomic Power Station, were not configured the same qS the generic model in Reference 9, the RPS Channel Test Switches were included in the analysis in Reference lO. Reference 10 concluded that the Surveillance Frequency extensions from (continued) B Revision No .. 0

,;, * .. ' .. , ..... ..... *--, I.*. , .. *.* ,** .. ' ..... ,_* r'. BASES RPS Instrumentation B 3.3.Ll APPLICABLE SAFETY ANALYSES, LCO, and .. 14. RPS Channel Test Switch (continued) RPS *Fun.ct ions, described in Reference 9, were not affected by. the difference in configuration, since each automatic RPS channel has a test switch which is functionally the same as the manual scram switches .in the generic model. As such, the RPS Channel Test Switches retained in the Technical APPLICABILITY .... ".'. ACTIONS . '. . -. . ' . PBAPS'UNrt*t Specifications. no Allowable Value for this since the channels are mechanically actuated on the

• position of the switches. *
• Four channels bf RPS Channel Test Switch with twb channels in trip arranged in a logic are* available and required to be OPERABLE in MODES 1 and 2, and . in MODE 5 with any control rod withdrawn from a core eel l containing one or more fuel assemblies, since these are the -MODES and other specified conditions when control rods are withdrawn. * . . . -. . .. .* A Note has been provided to modify the ACTIONS related 1:0 RPS instrumentation channels. Section 1.3, Completion Times, that once a Condition has been entered, ... . subsequent divisions, components, or variablei expressed in the Condition, discovered to be inoperab.le or not within limits, will.not result in separate entry irito the Condition .. Section 1.3 also specifies that Required *Actions of the Condition continue to apply for each * *.additional failure, with Completion Times based on initial .. * *. entry into the Condition. Hpwever, .the Reqi:tfred Acticms fot . inoperable RPS fostrumentat i ori channels provide appropriate compensatory measures for separate-inoperable channels. As * *such, a Not_e has been provided that a 11 ows separate ..
• Condition entry for each.*inoperable RPS. instrumentation
• cha.nnel. * * * * * . A.I and A.2 . , : * . * -. * ;
• Because of the d*iversity of sensors available to provide* .trip signals and the redundancy of the RPS design,_ ah *
• out -0f _service time of 12 has been.shown to *be acceptable. 9/ 12 & 13} to permit restoration of . **.*any inoperable* channel to OPERABLE status.*. However, this * 'out *of service time is' only _accepta'ble provided the**.. .,, .. associated * * * * *ccontinuedl
• B 3.3-23 ..... Revision No. 36 BASES ACTIONS PBAPS UNIT 2 A.l and A.2 (continued) RPS Instrumentation B 3.3.1.1 Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternatively, if it is not place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Condition D must be entered and its Required Action taken. As noted, Action A.2 is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of one required channel affects both trip For that condition, Required Action A.l must be satisfied, and is the only action (other than restoring operability) that will restore capability to accommodate a single failure. Inoperability .of more than one required APRM channel of the same trip function results in loss of trip capability and entry into Condition C, as well as entry into Condition A for each channel. B.1 and B.2 Condition B exists when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE, the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system. Required Actions B.1 and B.2 limit the time the RPS scram logic, for any Function, would not accommodate single failure in both trip systems (e.g., one-out-of-one and one-out-of-one arrangement for a typical four channel Function). The reduced reliability of this logic arrangement was not evaluated in References 9, 12 or 13 for the 12 hour Completion Time. Within the 6 hour allowance, the associated Function will have all required channels OPERABLE or in trip (or any combination) in one trip system. (continued .B 3.3-24 Revision No. 50 BASES ACTIONS UN.IT .2 -----------B.1 and B.2 (continued) RPS Instrumentation B 3.3.1.1 Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in References 9, 12 or 13, which justified a 12 hour allowable out of service time as presented in Condition A. The trip system in the more degraded state should be placed in trip or, alternatively, all the inoperable in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions). The decision of which trip is in the more degraded state should be based on pr0dent judgment and take into account current plant conditions (i.e .. , what MODE the plant is in). If this action would result in a scram or RPT, it is permissible .to place the other trip system or its inoperable channels in trip. The 6 h6ur Completion Time is judged acceptable based on the remaining capability to trip. the diversity of the sensors available to provide the trip signals, the low probability of .extensive numbers of i noperabi l i ti es* affecting all diverse Furittions, and the low probability of an event requiring the initiatfon of .a scram. Alternately, Hit is not desir.ed to place the inoperable system) in trip (e.g., as in the case where pl icing the. channel or associated trip system in. trip would result in a scram, Condition D must be entered its Required taken. ' -As ,no.ted,
• ti on B 'is not appli.cab le for .APRM Functions 2.a, 2.g; 2.c, 2.d, or 2.f .. lnoperab:ility of an APRM channel-affects both trip systems and is not associated with *.a specific trip system. as are th*e APRM 2.c:dut-Of-4 voter. and. other n9n-;APRM c:hannels for which Condition B applies:*. For an inop.erable APRM channel, .Required Acti.on A:l must be. sa.tisfied, and is the only action Cother than restoring. >*op,erabllity)' t.hat will'restbr.e ity to ac.c.ommodate. a single faifore; :Inoperability of a in more than : one channel results in loss of trip capability f o r th a t Eun ct i o n a n d en t r y i n to Con d i. ti on C , a s we 11 a s
• entry irit6.Conditi6n A for channel. Because A and. C ptovi de Requi re .. d Actions that are appropriate for the inoperability.of.f\PRM Functions2.a, 2.b, 2.c, 2.d,.or: 2.f; C)nd these functions are.not associated. with specific trip systems as are the APRM 2.-0ut-Of-4 voter and other APRM channels; Condition i3 does n-ot apply. Cc Ont i nued ' . Revision N6. 50 I I

'BASES ACTIONS (continued) . _._-* .. ' . ; ' .. -*, ' .. .. '* .. **:* . : .. -.*.-. PBAPS * .. UNIT.*. 2 Cl RPS Instrumentation . B Required Actirin C.l. is intended to ensure that appropriate actions*are taken. if multiple, inoperable, untripped . channels within the same trip system for the same Function *result in an automatic Function, or two or more manual .Functions, not maintaining RPS trip capability. A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), such that both trip systems w-il l generate a trip signal from the given Function on a.valid signal. For the typical Function with one-out-. taken twice logic and the IRM and APRM Functions, this woul(:!require both trip systems to have one channel OPERABLE or in trip (or the associated trip system iri trip). For Fimction 5 (Matn Steam Isolation Valve-Closure), this .. w6uld require both trip systems to have each channel . with the MSIVs in three main steam lines (not necessarily the.same main.steam lines for both trip systems)OPERABLE or irl*trip (or the associated trip system in trip). For Function 8 (Turbine Stop Valve-Closure),

• this _would require both trip systems to 'hav*e three each.OPERABLE or in.trip. (or the associated trip system in
• trip). for Functions 12 (Reactor* Mode Switch-Shutdown
• andl3 (Manual this would require both.*** trip .syste111s to have one channel , each OPERABLE or in trip , (or >ass6ci ated tri !)<system.in trip) .. : *
• The* et ion Ti me is intended to *all ow the operator. time to evaluate and repair any discovered inope.rabilities.
• The* *I .. Conipletfon Time. i.s. accept.able because it minimizes * *rlsk'while. *an owing iime .for.restoration or tri.ppfog of channels. *. * * * * * * * * .. -. **<'"--*. *_.. . ...... *-, -.. *_ : *:.:,_ .. -:'.*-.' o. rd i entrY into the' appropriate. ' CondftiC>rl reference.d*.ih Table *rile applkable co11diti on: specified. in the Table is Futict itm and MODE or *.*. other speCifi ed 'condition dependent .and :change as the R.eqt.iired Action of a preyious Condition *is Ea.ch .. * .. time> an inoperable chan.nel has *n9t 1net any Hequi.red Action . *of Condition ox c*and the associated Completi_on T.ime: * ** . has .expi.r,ed,. Condi.tion D .will be entered.for that channel .. **.**** .. *.*and provides' for transfer to, the appropri_a'te subsequent . Condit i ori . . * * * ** *.. * . . :; ", .. -'. **. ,. . .. ** .* * ...... * , s*i.3"--2-6.* :, : ,._ .. * '. -; *: ,:_ .. ' . ,.*.-. .. :* .** -. *. *36 BASES ACTIONS (continued) PBAPS UNIT 2 E.1. F.l and G.l RPS Instrumentation B 3.3.1.1 If the channel ( s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCD does not apply. The allowed Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition, the Completion Time of Action E.l is consistent with the Completion Time provided in LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)." If the channel Cs) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This. is done by immediately initiating action to fully insert all insertable control rods in core cells c6ntaining one or more fuel Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in .core tells containing one or fuel assemblies are fully inserted. L...l If OPRM Upscale trip capability is not maintained, Condition I exists and Backup Stability Protection CBSr) is required. The Manual BSP Regions are described in 22. Ths Manual -BSP Regions are pr6cedurally established consistent with the identified in Reference 22 and require specified manual operator actions if certain predefined operational conditions occur. The Completion Time of immediately is based on the importance of limiting the period of time during which no or alternate detect and suppress trip capability is in place. 1.2 and 1.3 Actions 1.2 and 1.3 are both required to be taken in conjunction with Action 1.1 if OPRM Upscale trip capability is not maintained. As described in Section 7.4 of Reference 22, the Automated asp Scram Region is designed to avoid reactor instability by automatically entry into continued .B 3.3-27 Revision N6. 123*

BASES ACTIONS PBAPS UN IT 2 I.2 and I.3 (continued) RPS Instrumentation B 3.3.1.1 the region of the power and flow-operating map that is susceptible to reactor instability. The reactor trip would be initiated by the modified APRM Simulated Thermal Power-High scram setpoints for flow reduction events that would have terminated in the Manual BSP Region I. The *Automated BSP Scram Region ensures an early scram and SLMCPR protection. The Completion Time of 12 hours to complete the specified actions is reasonable, based on operational experience, and based on the importance of restoring an automatic reactor trip for thermal-hydraulic instability events. BSP is intended as a temporary means to protect against hydraulic instability events. The action should be initiated immediately to document the situation and prepare the report. The reporting requirements of Specification 5.6.8 document the corrective actions and schedule to restore the required channels to an OPERABLE status. The Completion Time of 90 days shown in *Specification 5.6.8 is adequate to allow time to evaluate the cause of the inoperability and to determine the appropriate corrective actions and schedule to restore the required channels to OPERABLE status. If the Required Action I is not within the associated. Completion Time, then J is required. The Bases for the. BSP Regions and assbciated Completion Time is addressed in the Bases for I.1.

• The Manual BSP Regions are required in conjunction with the BSP Boundary. J. 2 . The BSP _as in 1.3 of Reference 22, defines an domain where potential instability events can be effectively by the specified BSP manual operator actions.* The BSP Boundary is such that a flow reduction event .initiated from.this boundary and terminated the core natural circulation line CNCL) would not exceed the Mariual BSP Region I stability criterion. Potential instabilities would develop slowly as a result of the feedwater temperature transient (Ref. 22). The Completion Time of 12 hours to complete the specified actions is reasonable, based_ on operational experience, to reach the condition from full power conditions in an orderly manner and without chal lehgi ng pl ant systems .. continued B 3.3-27a Revision No.123*j BASES ACTIONS * (continued) .PBAP S UNIT 2 RPS Instrumentation B 3.3.1.1 BSP is a temporary means for protection against hydraulic instability events. An extended period of inoperability without automatic trip capability is not justified. Consequently, the required channels are required to be restored to OPERABLE status 120 days. Based on engineering judgment, the likelihood of an instability event that could not be adequately handled by the use of the BSP Regions (See Action J.1) and the BSP Boundary (See Action J.2) during a 120-day period is negligibly small. The 120-day period is intended to allow for resolution of a variety of equipment problems (e.g., design changes, extensive analysis, or other unforeseen circumstances). This acti6n is not intended to be used for operation al convenience. Correction of most equipment failures or inoperabilities is expected to normally be accomplished within the completion times allowed for Actions for Conditions A and I. A Note is provided to indicate that LCD 3.0.4 is not applicable. The intent of the note is to allow plant startup while operating within the 120-day Completirin Time for Required Action J.3. The primary purpose of ttiis exclusion is to allow an orderly completion of design and verification activities, in the event of a required design change, without undue impact on plant operation. If required channels are not restored to OPERABLE status and the Required Actions of J are not met within the associated Completion Times, then the plaht must be placed in an operating condition in which the LCD does not apply. To achieve this status, the plant must be brought to less than 18% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reach the specified operating power level from full power conditions in an orderly manner and without challenging plant systems. (continued) B 3.3-27b Revision No. 124 RPS Instrumentation B 3.3.1.1 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 As noted at the beginning of the SRs, the SRs for each RPS instrumentation Function are located in the SRs column of Table 3.3.1.1-1. The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 9, 12 & 13) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RPS wi 1.1
• trip when necessary. SR 3.3.1.1.1. Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK. is norma 11 y a comparison of the parameter indicated on one channel to a similar parameter on other channels. *It is based on the assumption that instrument monitoring the parameter should read approximately the same value. Significant deviations between channels could be an indication of excessive instrument drift* in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. Agreement criteria are determined by the plant staff based on a combination.of the channel instrument uncertainties, including indication: and readability. Ifa channel is the may be an indication that the instrumerit has its limit. The Sur\(ei 11 ance Frequency is control led under the Survei Hance Frequency Control Program. The CHANNEL CHECK supplements less formal; but more frequent, checks of . cha.nnels during normal .operational use .of*the displays associated with channels required .bY the LCO. SR. *3 3*
• 1 1 2 .* . . : . : . . . . . *. . . . .. .. . ... . .. . . . . . . . To enstir'e that th-e APRMs are :accurately .i nd*icati ng *core average power; the APRMs are.calibrated to the reactor power heat The Frequency i s *cont ro 11.ed !Jn d_e r the S Lirve i Tl ari ce Frequency . Control progr.am. *
• continued
• B 3.3-28 Revision No .. 123 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.3.1.1.2 (continued) RPS Instrumentation B 3.3.1.1 A restriction to satisfying this SR when < 23% RTP is provided that requires the SR to be met only at 23% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when< 23% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR, LHGR and APLHGR). 23% RTP, the Surveillance is required to have been satisfactorily performed in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 23% if the Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after reaching or exceeding 23% RTP. Twelve hours is on operating experience and in of providing a time in which to complete the SR. SR 3.3.1.1.3 (Not Used.) SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program .. SR 3.3.1.1.5 and SR 3.3.1.1.6 A CHANNEL* FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be made with the assumptions of the current plant specific setpoint methodology. As noted, SR 3.1.1.1.5 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required WRNM Functions cannot be performed in MODE 1 without 0tilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the Frequency is not met per SR In this event, the SR must be performed w i t h i n 12 ho u r s a ft e r en t e r i n g M 0 D E 2 from. M 0 D E 1 . T we 1 v e hours i s. b a s e d on opera ti n g ex 13 er i enc e a n d i n cons i de rat i on of providing a reasonable time ih which to complete the The Surveillance Frequency is controlled under the Surveillance C6ntrol continued I .B 3.3-29 Revision No. 114 * .. **

BASES SURVEILLANCE REQUIREMENTS (continued) ** PBAPS UNIT 2. SR 3.3.1.1.7 (Not Used.) SR 3.3.1.1.8 RPS Instrumentation B 3.3.1.1 LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP) System. This establishes the relative flux for appropriate representative input to the APRM System .. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.1.1.9 and SR 3.3.1.1.14 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the. assumptions of the current plant specific setpoint methodology. For Function 5, 7, and 8 channels, verification that the trip settings are less than or equal to the specified. Allowable Value during the CHAN_NEL FUNCTIONAL TEST is not required since the channels consist of mechanical switches and are not subject to drift. An exception to this are two of the. Function 7 level are not mechanical;* These Scram Discharge Volume CSbV) RPS switches (Fluid Components Inc.} heat sen&itive electronic level detectors which actuate by sensing a*difference in detettors are permahently affixed within scram discharge volume piping conservatively below the leve_l (allowable* value as measured in gallons) at which an RPS actuation* wjll Since there is no 6rift involved with the physical 1 ocati on of these switches, verifying the trip-. are less than or to the specified value during th:e CHANNEL FUNCTIONAL TEST is not required. < Additionally, historical calibrattori data has indicated that FCI level switches have not exceeded their Allowable when tested. *In addition, 5 and 7 instruments are not* accessible* *whi*le the unit is operating at power due to high radiation _and the installl?d indication instrumentation does not provide accuraie indication of trip setting. For tbe Function 9 that trip settings are less than

• or equal to-_ the specified Allowable Value during the CHANNEL continued -B 3:3-30 Revision No. 114 BASES S U RV E I L LAN C E REQUIREMENTS -_ PBAPS UNIT 2 RPS Instrumentation B 3.3.1.1 SR 3.3.1.1.9 and SR 3.3.1.1.14 (continued) FUNCTIONAL TEST is not required since the instruments are not accessible while the unit is operating at power due to high radiation and the installed indication instrumentation does not provided accurate indication of the trip setting. Waiver of these verifications for the above functions is considered acceptable since the magnitude of drift assumed in the setpoint calculation. is based on a 24 month calibration interval. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3:1.1.10. SR* 3.3.1.1.12. SR 3.3.1.1.15. and SR -A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the current plant specific setpoint methodology. -As noted for SR 3.3.1.1.10, radiation detectors are excluded from CHANNEL CALIBRATION due to ALARA reasoris -(when the pl ant is operating, the radiation detectors are generally in a high radiation area; the steam tunnel). This exclusion is acceptable because the radiation detectors are passive devices, with minimal drift. To complete the radiation CHANNEL CALIBRATION,-SR 3.3.1.1.16 requires that the radiation detectors be calibrated in accordance with the Surveillance Frequency Control Program. SR 3.3.1.1.12 for Function 3.3.1.1-1.2.b is modified by two Notes as "identified in Table 3.3.1.1-1. *The first N6te requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel peFformante assumptions in the setpoint methodology. The purpose of the assessment is to ensute confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the perfcirmance of these channels will be evaluated under the continued B 3.3-31 Revision No. 114

.BASES SU RV EI LLANCE REQUIREMENTS *RPS Instrumentation B 3.3.1.l SR 3.3.1.1.10. SR 3.3.1.1.12. SR 3.3.1.1.15. and SR 3.3.1.1.16 (continued) plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the Leave Alone Zone around the NTSP. Where a setpoint more conservative than the NTSP. is used in the plant surveillance procedures CATSP),_the Leave Alone Zone and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. Th1s will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the Leave Alone Zone around the NTSP, then the channel shall be declared inoperable. The second Note also requires that NTSP.and the methodologies for calculating the Leave Alone Zone and the as-found tolerances be in the Bases for the applicable Technical Specifications. The Surveillance Frequency is controlled under the SLlrveillance Frequency Control *As noted for SR 3.3.1.1.12, neutron detectors are excluded fr6m CHANNEL CALIBRATION because they are passive devices, With minimaJ and of the difficulty of simulating a meaningful signal. Changes i:n neutron _sensitivity are compensated for by performing the calorimetric calibration CSR 3.3.1.1.2) and the LPRM calibrafioh against the TIPs CSR

• A secdrid note i spr'ovi ded for SR 3. 3 .1.1.12 that al lows the WRNM SR to be perfbrmed.within 12 of entering MQDE 2 frrim MODE 1. Testing of the MODE 2 WRNM Funttions canndt be performed in MODE 1* wi thput utilizing jumpers,. lifted leads or movable links. This Note allows entry into MODE 2 from MODE :f';. i*f* t.he*Frequency is' not met per SR 3.0'.2. Twelve *hours is *based on operating experience.and in consideration * * ** of p_rovfdin_g a reasonable time in which to complete_ the .SR. PBAPS. UNIT 2 A thira_note .is provided: for _SR3.3.1:1.12 that includes in the SR the: recirculation flow' (drive flow) transmitters, .which supply the.flo.w signal to the APRMs. The APRM . Simulated* Thermal -Power-High Function (Function 2.b) and the O.PRM Upscale Function (Function both require a valid* drive flow signal.* *The APRM Simulated_ Therm*al Power-High continued ,B 3. 3-32 *No. 114

\. BASES *SU RV EI LLANCE REQUIREMENTS PBAPS UN IT 2 RPS Instrumentation B 3.3.Ll SR 3.3.1.1.10. SR 3.3.1.1.12. SR 3.3.1.1.15. and SR 3.3.1.1.16 (continued) Function uses drive flow to vary the trip setpoint. The OPRM Upscale Function uses drive flow to automatically enable or bypass the OPRM Upscale trip output to RPS. A CHANNEL CALIBRATION of the APRM drive flow signal requires both calibrating the drive flow transmitters and establishing a valid drive flow I core flow relationship. The drive flow /core flow relationship is established once per refuel cycle, while operating at or near rated power .and flow conditions. This method of correlating core flow and drive flow is consistent with GE recommendations. Changes throughout the cjcle in the drive flow I core flow relationship due to the changing thermal hydraulic operating conditions of the core are accounted for in the margins included in the bases or analyses used to establish the setpoints for the APRM Simulated Thermal Power-High Function and the OPRM Upscale Function. The Surveillance is controlled under the Sur.vei 11 an-ce Frequency Control Program. SR 3.3.1.1.11 A CHAN.NEL FUNCTIONAL TEST is performed on each required* channel to ensure that the entire channel will perform the -intended function. For the APRM Functionsi this test* supplements the automatic self-test functions that operate continuously in APRM and voter channels. The scope of the APRM CHANNEL FUNCTIONAL TEST is limited to verification of system trip output hardware. Software controlled functions are tested only incidentally. Automatic internal functions check the EPROMs ih which the controll ed logic_ is _defil'.led_. Any changes in the EPROMs wi i l be-detected 'by the self-test function resulting in a trip and/or alarm conditiori.-The APRM CHANNEL FUNCTIONAL TEST covers the APRM recirculation flow_ applicable to Function 2.b and the auto-enable portion *oLFuncti on 2-. f only), the 2 voter channels, *and the.interface.connections into 'the RPS trip systems -from the voter -channels. Any set point adJustment _ shall_ be consistent with_ the assumptions of the _current plant specific setpoint methodology. The Surveillance -Frequency is controlled under* the Survei 11 ance Frequency -Contro.l Program ... (NOTE: The actual_ voting logic of the 2-.. Outc0f:4 Voter Function _is tested as part of SR 3.3.1.1.17.

• _The actual auto-enable setpoints -for* the OPRM Upscale trip
• are confirmed by SR 3 .. 3.1.1.19.) continued -13 3. 3,3 Revision No. 114.

BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.3.1.1.11 (continued) RPS Instrumentation B 3.3.1.1 A Note is provided for Function 2.a that requires this SR to be performed within 12 hours of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM Function cannot be performed in MODE l without utilizing or lifted leads. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. A second Note is provided for Function 2.b that clarifies that the CHANNEL FUNCTIONAL TEST for Function 2.b includes. testing of the recirculation flow processing electronics, excluding the flow transmitters. SR 3.3.1.1.13 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be bypassed when THERMAL POWER 26.7% RTP. This involves calibration of the bypass channels. Adequate margins for instrument setpoint methodologies are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint (THERMAL POWER is from turbine fi0st stage pressure), the main turbine bypass valves must remain closed during the calibration at THERM.AL POWER 26.7% RTP to *ensure that the calibration is valid. If chahnel"s setpoint is nonconservative (i.e., the are bypassed at 26.7% RTP, either due to open main bypass valve(s) or other reasohs), then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition Cnonbypass). If placed in the condition, this SR is met and the c h a n n e l i s co n s i de red 0 P ERA B LE . The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B Revision No.*125 BASES SU RV EI LLANCE REQUIREMENTS (continued) PBAPS UN IT 2 SR 3.3.1.1.17 RPS Instrumentation B 3.3.1.1 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods (LCD 3.1.3), and SDV vent and drain valves (LCD 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The LOGIC SYSTEM FUNCTIONAL TEST for APRM Function 2.e simulates APRM and OPRM trip conditions at the 2-0ut-Of-4 voter channel inputs to check all combinations of two tripped inputs to the 2-0ut-Of-4 logic in the voter . and APRM related redundant relays. SR 3.3.1.1.18 This SR ensures that the individual channel response times are maintained less than or equal to the original design value. The RPS RESPONSE TIME acceptance criterion is included in Reference 11. The Surveillance Frequency is controlled under the Surveillance Cortrol Program. SR 3.3.1.1.19 Deleted * (continued) B 3.3-35 Revision No. 123 RPS Instrumentation B 3.3.1.1 BASES (continued) REFERENCES PBAPS UN IT 2 1. UFSAR, Section 7.2. 2. UFSAR, Chapter 14. 3. NED0-32368, "Nuclear Measurement Analysis and Control Wide Range Neutron Monitoring System Licensing Report for Peach Bottom Atomic Power Sta ti on, Units 2 and 3," November 1994. 4. NEDC-33566P, "Safety Analysis Report for Exelon Peach ottom Atomic Power Station, .Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 5. UFSAR, Section 14.6.2. 6. UFSAR, Section 14.5;4. 7. UFSAR, Section 14.5.1. 8. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980. 9. NED0-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System," March 1988. 10. MDE-87-0485-1, "Technical Specifi ca ti on Improvement Analysis for the Reactor Protection System for Peach Bottom Atomic Power Station Units 2 and 3," October 1987. 11. UFSAR, Section 7.2.3.9. 12. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," October 1995. 13. NEDC-32410P Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function, Supplement 1", November 1997. 14. Deleted 15. Deleted (continued) B 3.3-3.5a Revision No. 123 BASES REFERENCES (continued) PBAPS. UNIT_ 2 16. Deleted 17; Deleted 18. Deleted Instrumentation B 3.3.1.1 19. NED0-24229-1, "Peach Bottom Atomic Power Station Units 2 a*nd 3 Single-Loop Operation," May 1980. 20. Setpoint Methodology for Peach Bottom Atomic Power Station and Limerick Station, CC-MA-103-2001. 21. Backup Stability (BSP) for Inoperable Option III Solutions, OG02-0119, July 17, 2002. 22. GE Hitachi Nu cl ear Energy, "GE Hitachi Boiling Water Reactor, Detect and Suppress Solution -Confirmation Density," NEDC-;33075P-A, Revision 8, November 2013. GEH letter to NRC, "NEDC-33075P-A, Detect and Suppress Solutton -Confirmatiori Density COSS-CD) Analytical Limit (TAC No .. MD0277)," October 29, 2008. *(ADAMS No. Ml083040052). 24. OOON7936-RO, "Project Task Report -Exelon Generation. *Company LLC, Peach Bottom Atomic Power Statiori Unit 2 & 3 MELLLA+, Task T0202: Thermal-Hydraulic Stability," . April 2014. *.-.. '. B ReViSion No. WRNM Instrumentation B 3.3.1.2 B 3.3 INSTRUMENTATION I B 3.3.1.2 Wide Range Neutron Monitor (WRNM) Instrumentation BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 The WRNMs are capable of providing the operator with information relative to the neutron flux level at very low flux levels in the core. As such, the WRNM indication is used by the operator to monitor the approach to criticality and determine when criticality is achieved. The WRNM subsystem of the Neutron Monitoring System (NMS) consists of eight channels. Each of the WRNM channels can be bypassed, but only one at any given time per RPS trip system, by the operation of a bypass switch. Each channel includes one detector that is permanently positioned in the core. Each detector assembly consists of a miniature fission chamber with associated cabling, signal conditioning equipment, and electronics associated with the various WRNM functions. The signal conditioning equipment converts the current pu-lses from the f;Lssion chamber to analog DC curr'ents _that correspond to the count rate. Each channel. also includes indication; alarm, and control rod blocks. However, this LCO specifies OPERABILITY requirements only for the monitoring _and indication functions of the WRNMs. During refueling, shutdown, and low power operations, the primary indication of neutron flux is provided by the WRNMs or special movable detectors conn_ected to the normal WRNM circuits. The. WRNMs provide monitoring of reactivity changes during fuel or control rodmovement and give the contrpi operator early indication of unexpected subcritical multiplication that could be indicative of an: approach *to _cri t¥. --Prevention and mitigation of prompt react:ivity excursions during* refoeling and low power operation is provided by LCO 3, 9 .-1, '"Refueling EqU:ipritent Interlocks."; LCO l; ,,-SHUTDOWN MARGIN-(SDM) 11; -LCO 3.3.1.1, "Reactor Protection System: (RPS) Instrumentation"; WRNM Period-Short and * . (continued) ... *-* B -3. 3-3_6 Revision 24 BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS :UNIT -2 WRNM Instrumentation B 3.3.1.2 Average Power Range Monitor (APRM) Startup High Flux Scram Functions; and LCO 3.3.2.1, "Control Rod Block Instrumentation." The WRNMs have no safety function associated with monitoring neutron flux at very low levels and are not assumed to function during any UFSAR design basis accident or transient analysis which would occur at very low neutron flux levels. However, the WRNMs provide the only on-scale monitoring of neutron flux levels during startup and refueling. Therefore, they are being retained in Technical Specifications. During startup in MODE 2, three of the eight WRNM channels are required to be OPERABLE to monitor the reactor flux level and reactor period prior to and during control rod withdrawal, subcritical multiplication and reactor criticality. These three required channels must be located in different core quadrants in order to provide a representation of the overall core response during those periods when reactivity changes are occurring throughout the core. In MODES 3 and 4, with the reactor shut down, two WRNM channels provide redundant monitoring of flux levels in the core. -In MODE 5, during a spiral offload or reload, a WRNM outside the fueled region w_ill no longer be required to be OPERABLE, since it is not capable of monitoring neutron flux in the -fueled region of the core. Thus, CORE ALTERATIONS are allOwed in a quadrant with no OPERABLE WRNM in an adjacent quadrant provided the 3.3.1.2-1, footnote (b), requirement that the bundles being spiral reloaded or spiral offloaded are all in a single fueled region containing a:t least one OPERABLE WRNM is met.

• Spiral reloading and offloading encompass reloading or offloading a cell on the .edge of a continuous fueled region (the cell can be reloaded or offloaded in any sequence). In nonspiral routine operations, two WRNMs are required to be OPERABLE to provide redundant monitoring of reactivity changes in the reactor core. Because of the local nature of reactivity changes during refueling, adequate coverage is provided by requiring one WRNM to be OPERABLE for the connected fuel in the quadrant of the reactor core where (continued) I I B_ 3.3-37 -Revision No. 24 BASES LCO (continued) I APPLICABILITY ACTIONS I I PBAPS UNIT 2 WRNM Instrumentation B 3.3.1.2 CORE .ALTERATIONS are being performed. There are two WRNMs . in each quadrant. Any CORE ALTERATIONS must be performed in a region of fuel that is connected to an OPERABLE WRNM to ensure that the reactivity changes are monitored within the fueled region(s) of the quadrant. The other WRNM that is required to be OPERABLE must be in an adjacent quadrant containing fuel. These requirements ensure that the reactivity of the core will be continuously monitored during CORE ALTERATIONS. Special movable detectors, according to footnote (c) of Table 3.3.1.2-1, may be used in place of the normal WRNM nuclear detectors. These special detectors must be connected to the normal WRNM circuits ;n-the NMS, such that the applicable neutron flux indication can be generated. These special detectors provide more flexibility in . monitoring reactivity changes during fuel loading, since they can be positioned anywhere within the core during refueling. They must still meet the location requirements of SR 3.3.1.2.2 and all other required SRs for WRNMs. The Table 3.3.1.2-1, footnote (d), requirement provides for conservative spatial core coverage. For a WRNM channel to be considered OPERABLE, it must be providing neutron flux monitoring indication. The WRNMs are required to be OPERABLE in MODES 2, 3, 4,
• and 5 prior to the WRNMs reading % power to provide for neutron monitoring. In MODE I, the APRMs provide
• adequate monitoring of reactivity changes in the core; therefore, the WRNMs are not required. In*MODE 2, with WRNMs reading greater than 125E-5 % the WRNM Short function provides adequate monitoring and the WRNMs monitoring indicati9n is not required. A.I and B.I In MODE 2, the WRNM channels provide the means of monitoring core reactivity and criticality. With any number of the required WRNMs.inoperable, the ability to monitor neutron flux is degraded. Therefore, a limited time is allowed to .** res.tore the inoperable channels to OPERABLE status.
• Provided at least one WRNM remains OPERABLE, Required
• Action A.I allows 4 hours to restore the required WRNMs to OPERABLE status.* This time is reasonable because there is adequate capability to monitor the core, there is limited risk of an event dur1ng this time, is to take corrective actions to restore the *
• required WRNMs to OPERABLE. status.
• During this ti me,* control rod withdrawal and power increase is not precluded (continued) B 3.3-38 Revision No. 24 BASES ACTIONS PBAPS UNIT 2 A.I and B.I (continued) WRNM Instrumentation B 3.3.1.2 by this Required Action. Having the ability to monitor the core with at least one WRNM, proceeding to WRNM indication greater than I25E-5 % power, and thereby exiting the Applicability of this LCO, is acceptable for ensuring adequate core monitoring and allowing continued operation. With three required WRNMs inoperable, Required Action B.I allows no positive changes in reactivity (control rod withdrawal must be immediately suspended) due to inability to monitor the changes. Required Action-A.I still applies and allows 4 hours to restore monitoring capability prior to *requiring control rod insertion. This allowance is based on the limited risk of an event during this time, provided that no control rod withdrawals are allowed, and the desire to concentrate efforts on repair, rather than to immediately shut down, with no WRNMs OPERABLE. In MODE 2, if the required number of WRNMs is not restored to OPERABLE status within the allowed Completion Time, the *reactor shall be placed in MODE 3. With all control rods fully inserted, the core is in its least reactive state with the most margin to criticality. The allowed Completion Time of I2 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. D.I and D.2 With one or more required WRNMs inoperable in MODE 3 or 4, the neutron flux monitoring capability is degraded or nonexistent. The requirement to fully insert all insertable control rods ensures that the reactor will be at its minimum reactivity level while no neutron monitoring capability is available.
• Placing the reactor mode switch in the shutdown position prevents subsequent control rod withdrawal by maintaining a control rod block. The allowed Completion Time of I hour is sufficient to accomplish the Required Action, and takes into account the low probability of an event requiring the WRNM occurring during this interval. (continued) B 3.3-39 Revision No. 24 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS . PBAPS UNIT 2 E. l and E.2 WRNM Instrumentation B 3.3.1.2 With one or more required WRNMs inoperable in MODE 5, the ability to detect local reactivity changes in the core during refueling is degraded. CORE ALTERATIONS must be immediately suspended and action must be immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Suspending CORE ALTERATIONS prevents the two most probable causes of reactivity changes, fuel loading and control rod withdrawal, from occurring. Inserting all insertable control rods ensures that the reactor will be at its minimum reactivity given that fuel is present in the core. Suspension of CORE ALTERATIONS shall not preclude completion of the*movement of a component to a safe, conservative position. Action (once required to be initiated) to insert control rods must continue until all insertable rods in core cells containing one or more fuel assemblies are inserted. As noted at th.e beginning of the SRs, the SRs for each WRNM Applicable MODE or other specified conditions are found in the SRs column of Table 3.3.1.2-1. SR and SR Petformance of the CHANNEL CHECK ensures that a gross . failure. of instrumentation has not occurred_. . A CHANNEL CHECK is normally a comparison of the parameter indicated on one to* a s.imi l ar parameter on another channel. It is based on the assumptfon that instrument channels
• monitoring .the* same parameter should read approximately the same value. Significant deviations between the instrument channels could 'be an indication of excessive :instrument drift in one of the channelS or something even more sedous. A CHANNEL CHECK w.ilr:detect gross ch*annel failure; thus., Jt is key to verifying*the instrumentation continues to operate properly between each CHANNEL CALIBRATION. Agreementcriteria by.the plant staff *based* on a combfriation of the channel instrument uncertainties, including. indication and readability .. If. a channel is . outside the criteria' it may be an indication that the . has.drifted outside iii limit. * .. -(continued) B J.3-:40 Revision No. 24 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 WRNM Instrumentation B 3.3.1.2 SR 3.3.1.2.l and SR 3.3.1.2.3 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less forma.l, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCD. SR 3.3.1.2.2 To provide adequate coverage of potential reactivity changes in ttie core, one WRNM is required to be OPERABLE for the connected fuel in the quadrant where CORE ALTERATIONS are being performed, and the other OPERABLE WRNM must be in an quadrant containing fuel. Note 1 states that the SR is to be met only during CORE ALTERATIONS. It is not required to be met at other times in MODE 5 since.core reactivity changes are not occurring. This Surveillance consists of a review of plant logs to ensure that WRNMs to be OPERABLE for given CORE ALTERATIONS are, in fact, dPERABLE. In the that only one WRNM is required to be. OPERABLE, per Table 3.3.1.2-1, footnote Cb), only the a . po.rt i on o f t h i s S R i s re q u fr e d . N o t e 2 c l. a r i f i e s t h a t more than one of the three requirements can be met by the same OPERABLE WRNM.. The Survei 11 ance Frequency is controlled under the Surveillance Freql/ency Control Program. SR 3.3.1.2.4 Th i. s S u r v e il l a n c e con s i s t s o f a v e r if i ca t i on o f t he W RN M i nstruriient readout to ensure that the WRNM reading is .greater than a specified which the detect.ors.are indicating cOunt rates.indicative of neutron flui levels within The signal-to-noise ratio shown in .Figure 3.3.1.2-1 is the WRNM count rate which there is a 95% *pr::9bability th.at the WRNM signal indi.cates the presence_ of neutrons and only a 5%* probability that the WRNM. signal is the resuJt of noise (Ref: 1). With few fuel. assemblies. loaded, the WRNMs not have a high enough count rate to sat-isfy the SR.* *Therefore, allowances are made for loading . sufficient "sour.ce material .* in the form of irradiated fuel. assembl *i es,. t6 e.stabli sh -the mi hi.mum count .rate. continued B_ 3. 3-41 Revi si"on No. 86 BASES SU RV EI LLANCE REQUIREMENTS PBAPs* UN IT 2 SR 3.3.1.2.4 (continued) WRNM Instrumentation B 3.3.1.2 To accomplish this, the SR is modified by Note 1 ttiat states that the count rate is not required to be met on a WRNM that has less than or equal to four fuel assemblies adjacent to the WRNM and no other fuel assemblies are in. the associated core quadrant. With four or 1 ess fuel assemblies 1 oaded around each WRNM and no other fuel assemblies in the core quadrant, control rod withdrawn, the configuration will not be critical. In addition, Note 2 states that this requirement does not have to be met during Spiral unloading. If the core is being unloaded in this manner, the various core configurations encountered.will not be critical. The Surveillance Frequency is controlled under the Frequency Control Program. SR 3.3.1.2.5 of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel function properly. SR 3.3.1.2.5 is required in MODES 2, 3, 4 arid .5 and ensures that the are OPERABLE while core reactivity changes could be in progress .. The Surveillance Frequency is controlled under the Frequency Control Program. continued B Revision No. 86' BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2
• SR 3.3.1.2.5 (continued) WRNM Instrumentation B 3.3.1.2 Verification of the signal to noise ratio also ensures that the are correctly monitoring the neutron flux. The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability (THERMAL POWER decreased to WRNM reading of 125E-5 % power or below). The SR must be performed within 12 hours after WRNMs are reading 125E-5 % power or below. The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability .. Although the. Surveillance could be performed while at higher power, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the WRNMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) arid the time required to perform the Surveillances. SR 3.3.1.2.6 Performance of a CHANNEL CALJBRATION verifies the performance. 1*
• of the WRNM detectors and associated circuitry. The considers the plant conditions required to perform the test, the ease of performing the test, and the likelihood of a change in the system or component status. **Note 1 excludes the neutron detectors from the CHANNEL CALIBRATION because thej cannot be adjusted. The detectors fission that are to have a relatively constant sensitivity over the range and with specified for .a fixed u_seful life.
• continued B 3.3-43 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT. 2 WRNM Instrumentation B 3.3.1.2 SR 3.3.1.2.6 (continued) Note 2 to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours of entering MODE 2 with WRNMs reading 125E-5 % power or below. The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability. Although the Surveillance could be performed while at higher power, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency.is reasonable, based on the WRNMs being otherwise verified to be OPERABLE Ci .e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillance. 1. NRC Safety Evaluation Report for Amendment Numbers 147 and 149 to Facility Operating License Numbers DPR-44 and DPR-56, Peach Bottom Atomic Power Station, Unit Nos. 2 3, August 28, 1989. B 3.3-44 Revision No. 86

. .' .. : I:* . *.;. Control Rod Block Instrumentation B B 3.3 INSTRUMENTATION B Control Rod Block BASES BACKGROUND ....... . ' . *.:.' . ' ' <'* . . ..,,, .' ., . *" *.** ... *', ... '* -, ***.'. . .;' ._,*. ,_,.*_:*. ,*' .: ... **--... ::: . -PBAPS -UN'rJ< 2 Control rods pr:ovide-the primary means_ for control of reactivity changes. Control rod block instrumentation includes channel sensors, logic circuitry, switches, and relays that are designed to that specified fuel design limits are not exceeded for postulated transients and accidents. During high power-operation, the rod block monitor (RBM) provides protection for controlrod withdrawal -error events. During_ low.power operations, control rod blocks from the rod worth minimizer (RWM) enforce specific control rod sequences designed to mitigate the consequences of the control rod drop accident (CRDA). During shutdown conditions, control *rod blocks from the Reactor Mode _ Switth.;,_Shutdown Position Function ensure that all control rods rem(liri inseried to prevent inadvertent criticalities. The of the is to limit control rod withdrawal if _ _ localized -neutron flux exceeds a predetermined setpoi nt .during control rod manipulations. It is assumed to function to block_ ft.irther control rod withdrawal to preclude a MCPR Safety {SL) -The RBM supplies a trip signal ------to th __ e Reactor Manual Control System tRMCS) to appropriately -_ inhibit control rod withdrawalduring -power operation abpve:

• _.--the lOw power setpoinL __ The RBM has-two channels,_ -control when the. -chann'eL output exceeds-the *control rod block set point. __ One RBM th(lnnel inputs_into:one RMCS rod block circuit and-the _ other RBM channel. inputs _into the*.sec:oild _RMCS-rod_ block --__ -. circuit) Jhe .RBM-Chifnnel stgnal.Js generated by averaging a .. -set of :1ocal power*range mo'nitor: (lPRM) .signals at: varfous __ . --_-core heights .. surrounding .the-. control rod being withdrawn:; , A _ ---s ign_a l _from one of the four )'edund ant: average power range ' ' --_--_ -monitor *(Al>RMt_,chann'els --s*upplies a reference signal for _one ---* * * -'Qf the *RBrt a signal '.from *ariother o:F the APRM --channe.ls __ th1f refer(!nc.e signal to the. s,econd RBM "' channel. "-Thi*s* reference used to* which---RBM range setpoint {low, or high) is enabled.*_ If the APRM' Js *indicating than the-power* range -_
• theRBM is (lutqmatically bypassed.,-The RBM*is . _ if a peripheral *control rod is -'(Ref. l) . --A block s igna 1 .-is -al so if _ :an RBMjnoperable frip occu'rs, sirice this_. could indicate a* problern with 'the RBM chann_el_ :,---' -*, . .,. , --.. :,**: *'* *., ..... . :* .** ,-,:-.. * .. ' (continued) _Revision-_ No ..

J* ' . . . . -BASES -BACKGROUND (continued) .. -.,. : 't* .. _ _ Control Rod Block Instrumentation B 3.3.2.1 The inoperable trip will occur if, during the nulling (normalization} sequE!nce, the RBM channel fails to null or too few LPRM inputs are available,. if a critical self...:test fault has detected, or. the RBM instrument mode switch is moved to any other than "Operate". -The *pufpose of the RWM is to control rod patterns during startup and shutdown, such that rinly specified control rod and relative positions are allowed over the operating range from all control rods inserted to 10% RTP. *The sequences effective 1 y J i mi t the potent i a 1 amount and rate of reactivity increase during a CRDA. Prescribed control rod sequences _are stored in the RWM, which will initiate rod withdrawal and insert blocks wheri the actual-sequence deviates beyond allowances-from the stored sequence .. The RWM determines the actual sequence based posit.ion* indication for control rod. The RWM alSo uses feedwater fl ow and steam fl ow signals to determine when the -reactor -power is .above the preset power level at which -the RWM is automatically 2).--The RWM is a single channel system thatprovides input into both RMCS rod block _circuits. ---* With .:the reactor_ mode swjtch in the shutdown position, -a -_ control rOd withdrawal bl_ock iS applied to all control.rods to en.s.urE! that the shutdown condition is maintained. This -. Function *prevents ftladvertent cri ti cal ity a.s the result of a control rod _withdrawal .during MODE -3 or 4, or during MODE 5 -reactor* mode swi fch is required-to be in the -The reactor mode switch: has two channels, each inputting fotri a separate RMCS rod block circuit. A rod block in either RMCS will provide a -.control rod block to alL control rods.: .. 'l.-;.::'* . ..

• __ -,_* 1 ... Rod :Block Md'n i'tor > < ------SAFETY. ANALYSES, -------LCO :.and-:
• _
• l:he*RBM.fs cies*igned-to violatiori:of"the MCPR __ -_---APPLICABILITY * *-SL __ and'.:the cladding 1% :plastic_ strain fliel d_esign l imtt.that _, --m*ay control_ rod withdrawal error (RWE}
• event. .The analytical methods and used i.n _-. ___ _ "f** . ' ":* .. eval uat1n9* the event_ are -suminariied.* i l/ A' --.** ' Ccontinliedl * .. **-... -*-***** : ... . *,. .*** *, .-* *-.* * ., .. ' .. :* .. __ . Revi sitm No. 36 . * .. /. --: ... ,*:**. . . . ', :

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAi?S UNIT 2 Control Rod Block Instrumentation :B 3.3.2.1 1. Rod Block Monitor (continued) statistical analysis of RWE events was performed to determine the RBM response for both channels for each event. From these responses, the fuel thermal performance as a function of RBM Allowable Value was determined. The Allowable Values are chosen as a function of power level. The Allowable Values are specified in the CORE OPERATING LIMITS REPORT (COLR). Based on the specified Allowable Values, operating limits are established. The RBM Function satisfies Criterion 3 of the NRC Policy Statement. Two channels of the RBM are required to be OPERABLE, with their setpoints within the appropriate Allowable Values to ensure that no single instrument failure can preclude a rod block from this Function. The actual setpoints are calibrated consistent with applicable setpoint methodo*logy. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the_ setpoints do not exceed the Allowable Values between successive CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the trip setpoint, but within its Allowable Value; is acceptable. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor power), and when the meas_ured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic design limits are derived from the limiting values of the process parameters obtained from the safety analysis or other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for calibration, process, and instrument errors. The trip setpoints a-re determined from analytical or design limits, corrected for calibration, process, and instrument errors, as well as, instrument drift. In selected cases, the Allowable Values and trip setpoints are determined by engineering judgement or historically accepted practice to the intended function of the channel. The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environments during the operating time of* the channels are accounted for. (continued) B 3.3-47 -Revision No. o

• BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UN IT 2 Control Rod Block Instrumentation B 3.3.2.1 1. Rod Block Monitor (continued) The RBM is assumed to mitigate the consequences of an RWE event when 30% RTP. Below this power level, the consequences of an RWE event will not exceed the MCPR SL and, therefore, the RBM is not required to be OPERABLE (Ref. 1). When operating< 90% RTP, analyses CRef. 1) have shown that with an initial MCPR 1.70, no RWE event will result in exceeding the MCPR SL. the analyses demonstrate that when operating at 90% RTP with MCPR 1.40, no RWE event will result in exceeding the MCPR SL (Ref. 1). Therefore, under these con di ti ons, the RBM is also not required to be OPERABLE. 2. Rod Worth Minimizer The RWM enforces the analyzed rod position sequence to ensure that the initial conditions of the CRDA analysis are not violated. The analytical methods and assumptions used in evaluating the CRDA are summarized in References 3, 4, 5, and 11. The analyzed rod position sequence requires that control rods be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions. Requirements that the control rod sequence is in compliance with the analyzed rod position sequence a re specified in LCO 3 .1. 6, "Rod Pattern Control." When performing a. shutdown of the plant, an optional control rod (Ref. 11) may be used if the coupling of each withdrawn control rod has been confirmed. The rods may be inserted without the need to stop at intermediate positions. When using the Reference 11 control rod insertion sequence for shutdown, the RWM may be reprogrammed to enforce the requirements of the improved control rod insertion process, or may be bypassed and the improved control rod shutdown sequence implemented under the controls in Condition D. The RWM Function satisfies Criterion 3 of the NRC Policy Statement. Since the RWM is a hardwired system designed to act as a backup to operator control of the rod sequences, only one channel of the RWM is available and.required to be OPERABLE (Ref. 6). Special circumstances provided for in the Required Action of LCO 3.1.3, "Control Rod OPERABILITY," .and LCO 3.1.6 may necessitate bypassing the RWM to allow continued operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the analyzed rod position sequence. The RWM may be bypassed as required by these conditions, but then it must be considered inoperable and the Required Actions of this LCO followed. continued B 3.3-48 Revision No. 63 BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY ', .. -.,-Control Rod Block Instrumentation B 3.3.2.1 2. Rod Worth Minimizer (continued) Compliance with the analyzed rod position sequence, and therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is< 10% RTP. When THERMAL POWER is > 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Refs. 4 and 6). In MODES 3 and 4, all control rods are required to be inserted into the core; therefore, a CRDA cannot occur. In MODE 5, since only a single control rod can be withdrawn from a cell containing fuel assemblies, adequate SOM ensures that the consequences of a CRDA are acceptable, since the reactor will be subcritical. 3. Reactor Mode Switch-Shutdown Position During MODES 3 and 4, and during MODE 5 when the reactor mode .switch is required to be in the shutdown position, the core is assumed to be subcritical; therefore, rio positive reactivity insertion events. are analyzed. The Reactor Mode Positio*n control rod withdrawal block . ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions* of the sbfety
• Th e Re a tt o r -Mod e S wit c h -S h u t d own P o s i t i on Fu n ct i o n satisfies 3 of the NRC Statement. Two channels a re required to be *opERABLE *to ensure that no sirigl e .channel failure* wi 11 precJude a rod block when _ requirea. The.re is no Allowable Value for.this Function* the actµated based so1ely on reacior mode switch po.s i ti on. * * -. . ... . During shutdown.condftions (.MODE 3, 4, or 5) ,*no. positive _reactiv{ty insertion events ar'e that _control. rod *'withdrawal blocks are provided to prevent criti ca 11 ty.
• Therefore, when the reactor mode switch is.in-the.shutdown position, the control rod wit_hdrawal bloCk is required to be OPERABLE. During MODE 5 w{ih mode switch in the position, the refuei position One..:roci-out interlock (LC03.9.2, "Refuel
• Position One-Rod-Out Inter.lock") provides the required *control** r9d *withdrawal bl-oc.ks .. * * * * * (continued) . B 3.3-49 Revision No. 63 * .<.

Control Rod Block Instrumentation B 3.3.2.l BASES (continued) . ACTIONS 1 PBAPS -UNIT 2 With one RBM channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod block function; however, overall reliability is reduced because a single failure in the remaining OPERABLE channel can result in no control rod block capability for the RBM. For this reason, Required Action A.I requires restoration of the inoperable channel to OPERABLE status. The Completion Time of 24 hours is based on the low probability of an event occurring coincident with a failure in the remaining OPERABLE channel. If Required Action A.I is not met and the associated Completion Time has expired, the inoperable channel must be placed in trip within I hour. If both RBM channels are inoperable, the RBM is not capable of performing its intended function; thus, one channel must also be placed in trip. This initiates a qmtrol rod withdrawal block, thereby ensuring that the RBM function is met. The I hour Completion. Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities and is acceptable because it*minimizes risk while allowing . time for restoration or tripping of inoperable channels. C.l. C.2.1.1. C.2.1.2. and C.2.2 With .the RWM inoperable during a reactor startup, the operator is still capable of enforcing the prescribed control rod sequ_ence. : However; the overall reliability* is reduced because a single operator error can result in .violating the control *rod. sequence. Therefore,* control rod 'movement must be immediately suspended except by scram. Alternatively, startup continue if at least 12 control rods have already.been. withdrawn, or a reactor startup with an inoperable RWM was not performed in. the last 12_ months. These requirements minimize the number .of reactor startups initiated with theRWM inoperable. Required Actions C.2.1.l *and C.2.1.2 require verification of these conditions by . revfew of plant Jogs and C:o*ntrol room indications. ' Qnce Re_quired Action C.2.1.1 or C.2 .. 1.2 is satisfactorily '(continued) -B-3.3-50 Revision No. 0 BASES ACTIONS -PBAPS UN Ii 2 Control Rod Bl-0ck Instrumentation B 3.3.2.l C.l. C.2.1.1. C.2.1.2. and C.2.2 (continued) completed, control rod withdrawal may proceed in accordance with the restrictions imposed by Required Action C.2.2. Required Action C.2.2 allows for the RWM Function to be performed manually and requires *a double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other qualified member of the technical staff. The RWM may be bypassed under these conditions to allow continued operations. In addition, Required Actions of LCD 3.1.3 and LCD 3.1.6 may require bypassing the RWM, during which time the RWM'must be considered inoperable with Condition C entered and its Required Actions taken. D. l With the RWM inoperable during a reactor shutdown, the operator is still capable of enforcing the prescribed control rod sequence. Requi-red Action D.l allows for the RWM Function to be performed manually and requires a double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor *Operator) or other qualified member of the technical staff. The RWM may be bypassed under these conditions to allow the re-actor shutdown to E. l and E.2 With one Reactor Mode Switch-Shutdown Position control rod withdrawal -block channel fnoperable, the remaining OPERABLE channel is adequate to perform the control rod withdrawal block function. However, since the Required Actions are consistent with the normal action of an OPERABLE Reactor Mode Switch-Shutdown Position Function (i.e., maintaining all control rods inserted), there is no distinction between having or two channels inoperable. In both cases (one or both channels inoperable), suspending. all control rod withdrawal,and initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies will ensure that the core is subcritit:al with adequate SOM ensured by LCO 3.1.1. Control rods in core cells no fuel assemblies do not (continued) B 3.3*51 Revjsion No.* 0 *.".**. BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS *UN IT *2 E.1 and E.2 (continued) Control Rod Block Instrumentation B 3.3.2.1 affect the reactivity of the core and are therefore not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. As noted at the beginning of the SRs, the SRs for each Control Rod Block instrumentation Function are found in the SRs column of Table The Surveillances are modified by a Note to indicate that when an RBM channel is placed in an inoperable status solelij for performance of required Surveillances, entry associated Conditions and Required Actions may be delayed for up to 6 hours provided the.associated Function maintains control rod block capability. *Upon completion Of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 8, 9, & assumptions of the average time required to perfotm channel surveillances; That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the. probability a rod block will be .initiated

• necessary. SR 3.3.2.1.1 A CHANN'EL FUNCTIONAL TEST is performed for each RBM channel to erisure that the entire channel will perform the intended* Any setpoint shall consistent with the.* assumpt1ons of the current plant specifi'c setpoint methodology. The Frequency is controlled under * ... I the. Frequehcy C6ntrol Program. continued B3.3-52 No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) . .. PBAPS UN IT 2 Control Rod Block Instrumentation B 3.3.2.1 SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform the intended function. The CHANNEL FUNCTIONAL TEST for the RWM is performed by withdrawing a control rod not* in compliance with the prescribed sequence and verifying a coDtrol rod block occurs. It is permissible to simulate the withdrawn control rod condition into the RWM in order to verify a control rod block occurs. SR 3.3.2.1.2 is performed during a startup and SR 3.3.2.1.3 is performed during a shutdown (or power reduction to s 10% RTP). As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until 1 hour after any rod is withdrawn at s 10% RTP in MODE 2. As noted, SR 3.3.2.1.3 is not required to be performed until 1 hour after THERMAL POWER is s 10% RTP in MODE 1. This allows entry at s 10% RTP in MODE 2 for SR 3.3.2.1.2 and entry into MODE 1 when THERMAL POWER is s 10% RTP for SR 3.3.2.1.3 to perform the required Surveillance if the Frequency is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
• SR 3.3.2.1.4 The RBM setpoints are varied as a function of power. Three Allowable are specified in the COLR, each within a speci1ic power range. The power at which the control rod block Allowable Values automatically change are based on the APRM signal's input to each RBM channel. Bel ow the minimum power setpoint, the RBM is automatically bypassed. These power Allowable Values must be verified using a simulated or actual signal periodically to be less than or equal to the specified values. If any power range setpoint is nonconservative, then the affected RBM channel is considered inoperable. Alternatively, the power range continued B 3.3-53 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS '*:_. -PBAPS UN IT 2 SR 3.3.2.1.4 (continued) Control Rod Block Instrumentation B 3.3.2.1 channel can be placed in the conservative condition (i.e., enabling the proper 'RBM setpoint). If placed in this condition, the SR is met and the RBM channel is not considered inoperable. As noted, neutron detectors are excluded from the Surveil.lance because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal: Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.2.l.5 A CHANNEL CALIBRATION is a complete check of the instrument loop the This verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account f.or instrument drifts between.successive calibrations with the plant specific setpoint methodology. As neutron are excluded fr6m CHANNEL because they passive devices, with minimal drift, atid of.the difficulty of simulating a .me*aningful' signal. Neutron detect6rs are adequately tested *in SR and SR 3:3.L.l.8. The Surveillance control.led the C6ntrol * . ___ ' continued . B 3.3-54
• Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS U IT 2
• SR 3.3.2.1.6 Control Rod Block Instrumentation B 3.3.2.1 The RWM is automatically bypassed when power is above a specified value. This automatic action can itself be , bypassed to allow for control rod sequence enforcement up to 100% RTP. The power level is determined from feedwater flow and steam flow signals. The automatic bypass setpoint must be verified periodically to be> 10% RTP. If the RWM low power setpoint is nonconservative, then the RWM is considered inoperable. Alternately, the low power setpoint channel can be placed in. the conservative condition (nonbypass). If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. *SR*3.3.2.l.7 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Position Function to ensure that the entire thannel will perform the intended function. The CHANNEL FUNCTIONAL. TEST for the Reattor Mode Switch-Shutdown* Position Function is performed by attempting to withdraw any rod with the reactor mode swttch in the shutdown position a.nd veri fii ng. a cont.rol rod bl oc.k occurs. As noted in the SR, the is not required to be performed until 1 hour after*the reactor mo.de switch is in shutdown position, since testing of this interlock with the reactor mode s0itch in any other position cannot be performed wi t,hout usi.ng jumpers' lifted leads.' or movable links* .. This allows entry into MODES 3 and 4 if the Frequency is not SR 3.D.2,: The i hour allowance is based operating ex'.per1 ence arid in* consi derati*on of provi dfng a reasonable.time in whfrh to complete the SR.
• continued B 3.3-55. Rev i s i on N o .
• 8 6 **-..

BASES SURVEILLANCE REQUIREMENTS REF.ERENCES PBAPS UN IT 2 Control Rod Block Instrumentation B 3.3.2.1 SR 3.3.2.1.7 (continued) the Surveillance Frequency is controlled the Surveillance Frequency Control Program. SR 3.3;2.l.8 The RWM will only enforce the proper c*ontrol rod sequence if the rod sequence is properly input into the RWM computer. This SR ensures that the proper sequence is loaded into the RWM so that it can perform its intended function. The Surveillance is performed once prior to declaring RWM OPERABLE following loading of sequence int-0 RWM, since this is when rod sequence input errois are possible. 1. NEDC-32162-P, "Maximum Extended Load Line Limit and ARTS Improvement Program for Peach Bottom Atomic Power Station, Units 2 and 3," Revision 1, February 1993. 2. UFSAR, 7.10.3.4.8 and 7.16.3. 3. NEDE-24011-P-A, ."General Electric Standard Application for Reactor Fuel," latest approved revision. 4. ."Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BWR Owners' Group, July 1986. 5. NED0-21231, "Banked Position Withdraw.al Sequence," January 1977.

• 6 . N RC S ER , " Accept a n c e o f Re f e re n c i n g o f Li ce n s i n g Topical Report NEDE-24011-P-A," "General Electric St a n d a rd App l i. ca t i on fo r Re a* ct o r Fu el , Re v i s i o n 8 , Amendment 17," December 27, 1987. continued B 3. 3-56 Re vi si ori* No. 86 I BASES REFERENCES (continued) PBAPS UNIT, 2 7. Control Rod Block Instrumentation B 3.3,2.1 NEDC-30851-P-A, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation," October 1988. 8. GENE-770-06-1, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991. 9. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Mani tor (*NUMAC PRNM) Retrofit Plus Option III Stability Trip Function", March 1995. 10. NEDC-32410P Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function, Supple:ment 1", November 1997. 11. NED0-33091-A, * "Improved BPWS Control Rod Insertion Process," Revision 2, July 2004 B 3.3-57 . Revision .No .. 6l Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 B 3.3 INSTRUMENTATION B 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation BASES . BACKGROUND PBAPS UNIT 2 The feedwater and main turbine high water level trip instrumentation is designed to detect a potential failure of the Feedwater Level Control System that causes excessive feedwater flow. With excessive feedwater flow, the water level in the reactor vessel rises toward the high water level setpoint, causing the trip of the three feedwater pump turbines and the main turbine. Digital Feedwater Control System (DFCS) high water level signals are provided by six level sensors. However, only three narrow range level sensors are required to perform the function with sufficient redundancy. The three level sensors sense the difference between the pressure due to a constant column of water (reference leg) and the pressure aue to the actual water level in the reactor vessel. (variable leg). The three level signals are input into two redundant digital control computers. Any one of the three signals is automatically selected (by the digital control computer) *as the signal to be used for the high level trip. Each digital control computer has two redundant digital outputs (channels) to provide redundant signals to an associated trip system. Each digital control computer processes input signals and compares them to pre-established setpoints. When the setpoint is exceeded, the two digital outputs actuate two contacts arranged in parallel so that either digital output can trip the associated trip system. The tripping of both digital computer trip systems will initiate a trip of the feedwater pump turbines and the main turbine. A trip of the feedwater pump turbines limits further increase in reactor vessel water level by limiting further addition of feedwater to the reactor vessel. A trip of the main turbine and closure of the stop valves protects the turbine from damage due to water entering the turbine. (continued) B 3.3-58 Revision No. O L__ ___________________ _

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES (continued) APPLICABLE SAFETY ANALYSES LCO PBAPS UNIT 2 The feedwater and main turbine high water level trip instrumentation is assumed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1). The high water level trip indirectly initiates a reactor scram from the main turbine trip 26.7% RTP) and trips the feedwater pumps, thereby terminating the event. The scram mitigates the reduction in MCPR. Feedwater and main turbine high water level trip. instrumentation satisfies Criterion 3 of the NRC Policy Statement: The LCO requires two DFCS channels per trip system of high water level trip instrumentation to be OPERABLE to ensure the feedwater pump turbines and main turbine will trip on a valid reactor vessel high water level signal. Two DFCS (one per trip system) are needed to provide trip signals in order for the feedwater and main turbine trips to Two l'evel signals are also required to ensure a single sensor failure will not the trips 6f the feedwater turbines and main turbine when reactor vessel water level is at the high water level reference point. Each channel must have its setpoint set the specified Allowable Value of SR The Allowable' Value is set to ensure that the are not exceeded during the event .. The actual setpoint is calibrat_ed to be consistent with the applicable setpoint methodology assµmptions ... Trip setpoints. are specified in the setpoint calculations, ... The trip setpoints*are selected to ensure . that the-setpoint§ do the Allowable Value between CALIBRATlONS. Operatioff with a t0ip setting less cbnservative'thari the trip setpo.int, but within its Allowable Value, 1s acceptable.

• setdoihts are those of output at which. an *action shoul*d take place. The setpoints are . to the actual process (e.g., reactor vessel w*ater level), and when the measured output value of *the process parameter exceeds the setpoint, the associat_ed . device ,. tr.ip unit) changes state. The analytic or design limits are derived from the limiting values of the pro-cess parameters -obtained from the safe.ty'analysis or continued . B 3.3-59 114 -. -. I BASES LCO (continued)* APPLICABILITY *ACTIONS PB.APS*UNIT 2 Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for talibration, process, and instrument errors. A channel is inoperable if its actual trip is not its required Allowable Value. The trip setpoints are determined. from analytical or design limits, corrected for calibration, process and instrument errors, as well as, instrument drift. The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environment the operating time for the associated channels are accounted for. The feedwater and main turbine high water level trip instrumentation is required to be OPERABLE 23% RTP to ensure that the fuel cladding integrity Safety Limit and the ciadding 1% plastic strain limit are not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE ( LHGR)," and LCO 3 .2 .2, "MINIMUM CRITICAL POWER RATIO (MCPR)," margin to these limits exists below 23% RTP; therefore, these requirements are only necessary when operating at.or above this power level. . . . A Note has been provided to modify the ACTIONS related to main turbine high water .level trip channels. Section 1.3, Completion Times, spetifies that ante a Condition has been entered, subsequent divisioris; subsystems, components, or variables expressed .in the Condition, discovered to inoperable or hot within* limits, will not in separate entry into *the Condition. Sec.tio*n 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable feedwater and main turbine high water trip instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable feedwater and main turbine high water level trip instrumentation channel. conti ued B Revision No. 114

'< ... **:-= ***' ** !, *. *. '*,' BASES . ACTIONS (continued) ,**,*** .. . ; _ .. ,. __ *. Feedwater and Main Turbine High Water Level Trip Instrumentation .

• B 3.3.2.2 With one or more feedwaterand main turbine high water level trip channels inoperable, but with feedwater and main*
• turbine high water level trip capability maintained (refer to Required Action B.l Bases), the remaining OPERABLE . channels can provide the required trip signal. However, overall instrumentation reliability is reduced because a single active instrument failure in one of the remaining channels may result in the instrumentation not being able to perfonn its intended function.* Therefore, continued operation ;s only allowed for a limited time with one or more channels inoperable. If the: inoperable chann.els cannot be restored to OPERABLE status within the Completion Time, the channels must be. placed in the tripped condi.tion per* Required Action Placing the inoperable channel in trip
• would conservatively compensate for the inoperabil ity,
• restore capability to acconunodate a single active instrument
• failure, and allow operation to continue with no. further
• restrictions. *Alternately, if it is not desired to place
• the channel ;n trlp as in the case where placing the. inoperable channel in trip would result in the feedwater and *main turbine trip), Condition C must be entered and its Required Act iOn taken. *. * * * . *The Completion Time of 72 hours is based op the low probability of the event occurring coincident with a single failure in a remaining OPERABLE channeL * .. Required Action: B. l is intel)ded to ensure *that appropricitl! * .
• actions. are taken> if multiple,* *untripped * . *.**.
• channels result in *the* High Water Level .function of DFCS not* .. **. maintaining feedwater and main* trip .* In . *.** this condit.ion, 'the feedwater and main turbine high water * ,level trip instrumentfition cannot perform its design . ,* ' ' functi,on. Therefore, cont.inued operation is only permitted :for a 2 hour period, durtng which feedwater and main turbine
• hlgh water level trip capability must be restored *. The tr.ip capability is considered maintained when. sufficient channels are OPERABLE or in trip. such that .the feedwater and main turbine high. water. level .* trip logic will generate a* trip * . _ .. ** ' " . :;:* . (continued) . .'* *-. . ,. -. . -.. *.** PBAPS 'UNIT 2 *.*. .* . . . . B 3.3-61 Revision No .. Cl .;* .. .: ,_.* '.,

--. . ' BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 B.l (continued) signal on a valid signal. This requires one channel per trip system to be OPERABLE or in trip. If the required channels cannot be restored to OPERABLE status or placed in trip, Condition C must be entered and its Required Action taken. The 2 hour Completion Time is sufficient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of feedwater and main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 hour Completion Time provtded in LCO 3.2.2 for Required Action A.l, since this instrumentation's purpose is* to preclude a MCPR violation. C.l and C.2 With any Required Action and associated Completion Time not met, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 23% RTP within 4 hours. Alternatively, the affected feedwater pump(s) and affected main turbine valve(s) may be removed from service since this performs the intended function of the instrumentation. As discussed in the Applicability section of the Bases, operation below 23% RTP results in sufficient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of 4 hciurs is based on operating experience to reduce THERMAL POWER to < 23% RTP from full power I conditions in an orderly manner and without challenging plant systems. Required Action C.l is modified by a Note which states that the Required Action is only applicable if the inoperable is the result of an inoperable feedwater pump turbine or main turbine stop valve. The Note clarifies the situations under which the associated Required Action would be the appropriate Required Action. The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function feedwater and main turbine high water level trip capability. Upon completion of the Surveillance, or expiration Df 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered atid Required Actions taken. This Note is based on the reliability analysis (Ref. 2) assumption of the average time required to perform -continued B 3.3-62 I I I I BASES. SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT .2 * . Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not reduce the probability that the feedwater pump turbines and main turbine will trip when necessary. SR 3.3.2.2.l Performance of the CHANNEL CHECK once every 24 hoDrs ensures that a gross failure of instrumentation has not occurred. A CHANNEl CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. The CHANNEL CHECK may be performed by comparing indication or by verifying the absence of the DFCS "TROUBLE" alarm in the control room. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels, or something even more serious. A CHANNEL CHECK will detect gross channel failure; it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION .. Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limits. The Surveillance is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with the channels required by the LCO. SR 3.3.2.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.3-6;3 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) *REFERENCE$ . ' .. , __ .* -' *, -. .-:: .. PBAPS UNIT 2 Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 SR 3.3.2.2.3 CHANNEL CALIBRATION is a check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary . range and accuracy. CHANNEL CALIBRATION leaves the channel adJusted to account for instrument drifts. be.tween successive calibrations, consistent the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Frequency Control Program. SR The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific system functional test of the feedwater and maiti turbine stop valves is as part of this and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete of the assumed safety function. if a stop is incapable of operating, the instrumentation would be inoperable. The

• Sur v e ill an ce Frequency i s control l e d under the .. 1
• Survei 11 a.nee Frequency Control Program.'. 1. UfSAR, :Section 14.5.2.2. . . 2. -"Bases for Changes :tb and Allowed .Selected Instrurnentat1op. Technical Spetifi<cations,". February 1991'. * * * .*** . ; .. * .-' *; ***:.* .. * ..
• Nb.

L--PAM Instrumentation B 3.3.3.l B 3.3 INSTRUMENTATION B 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND APPLICABLE SAFETY ANALYSES --PBAPS UNIT 2 The primary purpose of the PAM instrumentation is to display plant variables that provide information required by the control room operators during accident situations. This provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Events. The instruments that monitor these variables are designated as Type Category I, and non-Type A, Category I, in accordance with Regulatory Guide 1.97 (Ref. 1). The OPERABILITY of the monitoring instrumentation ensures that there is sufficient information available on selected plant parameters to monitor and assess plant status and behavior following an accident. This capability is consistent with the recommendations of Reference 1. The PAM instrumentatiOn LCO ensures the OPERABILITY of Regulatory Guide 1.97, Type A variables so that the control room operating staff can:

• Perform the diagnosis specified-in the Emergency Qperat ii"lg Procedures ( EOPs). These var'i ab 1 es are_ res:tri cted to prep 1 armed actions f()r -the primary success path of Design Basis Accidents (DBAs), (e.g., loss of coolant accident (LOCA)), and*
• Take the-specjfied; preplanned, manuallycontrolled actions ,for which control is provided, which are required -for :safety systems to accompl i_sh their safety function .. _ * -The_ PAM; iOn LCO al so ensures OPERABILITY of Ca:tegor.}rI, *non-Type)\, ables so that the contra l room operating* s:taff can: *
• Determine'whether systems important to safety are performing their i ntencied funct i oils; _ -<continued) ---_Revision No .. 0 BASES PAM Instrumentation B 3.3.3.l APPLICABLE
• Determine the potential for causing a gross breach of the barriers to radioactivity release; SAFETY ANALYSES * (continued) LCO PBAPS liNIT .. 2
• Determine whether a gross breach of a.barrier has occurred; and
• Initiate action necessary to protect the public and for an estimate of the magnitude of any impending threat. The plant specific Regulatory Guide 1.97 Analysis (Refs. 2, 3, and 4) documents the process that identified Type A and Category I, non-Type A, variables. Accident monitoring instrumentation that satisfies the definition of Type A in Regulatory Guide 1.97 meets Criterion 3 of the NRC Policy Statement. Category I, non-Type A, instrumentation is retained in Technical Specifications (TS) because they are intended to assist operators in minimizing the consequences of accidents. Therefore, these Category I v.ariables are important for reducing public risk. *
• LCO 3.3.3.1 requires two OPERABLE channels for all but one Function to ensure th.at no single failure prevents the operators from being presented with the information necessary* to determine the status of the plant and to bring the plant to, and maintain it in, a safe condition following that accident. Furthermore, provision of two channels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.
• The exception to the two channel requirement*is primary containment isolation valve (PCIV) position .. In this case, the important information is the status of the primary containment penetrations. The LCO requires one position indicator for each active PCIV. This is sufficient to redundantly verify the holation status of each isolable penetration either via indicated status of the active valve and prior knowledge of passive valve or via system boundary status. If a normally active PCIV is known to be closed and. deactivated, position indication is not needed to determine status. Therefore, the position indication for valves in this state is not required to be OPERABLE. {continued) : -: . B 3-.3-66 **Revision No. '.O BASES LCO (continued) PBAPS . UNIT. 2 PAM Instrumentation B 3.3.3.1 The following list is a discussion of the specified instrument Functions listed in Table 3.3.3.1-1 in the accompanying LCO. -1. Reactor Pressure Instruments: PR-2-2-3-404 A, B Reactor pressure is a Category I variable provided to support monitoring of Reactor Coolant System (RCS) integrity and to verify operation of the Emergency Core Cooling .. Systems (ECCS). Two independent pressure transmitters with a range of O psig to psig monitor pressure and associated independent wide range recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel. 2. 3. *Reactor Vessel Water Level {Wide Range and Fuel.Zone) Instruments: Wide Range: LR-2-2-3-110 A, B (Green Pen) Fuel Zone: LR-2-2-3-110 A, B (Blue Pen) Reactor vessel water level is a Category I variable provided to support monitoring of core cooling and to verify
• operation of the ECCS. The wide range and fuel zone water level channe.ls provide the PAM Reactor Vessel Water Level Functions. The ranges.of the wide range level ch_anne 1 s and the foe 1 zone water 1 evel channels . overlap to *cover a range of -325 inches (just below the botto* of the active fuel) tp +50 inches (above the normal water level). Reactor vesse 1 water 1 eve l . is meas.ured by separate di fferent-ial pressure transmitters.
• The *output from* these channels is on two pen recorders, which* is the primary indication used by the operator during an accident. Each recorder has two channels, one for wide water and orie for fuel zone . reactor vesse 1 water level
• Therefore, the PAM
• Specification deals specifically with these portions of the *1nstrument channels. {continued).
• B 3.3-67 Revision.No. 7 BASES LCO (continued) PBAPS UN IT* 2 PAM Instrumentation B 3.3.3.1 4. Suppression Chamber Water Level (Wide Range) Instruments: LR-8123 A, B Suppression chamber water level is a Category I variable provided to detect a breach in the reactor coolant pressure boundary (RCPB). This variable is also used to verify and provide long term surveillance of ECCS function. The wide range suppression chamber water level measurement provides the operator with sufficient information to assess the status of both the RCPB and the water supply to the ECCS. The wide range water level recorders monitor the suppression* chamber water level from the bottom of the ECCS suction 1 i nes to five feet above norma 1 water level . Two wide range suppression chamber water level signals are transmitted from separate differential pressure transmitters and are continuously recorded on two recorders in the control room. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel. 5. 6. Drywell Pressure (Wide Range and Subatmospheric Range) Instruments: Wide Range: PR-8J02 A, B (Red Pen) Subatmospheric Range: PR-8102 A, B (Green Pen) Drywell pressure is a Category I variable provided to detect breach of the RCPB and to verify ECCS functions that operate to maintain RCS iritegrity. The wide range and subatmospheric range drywell pressure channels provide the PAM Drywell Pressure Functions. The wide range and subatmospheric range drywell pressure channels overlap to cover a range of 5 psia to 225 psig.(in excess of four times the design pressure of the drywell). Drywell pressure signals are transmitted from separate pressure transmitters and are continuously recorded and displayed on two independent control room recorders. Each recorder has two channels, one for wide range drywell pressure and one for subatmospheric range drywell pressure. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with these portions of the instrument channels. {continued) B 3.3-68 Revision No. 3 BASES LCD (continued) PBAPS UNIT. 2 7. Drywell High Range Radiation Instruments: RR-8103 A, B PAM Instrumentation B 3.3.3.1 Drywell high range radiation is a Category I variable provided to monitor the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. Post accident drywell radiation levels are monitored by four instrument channels each with a range of 1 to lxl08 R/hr. These radiation monitors drive two dual channel recorders located in the control room.* Each recorder and the two associated channels are in a separate division. As such, two recorders and two channels of radiation monitoring instrumentation Cone per recorder) are required to be OPERABLE for compliance with this LCO. Therefore, the PAM deals specifically with these portions of the instrument channels. 8. Primary Containment Isolation Valve CPCIV) Position PCIV is a Category I provided for verification of .containment integrity .. In the case of .PCIV pcisition, the important information is the isolaticin status . of the penetration. The LCD requires one* channel of valve positi'on indication in the control room to be OPERABLE for each active PCIV in a containment penetration flow path*, i.e., two .total channels of PCIV posit.ion i ndi ca ti on for a penetration flow path with two active For penetrations with only one active PCIV having control room indication, Note Cb) 0equirei channel of valve position indication to be_ This is to redundantly verify the i s.ol ati on* status of each. i solabl e penetration vi a indicated the atti.ve valve, as applicable, and prior *knowledge of passive valve or _system boundary status. If a penetraflon now path: is isolated*;_:position-indication.for *.the PCIV(s)_ in. the associate'd penetration flow path is not *needed to determine status; *Therefore, the positiOh * ..
• for in an isolated penetraticin flow path is not required fo be.'.OP[RABLE. The PCI.V position PAM *
• i nstrumel'ltati consists of positi'on switches, ated .wi:r:ing and tontr"Ol* roorn indicating lamps for acttv*e PCIVs (check valves and manual val'ves are not required' to have. *Therefore, 'the PAM Specification deals**specjffcally with these instrument channels. . . . *. . -*" ;,*:. B 3.3-69
• Revision No .. 57 BASES .LCO (continued) **:.', PSAPS UN.IT 2 9. 10. Deleted ' ' ' PAM Instrumentation B 3.3.3.1 11 .. Chamber Temperature . Instruments .. :* TR-8123 A; B TIS"2-2-71 A, B Rec;:orders Suppression chamber.water temperature is a Category variable provided to detec;:t a condition that could. potentially lead to containment breach and to verify the.' effecti.veness of ECCS *actions taken to prevent containment .. b.reach.. The suppression chamber water temperature
• instrumentation allows operators to detect trends in** suppressjon ch.amber wa.ter temperature in sufficient time to .take aclion.lq,prevent .steam quenching vibrations in the suppressiOn p()ol .. 5µppression<chamber water* temperature.is monitored by two* redundant c.hannel s. *. Ea*ch channel is assi.gned -to a separate 'safeguard power division .. Each channel . .c6nsi sts. -of. i3 .resista0ce temperalure* detecto.rs. CRTDs) mounted in' thermowells.installed .i.n :the. suppression chambe,r *shgll below .* the 111itii munr.water level ,
• a processor, and. control room *recorders *. The RTDs 'a re mounted in each of '13 of Uie {6 segments 6f the suppressi'on 'chamber. The RTD' ( conti n*ued) *** **-. < -*:*.:-*-* B 3.Jc?Q Revisi*on No.* 55 ....

BASES (continued) LCD APPLICABILITY ACTIONS * --*.-.. PBAPS UN IT 2 PAM Instrumentation . B 3.3.3.1 11. Suppression Chamber Water Temperature (continued) inputs are averaged by the processor to a bulk average temperature output to the associated control room recorder. *The allowance that only 10 RTDs are required to be OPERABLE for a channel to be corisidered OPERABLE provided no 2 adjacent RTDs are inoperable is acceptable based on engineering judgement considering the response profile of the suppression chamber water volume for analyzed evehts and the most challenging RTDs inoperable. These recorders ate the primary indication used by the operator during an accident. Therefore, the PAM . Specification deals specifically with this portion of the instrument channels. Four recorders are provided. A recorder in each di vision is required to .be OPERABLE to satisfy the LCO.

• The PAM instrumentation LCO is applicable in MODES 1 and 2. These variables are related to the diagnosis and preplanned actions required to DBAs. The applicable DBAs are assumed to occur in MODES 1 and 2. Iri MODES 3, 4, and 5, plant conditions are such that the.likelihood -of event that would require PAM instrumentation is extremely low; therefore, PAM instrumentation is not required to be OPERABLE iri these MODES. A Note has been provided to modify the ACTIONS related to PAM instrumentation channels. Section 1.-3, Completion Times, that once a Condition has entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits, will result in separate entry into the Conditicin. Section 1.3 also specifies that Required Act.ions of the Condition continue to apply for each additi6nal failure, Completion Times on initial entry into the Condition. However, the* Required Actions for (continued) B 3.3c71 *.Revision No. 52 *.,'. ... '.

,-;-BASES ACTIONS (continued) PBAPS UNIT. 2

• PAM Instrumentation B 3.3.3.1 inoperable PAM instrumentation channels provide appropriate compensatory measures for separate Functions. As such, a Note has been provided that allows separate Condition entry for each inoperable PAM Function. When one or more Functions have one required channel that is inoperable, the required inoperable channel must be restore.d to OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channels (or, in the case of a Function that has only one required channel, other non-Regulatory Guide 1.97 instrument channels to monitor the Function), the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval. If a channel has not been restored to OPERABLE status 1n
• 30 days, this Required Action specifies initiation of action in accordance_ with Specification 5.6.6, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown . requirement, stnce alternative actions are identified before loss of functional capability, and given the likelihood of plant conditions that would require information provided by ; this instrumentation. C.1 *. When one or Functions have two required channels that are inoperable (i.e., two channels inoperable in the same Function), one channel in the Function should be restored to'*. OPERABLE status within 7. days. The Completion Time Qf
• 7 days is based on the relatively low probability of an *event requiring PAM instrument operation and the
• availability to obtain the required inforfuation. Contiriuous operation with two required (continued)* B 3.3-72 Revision No. 3 BASES ACTIONS . . -.. " ' PBAPS UNIT 2 C.l (continued) PAM Instrumentation B 3.3.3.1 channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur. D .* l This Required Action directs entry into the appropriate Condition referenced in Table 3.3.3.1-1. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met the Required Action of Conditioh C and the associated Completion Time has expired, Condition D is entered for that channel and provides for transfer to the appropriate subsequent Condition. For the majority of Functions in Table 3.3.3.1-1, if the Required Action and associated Completion Time of Condition C is not met, the plant must be brought to a MODE in which the LCD not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. F.l Since alternate means of monitoring drywell high range radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the. areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels. *(continued) . B 3.3-73 .-Revision No. 3 PAM Instrumentation B 3.3.3.l BASES (continued) SURVEILLANCE REQUIREMENTS '* *--*. SR 3.3.3.1.1 Performance of the CHANNEL CHECK.once every 31 days ensures that a. gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should* read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious.. A CHANNEL 'CHECK wi 11 detect gross channel failure; thUs, it is key to verifying the instrumenfation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation be c6mpared to similar plant instruments located throughout the plant. Agreement are determined by the plant staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readabili.ty. If a channel is* outside the criteria, it may be an indication that the sensor or the .signal processing equipment has dr.ifted o.utside its *limit. The Frequency is controlled under the Frequency Program. The suppl eni_e.nts :les*s formal' bu't niore frequent' checks of . channels duri rig normal operat'i anal use of those di spi ays associ Cited with the channels required by fhe LCD . . SR 3. 3': 3. L 2* Deleted . _-._ ,* **.. . SR 3.3.3.l.3 These .$.Rs CHANNE*L CALiBRATIONs-to be. performed. A .*
• CHANNEL; CALI BRAT.ION i.s a co.mpl ete ch.eCk :of the instrument 'sensor .. The test verifies the channel* responds t.o measured parameter with the riec*essary range an_d accuracy. *For the Pos.ition Function, the CHANNEL CALIBRATION. cqnsists of verifying the .remot'e i.ndication conforms t.Q* actual valve position. * *
• 0 ,-. -*-( . ***. ,.**.* ' ... .. . . \ PBAPS UNIT .:2 B 3.3-74 *Revis.ion No. 86 ,.-;

BASES SU'RVEI LLANCE REQUIREMENTS REFERENCES .. ' . ,*_. ,._ -P BA P S l)N IT , 2 PAM Instrumentation B 3.3.3.1 SR 3.3.3.1.3 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control 1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," Revision 3, May 1983. 2. NRC *Safety Ev al uati on Report, "Peach Bottom Atomic station, Unit Nos. 2 and 3, Conformance to Guide 1.97;" January 15, 1988. 3. Letter-from Y. CNRC) to G. J. Beck CPECo) dated February 13, 1991 concerning "Conformance to Regulatory Guide 1.97 for Peach Bottom Atomic Power Sta ti on, Units 2 and 3". 4.

• letter from S. Dembek CNRC) to G. (PECO Energy) dated Marth 1994 concerning "Regulatory* 1.97 -Boiling.Water Reactor Neutron Flux Atomic Station CPBAPS), Units 2 and 3". . . . . * . .:; -,': .. ,._ _. __ :. . *. . . B . .* *** Revi soion No. 86 Remote Shutdown System B 3.3.3.2 B 3.3 INSTRUMENTATION B 3.3.3.2 Remote Shutdown System
• BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 The Remote Shutdown System provides the control room operator with sufficient instrumentation and controls to maintain the plant in a safe shutdown condition from a locatibn other than the control ro6m for at least one hour. This capability is to protect against ihe . possibility of the room becoming inaccessible. A scife shutdown condition is defined as MODE 3. With the plant in MODE 3, the Reactor Core Isolation Cooling CRCIC)
• System and the safety/relief valves can be used to remove core decay heat and meet all safety requirements. The long supply of water for the RCIC the ability to control reactor pressure and level from outside the control room allow extended operation in MODE 3. In the event that the contrbl room must be abandoned, a reactor trip and MSIV closure is assumed to have been initiated from the control robm prior to abandonment. For *the design event, it is assumed the loss of feedwater (as a result of MSIV closure) causes an automatic start of RCIC due to low reactor level. Althbugh HPCI also .typically initiates on low reactor level, it is conservatively assumed that it does ncit start for the design event to damage in the control room. *No LOOP, accident condition or other failures are assumi;!d. At the remote shutdown panel, reactor level and pressure is maintained with RCIC and operation of SRVs H, E*and L. SRV operation maintains pressure below the SRV lift* setpoi nt and transfers decay heat to. the ** s u p p res s i on po o 1 . Th i s c a n
• be ma int a i n e d for a t 1 e a s t on e hour without suppression pool cooling. If control room access cannot be regained in one hour, procedures provide direction to bring the plant to cold shutdown. The OPERABILITY of the Shutdown ensures there are .sufficient controls and information available for those plant parameters necessary to maintain the plant in MODE 3. for at least one hour. Other controls and indication on the remote shutdown panel are but they are not required for OPERABILITY. The. Remote Shutdown System is required to provide instrumentation and controls at appropriate locations outside*the control room with a design capability tb control reactor pressure and 1 evel, including the. necessary instrumentation and controls, to maintain the plant in a safe in MODE 3.
• continued B 3< Revision No. 132 1*;: . '.: BASES APP LI CABLE SAFETY ANALYSES (continued) LCD APPUCAB(LITY-PBAPS UN IT 2, Remote Shutdown System B 3.3.3.2 The criteria governing the design and the specific system requirements of the Remote Shutdown System are located in the UFSAR _(Refs. 1 and 2). The Remote Shutdown System is considered an important contributor to reducing the risk of accidents; as such, it meets Criterion 4 of the NRC Policy Statement. The Remote Shutdown System LCD provides the requirements for the OPERABILITY of instrumentation and controls necessary to maintain the plant in MODE 3 from a location other than the control room. The instrumentation and controls required are listed in Table B 3.3.3.2-1. The controls, instrumentation, and are those required for: -* -pressure vessel CRPV) pressure control;
• Decay heat and_
• RPV inventory control Remote Shutdown System is OPERABLE if all instrument and control channels heeded to support the remote shutdown function OPERABLE. The Remote Shutdown-System and_ control circuits coveretl by this LCD do not need to be energized to be considered OPERABLE. This LCD is intended_ to ensure that the i_nstruments and control circuits wi 11 be OPERABLE 'if -pl ant coriditi ons require that _the Shutdown SYstem be placed in I The Remote Shutdown System LCD is_appli.cable in MODES 1 _ -------* 2. is required so that the plant tan be in MODE 3 for an extended period of time from a location_-other than the control r.oom. continued B Revision No. 132
• .1 BASES APPLICABILITY (continued) ACTIONS PBAPS. UN IT 2 Remote Shutdown System B 3.3.3.2 This LCO js not applicable in MODES 3, 4, and 5. In these MODES, the plant is already subcritical and in a condition of reduced Reactor Coolant System energy. Under these conditions, considerable time is available to restore necessary instrument control Functions if control room instruments or control becomes unavailable. Consequently, the TS do not require OPERABILITY in MODES 3, 4, and 5. A Note has been provided to modify the ACTIONS telated to Remote Shutdown System Functions. Section 1.3, Completion Times, specifies that once a Condition has been entered, divisions, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Coriditibn. However, the Required Actions for inoperable Remote Shutdown System Functions provide appropriate compensatory measures for separate Functions. As such, a Note has been provided that allows separate Condition entry for each Remote Shutdown System Function. *
• Condition A addresses the situation where one or more required Functions of the Remote Shutdown System is inoperable. This includes the control and transfer switches for any required function. The Required Action is to restore the Function (all required channels) to OPERABLE status within 30 days. The Completion Time is based on operating experience and the low probability of event that would require evacuation of the control room. continued B 3.3-78 Revision No. 52 I I_ *:, .. BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS REFERENCES, * ,._ .' .-.-* *.. -.-:. PBAPS UNIT 2 Remote Shutdown System B 3.3.3.2 If the Required Action and associated Completion Time of Condition A are not met, the plant must be to a MODE in which the LCD dcies not app1y. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time is based on operating experience, to reach the required MODE from full power conditions in an orderly manrier and without challenging plant systems. SR 3.3.3.2.1 SR verifies that each instrument and control circuit in B 3.3.3.2-1 performi the intended function. This verification is performed from the remote shutdown panel and locally, if necessary. Operation of equipment from the remote shutdown panel is not necessary. The Surveillance can be satisfied by performance of a continuity check of the circuitry. Thi's wi 11 ensure that.* if the control ro6m becomes inactessible, the plant can be maintained in MODE 3 frpm the remote shutdown panel. EaEh required iransfer switch and circuit is limited to those -that necessary to reactof and . from the. remote shut.down panel during operation in Mode 3. The Surveillance Frequency is controlled under the Surveilla-nce frequenty Control Program. -_,. SR-3.3:3:2.2 -.CHANNEL 'CALIBRATION is. a:-complete of the inst rumeht
• _ loop-and the sensor. The. test verifies the ch_annel responds to measured parameter valUes wH_h the necessary range and accuracy,-The Surveillance is .controi led under the
• S_urveiJlance _* FVequency _Control Program; --. --_. * ,*, ...
• _.-; 1. UFSAR; Secfi on °L5 .1. 2. UFSAR, Sei::tlon 7.18. ,3;: ,. qrawin'g -..
• 4. :r,R -* ... '.. .*". : .. .. ; -_ B 3. 3 -79 ' Revision No. 132 -I I Remote Shutdown System B 3.3.3.2 Table B 3.3.3.2-1 (page 1 of 3) Remote *Shutdown System Instrumentation FUNCTION REQUIRED NUMBER OF CHANNELS Instrument Parameter 1. Reactor Pressure 2 2. Re.actor Level (Wide Range) 2 3. Torus Temperature.
• 2 4. Torus Level 1 5. . Condensate Storage Tank Level 1 6. RCI C Flow 1 7. RC IC Turbine Speed 1 8. RCIC Pump Suction Pressure 1 9 *. RCIC Pump Discharge,Press0re 1 '* 10; RCIC Turbine Supply Pressure l . 11. RCIC Turbine Exhaust Pressure 1 12. Drywel l* Pressure 1 Transfer/Control Parameter* . , . . 13. RCIC Pump* Flow. *1 ** ' .*.c ' 14; RCICDrain Isoiation .to 1:. 15.
• R¢Jt*.:steam Pot Drai*n steam Trap r '*,C_.. 16.
• RCI*C Drain Isolation to Main Condenser 1 ...
• I I ., . . * .:*, . ': . . PBApS UNIT 2. . . *. , ... *." .. * . s.i on* No: 132 . .. :.* .**.

Remote Shutdown System B 3.3.3.2 Table B 3.3.3.2-1 (page 2 of 3) Remote Shutdown System Instrumentation . . FUNCTION REQUIRED NUMBER OF CHANNELS Transfer/Control Parametet .(continued) 17. RCIC Exhaust Line Drain Isolation 18. RCIC Steam Isolation 19. RCIC Suction from Condensate Storage Tank 20. *RCIC Pump Discharge 21. RC.IC Minimum Flow 22. RCIC Pump Discharge to Full Flow Test Line 23. RCIC Suction from Torus 24. RCIC Steam Supply 25. *. RCIC Lube Oil Cooler Valve . 26. RCIC Trip Throttle Valve Operator Position 27. RCIC Trip Throttle Valve Position 28.. RCI C Vacuum Breaker 29: RCIC Condensate Pump 30. RCIC Vacuum Pump 31. Safety/Relief Valves (S/RVs). ** .. PBAPS UNIT 2 .** .. B 3.Jc,81 2 (1/valve) 2 (1/valve) 1 2 (1/val ve) 1 1 2 (1/valve) 1 1 1 1 1 .. 1 1 3 (1/va 1 ve) continued Revision No. 132 I I I I I I I I Remote Shutdown System 8 3.3.3.2 Table B (page 3 of 3) Remote Shutdown System Instrumentation FUNCTION REQUIRED NUMBER OF GHANNELS Transfer/Control Parameter 32 . Auto I s o l a t i on Re s et 33. Instrument Transfer PBAPS UN n 2' 8 3.3-82 2 (I/division) 5 (1/transfer switch) No. 132' ATWS-RPT Instrumentation B 3.3.4.1 B 3.3 lNSTRUMENTAlION B 3.3.4.1 Transient Without Scram Recirculation Pump Trip Instrumentation BASES BACKGROUND APPLICABLE SAFETY ANALYSES, LCO, and APP LI.CAB I LlTY PBAPS UN IT 2

• The ATWS-RPT System initiates an RPT, adding negative reactivity, following events in which a scram does not (but should) occur, to lessen the effects of an ATWS event. Tripping the pumps adds negative reactivity from the increase in steam voiding in the core area as core fl ow decreases. When Reactor Vessel Water Level -Low Low (Level 2) or Reactor Pressure-High setpoint is reached, the recirculation pump motor breakers trip. The ATWS-RPT System includes sensors, relays, and switches that are necessary to cause initiation of an RPT. The channels include electronic equipment that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs an ATWS-RPl signal to the trip lDgic. The ATWS"RPT of two trip systems.* There are Functions: Reactor Pressure-High and Reactor
• Vessel Water Level -Low Low (Level 2). Each trip system has two channels of Reactor Pressure-High and two channels of . Reactor Vessel Water Level -Low Low (Level 2). Each ATWS-RPT trip system is a one-out-of-two logic for each Function. Thus, one Reactor.Water Level-Low Low (Level 2) or Reactor Pressure-High signal is needed to trip a trip system. Both trip systems must be in a tripped condition to initiate the trip of both recirculation pumps (by tripping the recirculation pump motor breakers); Each recirculation pump has two breakers in series to disconnect the to the recirculation pump motor. A dedicated trip mechanism is to each breaker for the ATWS signal. When the ATWS signal is initiated via the reactor pressure high or reactor level low-low, these breakers will trip automatically and disconnect the power to the motor. The ATWS-RPT is not assumed in the safety analysis. The ATWS-RPT initiates an RPT to aid in preserving the integrity of the fuel cladding following events in which a scram does not, but should, occur. Based on its contribution to the reduction of overall plant risk, however, the instrumentation meets Criterion 4 of the NRC Policy Statement. continued B 3.3-83 Revision No. 115 ..

... : -; '. BASES ATWS-RPT Instrumentation B 3.3.4.1 APPLICABLE SAFETY ANALYSES, LCO, and . The OPERABILITY of the ATWS-RPT is dependent on the OPERABILITY of the individual instrumentation channel Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of APPLICABILITY (continued) . . . . . --.-. . -PBAPS UNIT 2 . SR 3.3.4.1.3. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Channel OPERABILITY also includes the associated recirculation pump drtve motor breakers. A channel is inoperable if its actual trip setting is not its required Allowable Value. Allowable Values are specified for each ATWS-RPT Function specified in the LCO. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure.that the setpoints not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting less than the trip but within its Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an actio.n should takeplace. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the* process parameter exceeds the setpoint, the associated device changes state. The or design limits are derived from the limiting of th.e process parameters obtained from the safety * . analysis. The Allowabl,e Values are derived from the.* . analytic or design limits*, corrected for calibration, process, a11d instrument errcirs as well as instrument drift. In selected cases*; the Allowable Values and :trip setpoints are deterinfned by engjneerfllg judgement or historically accepted practice relative to the intended function of the channel. trip setpoints determined. in this manner. ptovide.adequate protection by assuring* instrument and process uncert'a inti es

• expected for the envtronments. during .* the operating time of the associated channels are*accounted .* ** * * * * * * * * * *. ** * * . : . . .... -. **The 'individuaf'Functions* are required *to be: QPERABLE in
• M()DE Ltp .. prote¢t agaJnst.common,mode of the .,. Reactor Protection System by providing a diverse trip to mitigate the consequences of a :postulated ATWS event.. The . Reactor* p.ressure...;;.High and Reactor V.essel Water Level -Low Low (LeveF2) Functions are required to.be *OPERABLE in MODE.I sTnce t.he reaGtor is producing significant power ariq .. Ccontinuedl. .
• B 3.3-84 .. ** ., *. Revision NcL o BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) .. PBAPS. UNIT . 2 ATWS-RPT Instrumentation B 3.3.4.1 the recirculation system could be at high flow. During this MODE, the potential exists for pressure increases or low water level, assuming an ATWS event. In MODE 2, the reactor is at low power and the recirculation system is at low flow; thus, the potential is low for a pressure increase or low water level, assuming an ATWS event. Therefore, the ATWS-RPT is not necessary. In MODES 3 and 4, the reactor is shut down with all control rods inserted; thus, an ATWS event is not and the possibility of a significant pressure increase or low water level is negligible. In MODE 5, the one rod out interlock ensures that the reactor remains subcritical; thus, an ATWS event is not significant. In addition, the reactor pressure vessel (RPV) head is not fully tensioned and no pressure transient threat to the reactor coolant pressure boundary (RCPB) exists. *
• The specific Applicable Safety Analyses and LCO discussions are listed below on a Function by Function basis. a. Reactor Vessel Water Level-Low Low (Level 2) Low RPV water level indicates that a reactor scram should have occurred and. the capability to cool .the fuel may be threatened. Should RPV water level decrease too far, fuel damagecould result. The ATWS;.RPT System is initiated* at Level 2 to assist in the mitigation of the ATWS event. The resultant
• reduction of core fl ow reduces the neutron flux and THERMAL POWER and, therefore, the rate of coolant . boil off. * . Reactor v.es.sel water level signals are initiated from .. four. 1 evel tl"arismltters that sense the difference * *. between the pres.sure due to a constant column of. water (reference.leg) and *the pressure due to the actual ,water Jevel (variable leg) in* the vessel.*
• Four channels of Reactor Vessel Water Level Low * * :"(LeVel 2), with two channels 1n each trip system, are .*-available and required to be OPERABLE to ensure that no single. instrument failure can preclude an ATWS-RPT from this Function, on a val id signal. The Reactor * * * * * *
• Vessel Water Level_;,,, Low low (Level A 11owab1 e Value . . . ' . . (continued) . e *
• Revision No. Q . .. -' ....

BASES ATWS-RPT Instrumentation B 3.3.4.1 APPLICABLE a. Reactor Vessel Water Level-Low Low (Level 2) {continued) SAFETY ANALYSES,

• LCO, and . APPLICABILITY ACTIONS PBAPS :UNIT 2. .-. ',.' is chosen so that the system will not be initiated after a Level 3 scram with feedwater still available, and for convenience with the reactor core isolation cooling initiation. b. Reactor Pressure-High Excessively high RPV pressure may rupture the An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This increases neutron flux and THERMAL POWER, which could potentially result in fuel failure and overpressurization. The.Reactor Pressure-High Function initiates an RPT for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core power generation. For the overpressurization event, the RPT aids in the termination of the ATWS event and, along with the safety/relief valves, limits the peak RPV pressure to less than the ASHE Section lII Code limits. * * -The Reactor Pressure-High signals are initiated from four pressure transmitters that monitor reactor steam dome pressure. Four channels of Reactor High, with two channels in each trip system, are *.available and are required to be OPERABLE to ensure * *. that*no single instrument failure can preclude an from this Function on a valid signal. The Reactor Pressure-High Allowable Value is chosen to provide an adequate margin to the ASME Section III Code limits.
• A Note has been provided to modify the ACTIONS related to ATWS-RPT instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each (continued) Rev.ision No. **O *.,:* ...
• _*:

BASES ACTIONS (continued) PBAPS UN IT

• 2 ATWS-RPT Instrumentation B 3.3.4.l additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ATWS-RPT instrumentation channels provide appropriate compensatory measures for separate inoperable
• channels. As such, a Note has been provided that allows
• separate Condition entry for each inoperable ATWS"."RPT instrumentation channel. A.I and A.2 With one or more channels inoperable, but with trip capability for each Function maintained (refer to Required Actions B.l and C.l Bases), the ATWS-RPT System is capable of performing the intended function. However, the reliability and redundancy of the ATWS-RPT instrumentation is reduced, such that a single failure in the remaining trip system could result in the inability of the ATWS-RPT System *to perform the intended function. Therefore, only a limited time *is allowed to restore the inoperable channels to OPERABLE status. Because of the diversity of sensors available to provide trip signals, the low probability of extensive of inoperabilities affecting all diverse *.Functions, and the low probability of an event requiring the initiation of ATWS-RPT, 14 days is provided to restore the inoperable channel (Required Action A.I). Alternately, inoperable channel may be placed in .trip (Required
• Action A.2), since this would conservatively compensate *for * . the i noperabil i ty, restore ,capability to accommodate a * . single failure, and .allow operation to continue. As noted, placing the channel in trip with no further restrictions is not aJlowed if the inoperable channel is.the result of an . inoper.able.breaker; siilcethis may not adequately compensate
• for' the inoperable breaker (e.g., the breaker may be **inoperable such that it will not open). If it is not desired to place the channel in trip as in the case where placing the inoperable channel would result in an . . RPT) , or if the inoperable channel is th.e result of an . inoperable breaker, Condition D must be entered and its *. _Required Actions taken.
• B. l *. Requi_red.Action intended.to ensure that appropriate actfons are taken if multiple, inoperable, untripped . channels w.ithin the same Function result in the Function :not.*.* (continued) B 3.3-87 . Revision No.* o*

BASES ACTIONS .

• PBAPS UNIT 2 B.l (continued) ATWS-RPT Instrumentation B 3.3.4.1 maintaining ATWS-RPT trip capability. A Function is considered to be maintaining ATWS-RPT trip capability when sufficient channels are OPERABLE or in trip such that the . ATWS-RPT System will generate a trip signal from the given Function on a valid signal, and both recirculation pumps can be tripped. This requires one channel of the Function in each trip system to be OPERABLE or in trip, and the recirculation-pump drive motor breakers to be OPERABLE or in trip. The 12-hour Completion Time is sufficient for the operator to take corrective action (e.g., restoration or tripping of channels) and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during this period and that one Function is still maintaining* . ATWS-RPT trip capability *. Required Action C.l is intended to ensure that appropriate Actions are taken if multiple, inoperable, untripped channels within both Functions result in both Functions not maintaining ATWS-RPT trip capability. The description of a Function maintaining ATWS-RPT* trip capability is discussed in the Bases for Required Action 8.1 above. The I hour Completion Time is sufficient for the operator to *take corrective action and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during this period. D.l and D.2 With any Required Action and associated Completion Time not met, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 2 within 6 hours (Required Action D.2). Alternately, the associated recirculation pump may be removed from service since this performs the intended function of the instrumentation (Required Action D.l). The allowed Completion Time of (continued) B 3.3-88 Revision No. O BASES ACTIONS SURVEILLANCE REQUIREMENTS ., **:.:'* .. ; -.*. PBAPS UNIT 2 0.1 and 0.2 (continued) ATWS-RPT Instrumentation B 3.3.4.1 6 hours is reasonable, based on operating experience, both to reach MODE 2 from full power conditions and to remove a recirculation pump from service in an orderly manner and without challenging plant systems. Required Action 0.1 is modified by a Note which states that the Required Action is only applicable if the inoperable channel is the result of an inoperable RPT breaker. The Note clarifies the situations under which the associated Required Action would be the appropriate Required Action. The Survei1lances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances; entry into the associated Conditions and Required may be delayed for up to' 6 hours provided the associated Function maintains ATWS-.RPT trip capability. Upon completion of the _ or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. Th i s N o te i s b a s e d on t h e re l i a b i l it y a n a l y s* i s ( Ref. 1 ) assumption of the average time required to perform channel -Surveillance. -That _analysis demonstrated that the 6 hour testing allowance does not significantly.reduce the probability that the_recirculation*pumps will trip when -** SR 3.3'4.Ll Performa'rice of the CHANNEL CHECK ensures that -a* gross failure of instrumentation ha.s not occurred. A CHANNEL CHECK Ts normally ;a comparison of the* parameter indicated *on. one_ channe.l to a similar pa-rameter on other channels.-It_ is.* based .on -.the 'assumption' that instrument channels man Hori ng the -same parameter should.read aj:JproxiJT1ately the value._ Si ghi ficant devi'alfohs between the instrument channels coul_d be an 1ridicati-on ofexc*essive instrument drift in one of the -.channels or" scimeth1ng.even mor-e-<serious-. -A 'cHANNIL * -*will detect gross channel failure; thus; it i_s key to. verifying the instrumentatitin continues to operate properly between CALJBRATION. . . . . . Agreement cti ter1 a -are det.ermi ned. by the pl ant staff ba.sed .;OD a. C,Ombfnation ,Of the channel instrument Uncertainties, .. 'includ1ng indicatlon 'and rea*dability. -If a channel is _ outstde the it-may be,an .. that the -iristr'ument'has drif_ted outside its_ limit. --(continued) B 3.3-89 Revision No .. 86 BASES SURVEILLANCE REQUIREMENTS ' .' .. -, ... --:* .' .. -; P BA P S U N I t. 2 SR 3.3.4.1.1 (continued) ATWS-RPT Instrumentation B 3.3.4.1 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHECK supplements less formal, but more frequent, checks of channels during operational use of the displays with the required channels of this LCO. SR 3.3.4.1.2 A CHANNEL FUNCTIONAL TE.ST is performed on .each required channel tci ensure that the entire channel will perform the intended 1unction. Any s*tpoint adjustment shall be consistent* with the assumptions of the current pl ant specific setpoint method9logy. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.4.1.3 A CHANNEL CALIBRAtION is a complete check of the instrument loop and the sensor. This test verifies the responds to the measured parameter within. the accuracy. CHANNEL_ teaves the channel to account for drifts between successive calibrations, consistent_with ihe assumptibhs of the plant specific setpointinethodo\ogy. The Frequency is controlled under the Su r.ve i Hance Frequency Control P rog r'am. SR -3.3.4/1.4-.. -. . .. -__ The LOGIC.SYSTEM.FUNCTLONALTEST-demonstrates the 0-PERABilITY of the requi r.ed trip -1 ogi c fbr' a channei': The systerii functional test of the pump breakers is inclu_d_ecLas part of this Surveillance and -overlaps.the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the_ assumed safety functi ori. Therefore,. if_ a breaker is -incapab.le of operating,the associated-instrument chann_el(s) would be Jn'operabre:* --_.: ,* (continued) ---B -Re vision No. 86 I -

BASES SURVEILLANCE REQUIREMENTS REFERENCES p:BAPS *UN IT 2 SR 3.3.4.1.4 (continued) ATWS-RPT Instrumentation B 3.3.4.1 The Surveillance Frequency is controlled.under the Surveillance Frequency Control Program.* 1. GENE-770-06-1, "Bases for Changes To Survei 11 ance Test Intervals and Allowed Out-of-Service Times For Selected Instrumentation Technical Speci fi cations," *February 1991. /" /. Revisioh No. 86 **

i. I ) ... EOC-RPT Instrumentation B 3.3.4:2 B 3.3 INSTRUMENTATION B 3.3.4.2 End of Cycle Recirculation Pump Trip CEOC-RPT) Instrumentation BASES BACKGROUND PBAPS UNIT 2 The EOC-RPT instrumentation initiates a recirculation pump trip (RPT) to reduce the peak reactor pressure and power resulting from turbine trip or generator load rejection transients and to minimize the decrease in core MCPR during these transients. The benefit of the additional negative reactivity in excess of that normally inserted on a scram reflects end of cycle reactivity considerations. Flux shapes at the end of cycle are that the control rods insert only a small amount of negative reactivity during the first few feet of rod travel upon a: scram caused by Turbine Control Valve CTCV) Fast Closure, Trip Oil Pressure-Low or Turbine Stop Valve (TSV)-Closure. The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity at a faster rate than the control rods can add negative reactivity. The EOC-RPT instrumentation, as shown in Reference l, is composed of sensors that detect initiation of closure of *the TS Vs or fast closure of the TC Vs, combined with relays, . logic circuits, and fast acting circuit breakers that interrupt power from the recirculation pump adjustable speed drives (ASOs) to each of the recirculation pump . motors. When the setpoint is exceeded, the channel output relay actuates, whjch then outputs an EOC-RPT signal to the trip logic. When* the RPT breakers trip open, the tecircu1ation *pumps coast down under their own inertia. The EOC-RPT two identical trip systems, eittier 6f which tan actuate an RPT.

• Eath frip is a logic for each . . Function: ,thus, either two TSV-Cl osure or two TCV Fast Clos.ure, Trip Oil Pressur*e-Low signals are required for a trip system to: actuate ... If either trip system actuates' . *both pumps will trip. There two EOC-RPT breakers in series per rcul ati on pump. One trip sys fem .*trips one of the two breakers for recirculation (Continued).*
• B 3.3-91a. . Revi SiOf'l No. 137 BASES BACKGROUND (continued) APP LI CABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 2 EOC-RPT Instrumentation B 3.3.4.2 pump, and the second trip system trips the other EOC-RPT breaker for each recirculation pump. The and the TCV Fast Closure, Trip Oil Pressure-Low Functions are designed *to trip the recirculation pumps in the event of a turbine trip or generator load rejection to mitigate *the neutron flux, heat flux, and pressurization transients, and to minimize the decrease in MCPR. The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection, as well as other safety analyses that utilize. EOC-RPT, are summarized in References 2, 3, and 4. To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of movement of either the or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a scram alone so that the Safety *Limit MCPR is not exceeded. Alternatively, APLHGR operating limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE CAPLHGR)"), the MCPR operating limits CLCO 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)"), and the LHGR operating 1 imits *(LCO 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)") for an inoperable EOC-RPT, as speci1ied in the COLR, are sufficient to allow this LCO to be met. The RPT function is disabled when turbine first stage pressure is < 26.7% RTP. EOC-RPT iTistrumentaticin satisfies Criterion 3 of the NRC Policy Statement. The OPERABILITY of the EOC-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions, i.e., the TSV-Closure and the TCV Fast Closure, Trip Oil Pressure-Low functions. Each Function must have a required number of OPERABLE channels in each trip system, *with their setpoints within the specified Allowable Value of SR 3.3.4.2.3. Channel OPERABILITY also includes the assotiated EOC-RPT breakers. Each channel (including the associated EOC-RPT breakers) must also respond within its assumed response time. Allowable Values are specified for each EOC-RPT Function specified in the LCO. setpoints are specified in the plant design The trip setpoints are selected continued B 3.3-91b Revision No. 114 BASES APPLICABLE SAFETY ANALYSES, LCO, and APP LI CA BI LITY (cohtinued) <. *,*' -.**1 PBAPS UNI-f:z: EOC-RPT Instrumentation B_ 3.3.4.2 to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Dperation with a trip less conservative than the trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setting is not within its required Allowable Value. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the attual process parameters (e.g. TSV position), and when the measured output value of the process parameter exceeds the setpoint; the associated (e.g., limit switch) changes state. The analytic limit for the TCV Fast Closure, Trip Oil Pressure-Low was determined based on the TCV hydraulic oil circuit design. The Allowable Value is from the analytic limit, corrected for calibration, -process, and instrument errors. The trip setpo.i nt is _determihed from* the analytical limit corrected for calibratiori; process, and instrumentation as well as instrument drift; as applicable. The Allowable Value and trip setpoint the TSV-Closure Function was determined by engineering judgment and historically for -siinilar trip functions. Thi Analysis, LCO; and Applicability discussi-ons are listed below on a Function by F0nctioh -Alternat1veJy; since the instrurnentation protects against a MCPR SL violatioh, with the instrumentation-inoperable, __ modHications to the APLHGR ,operating limits _(LCO 3.2.1, -* "AVERAGE'-PLANAR LINEAR HEAT GENERATION RATE .CAPLH9R)"), the_ MCPR, opercitihg limits CLC0.3.2;2; :"MIN-IMUM CRITICAL POWER -RAf!O CMCPR)"); ancj theLHGR-operating limits CLCO 3._2.3, -*-"LJNEAR._,HEAT GENERATION RATE CLHGR)") may be applied to --all Ow this LCO to b_e met. The.appropriate MCPR operating limits -and power thermal limit adjustments for the -conditi'on are specified in the COLR. --.Turbine Sto'p' :' .. , --: ' Closure -of th'e TSVs and a main turbine trip result -i_n the -loss -of-a si n-k t"hat produc.es *reactor pressure, neutron fl lJX, an'd _heat ti ux transients_ that must be .limited. RPT is i*nitiated*on TSV_:__Closure in ---*arit\ci p'?t ion. of the transi erit's that would result from -* closure of these* '--1a hes., _ EO_C RPT _ d_ecreases peak reactor pqwer <:i"hd a18s the reactor scram f°ri ensur-ing_that the SL riot e((c_eeded during the worst transi erit. * *-(continued) B 3 ._3-9k Rev'i si on* No; 49 BASES APPLICABLE SAFETY ANALYSIS, LCD, a.nd APPLICABILITY * .. _,-_ PBAPS*UNij 2 EOC-RPT Instrumentation B 3.3.4.2 Turbine Stop Valve-Closure (continued) Closure of the TSVs.is determined by measuring the position of each valve. There are position switches associated with each st6p valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV-Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAl 26.7% RTP as measured at the turbine first *I stage pressure: This is normally accomplished automatically by pressure switches sensing turbine first stage pressure; therefore*, opening of the turbine bypass valves may affect this Function. Four channels of TSV-Closure, with two channels in each trip system, are available and required to be.OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT frorn this Function on a valid signal. The TSV-Closure Allowable Value is selected to detect imminent TSV closure. This.EOC-RPT Function is required, consistent with the safety analysis assumptjons, whenever POWER is 26.7% RTP. Below 26.7%.RTP, the Reactor Pressure-High I and the Average Power Range Monitor (APRM) Scram Clamp *Functions of the Reactor Protection System CRPS) are
• to maintain the necessary safety margins. Turbine Control Closure. Trip Oil Pressure -Low Fast closure of the TCVs during_ a generator load rejecti.on . results in the 1 oss of a heat sink that produces reactor pressure, neutron flux, and heat fl.ux traniients that must . be.limited .. an RPT is initiated on TCV Fast Tr]p Oil Pressure-low in anticipation of the transients that. would re*sui t -fr-om the closure of these valves. The E'dC-RPT peak reactor power.and_ aids . the reactor scram in. ensuring that the MCPR SL is not _ * ;exceeded' during the :worst case transient:
• of. the -TCVs is by measuring the -controlfluid pressure at-each contr'ol. valve. Tbere is. one pressure switch .as.socia_ted with each contr'ol valve, and the' signa.l from each switch-is assigned to a separate trip the logic fbr the TCV Fast Closure; Trip Oil Pressu.re"--Low Functicin. is .such that two or must be. *closE{d-'*(pressu_re switchtr::ips) * -* * .*-* *.* . _, .:-* *(continued} _.B:3.3-91d-Revision Nci .. 114 _.*-*.

BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY ACTIONS * . . . . ' :* " ' PBAPS' UN Ir'° 2 EOC-RPT Instrumentation B 3.3.4.2 Turbine Control Valve Fast Closure. Trip Oil Pressure-Low (continued) to produce an EOC-RPT. This Function be enabled at THERMAL 26.7% RTP as mecisured at turbine first stage pressure. This is normally accomplished automatically by switches sensing turbine first stage pressure; thereforei opening of the bypass valves may affect this Function. Four channels o( TCV Fast Ciosure, Trip Oil Pressure-Low, with. lwo channels in each trip system, are available and required to.be OPERABLE to ensure that no. single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TCV Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure. This protection i.s consistent with the analysis whenever THERMAL POWER 26.7% RTP. Below 26. 7% RTP, the Reactor Pressure-High and the APRM Scram Clamp Functions of the RPS are adequate to maintain the safety margins. A Note been provided to modify the ACTIONS related to EOC:RPT thannels. Section 1,3, Completion specifies that once a Condition has been entered, subsequent diyisions, subsystems, components, variables expressed in the Condition, to inoperable or limits, will not result in separate eritry int6.

• the Section 1,3 also specifies that Required of the Condition continue ta each failure; with Completion Times based on initial entry into the Con.dition. However, the Required Actions for inoperable instrumentation chanhels pr6vide appropriate compensatory measures for separate inoperable channels. As such, a Note has been pfovided that allows separate Condition entry for each inoperable EOC-RPT instrumentation channel. continued -Revision No, li4 : *.:-B

,.-' BASES ACTIONS (continued) PBAPS UNIT 2* A . 1 ___ 9_o_g __ )\.. .. 2. Instrumentation B 3.3.4.2 With one or more required channels inoperable, but with EOC-RPT trip capability maintained (refer to Required B.l Bases), the EOC-RPT System is capable of performing the intended function. However, the reliability and redundancy of the EOC-RPT instrumentation is reduced such that a single failure in the remaining trip system could result in the inability of the EOC-RPT System to perform the intended function. Therefore, only a limited time is allowed to compliance with the LCD. Because of the diversity of sensors available to provide trip. signals, the low probability of extensive numbers of inoperabilities all diverse Functions, and the low probability of an event requiring the initiation of an EOC-RPT, 72 hours is provided to restore the inoperable channels (Required Action A.1). Alternately, the inoperable channels may be placed in trip (Required Action A.2) this would conservatively compensate for the inoperability, capcibility to accommodate a single failure, and allow operation to continue. As noted in Required Action A.2, placing the channel in trip with no further restrictions is not allowed if the inoperable channel is the result of an inoperable breaker, since this may not adequately* compensate for the inoperable breaker (e.g., the .. breaker may be such that it will not open). If

• it is not desired to place the channel in trip (e.g., as in the placing the inoperable channel in trtp result in an RPT, or if the is result of an inoperable breaker), Condition C must be entered and its Required Actions taken. Required Action B.1 is intended to ensure that appropriate actions are taken .. if multiple, inoperable, untripped .** channe.l s within the same Function result in the Function not maintaining trip .A Fµnction is to maintaining EOC-RPT trip capability when* OPERABLE rir in such that:the System wi.ll generate a trip signal from the given function on a valid signal and both pumps can* be This requires two channels of the Function in the same trip system, to each be OPERABLE or in trip, and the EOC-RPT breakers. to be OPERABLE . . *. ,* (continued.) B 3.3.-9lf Revision No. 57 BASES ACTIONS SURVEILLANCE REQUIREMENTS* PBAPS UNIT 2 .B..,_.l (continued) EOC-RPT Instrumentation B 3.3.4.2 The 2 hour Completion Time is sufficient time for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of the EOC-RPT instrumentation during this period. It is also consistent with the 2 hour Completion Time provided in LCD 3.2.1 and 3.2.2 for Required Action A.I, since this instrumentation's purpose is to a thermal limit violation. C.1 and C.2 With any Requited Action and Completion Time not met, THERMAL POWER must be reduced to < 26.7% RTP within 4 hours. Alternately, for an inoperable breaker (e.g., the breaker may be inoperable such that it will not open) the associated recirculation pump may be removed from service, since this performs the intended function of the The allowed Completion Time of 4 hours is reasonable, based on experience, to reduce THERMAL POWER to< 26.7% RTP from full power conditions in an I. orderly manner and without challenging plant systems. Required Action C.l is modified by a Note which states that the Required Action is only applicable if ihe inoperable channel is the result of an inoperable RPT breaker. The . Note the situations under which the associated Required Action would be the appropriate Required Action. The Surveillances are modified by a Nqte to indicate that when a channel is placed in an inopetable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains EOC-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 5) assumption of the average time to perform channel Surveillance. That
• analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the recirculation pumps will trip when continue B 3 .3-9_lg Revision No. 114 BASES SURVEILLANCE REQUIREMENTS (continued) . *,* .... *: .': ,, '** P BA P S U N IT --2 SR 3. 3 .A. 2 .1 EOC-RPT Instrumentation B 3.3.4.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that entire channel will perform the intended funttion. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.4.2.2 CHANNEL CALIBRATION is a complete check of the instrument loop sensor. This test verifies the channel responds to the measured. parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusteci t-0 account for instrument drifts between successive *cal i brati ans consistent with the pl ant specific setpoi nt methodology. The $urvei l'l ance is controlled under the Surveillance Frequency C-0ntrbl Program: SR 3.3.4.2:3 . Th.e LOGIC SYSTEM FUNCTIONAL TEST demonstrates .the GPERABJLITY of the required trip logic for a specific channel.*-* The system functionai test of the pump breakers is included as. a part of this test, overlapping the LOGIC -SYSTEM FUNCTION-AL TEST' to .provide_ complete testing of the associated safety function.*:Theref-ore, if a breaker is incapable of ope.rating, the associated instrument channel(s) alsb be
• The. Surv'e1li ance Frequency is. confrol led -under. the. Surveillance .Frequency Program . . * . .:_ -* : . : ' . --*> **.'* .. : ,.**.* *-*. -* .. -:' . *. *'* (continued) -*'*.* ;;.,_ : . ( *_ -1 B. 3 . 3 -91 h :. -Revision No. 86' -".' .. ---'

BASES SU RV EI LLANCE REQUIREMENTS (continued) .* . , .. PBAPS UNIT 2 . SR 3.3.4.2.4 EOC-RPT Instrumentation B 3.3.4.2 This SR ensures an EOC-RPT initiated from the TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER 26.7% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual Because main turbine bypass flow can affect this. setpoint nonconservatively (THERMAL POWER is derived from first stage pressure) the main turbine bypass valves must closed during the calibration at THERMAL POWER 26.7% RTp to ensure that the calibration remains valid. If* any bypass channel's set point is nonconservative Ci. e,, the are bypassed at 26.7% RTP, either due to open main turbine bypass valv*s or other the affected TS.V--:-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the condition Cnonbypass}. If placed in the nonbypass condition, this SR is met with the channel* considered OPERABLE. The Surveillance is controlled under the Frequency Program. SR

• 3*. 3. 4. 2. 5. *.This SR* ensures that the* i ndi vi dual channel response ti nies are less than or equal to"the maximum values assumed in the analysis. The EOC-RPT SYSTEM RESPONSE TIME acceptance _criterion is included i h Reference 6. states that interruption time tnay be *assumed from. th_e most recent performance of This** is allo.wed since*the-time to-open the contacts after energi zati*or:i of the trip coil and the arc * *suppress1.on time areshort and* do not appreciably change, due.'. to the design of the breaker opening d*evi ce and the .fact *that the breaker* rs not. routinely cycled. * * . . ,-. (continued) . *.*--* B. 3 .*3-9 Revisi6n No; 114 BASES SU RV EI LLANCE REQUIREMENTS REFERENCES ' .. *. . PBAPS UN IT 2 SR 3.3.4.2.5 (continued) EOC-RPT Instrumentation B 3.3.4.2 Response times cann6t be at power because o¢eration of final actuated devices is required. The Survei 11 a nee Frequency .is controlled under the Survei 11 a nee Frequency Control Program.
• SR This SR that the RPT breaker interruptidn time Care suppression time plus time to open the contacts) is provided tci the EOC-RPT SYSTEM RESPONSE TIME test. The Frequency is controlled under the Surveillance Frequency Control Program. 1.. UFSAR, Figure 7.9.4A, Sheet 3 of 3 CEOC-RPT logic diagram). 2. UFSAR, Section 7.9.4.4.3. 3. UFSAR, Section 4. "General Electric Standard Application Reactor latest approved version. 5. GENE-770-06-1-A, "Bases for Changes to Surveillance Test Intervals Allowed Out-Of-Service Times for Selected Instrumentation Technical Spetifications,"
• December 1992. *
• 6. Co.re Operating Limits' Report. '.: . . -Revision No. 86 ECCS Instrumentation B 3.3.5.1 B 3.3 INSTRUMENTATION B 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation BASES BACKGROUND PBAPS UNIT 2 The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that the fuel is adequately cooled in the event of a design basis accident or transient. For most abnormal operational transients and Design Basis Accidents (DBAs), a wide range of dependent and independent parameters are monitored. The ECCS instrumentation actuates core spray (CS), low pressure coolant injection (LPCI), high pressure coolant injection (HPCI), Automatic Depressurization System (ADS), and the diesel generators (DGs). The equipment involved with each of these systems is described in the Bases for LCO 3.5.1, "ECCS-Operating." Core Spray System The CS System may be initiated by automatic means. . . Automatic initiation occurs for conditions of Reactor Vessel** . . Water Level-Low Low Low (Level 1) or Drywell Pressure--High
• with a Reactor Pressure-Low permissive. The reactor vessel water level and the reactor pressure are monitored by four redundant transmitters, which are, *in turn, connected-to four-pressure compensation instruments. The drywell pressure variable is monitored by. four redundant .* transmitters, which are, in turn, connected to four trip units. The outputs of the pressure compensation instruments and the trip units are connected to relays*which send. * *signals to two trip systems, with each trip system arranged in. a one-out;..of-two taken twice logic (each trip unit sends .
• a signal to bo.th trip systems.) Each trip system initj ates two of the four CS pumps. Upon receipt of an initiation signal, if normal AC power iS . available_, CS pumps A and C start after a time delay of--approximately 13 seconds and CS pumps B and D start after a time delay of approximately 23 seconds. If normal AC power is not available, the four cs .pumps start simultaneously after a time delay of approximately 6 seconds after the *. respective-DG is ready to load. (continued) B 3.3-92 *Revision No*. o BASES BACKGROUND PBAPS UNIT 2 .
• Core Spray System (continued) ECCS Instrumentation B 3.3.5.1 The CS test line isolation valve, which is also a primary containment isolation valve (PCIV), is closed on a CS initiation signal to allow full system flow assumed in the accident analyses and maintain primary containment isolated in the event CS is not The CS pump discharge flow is monitored by a differential pressure indicating switch. When the pump is running and discharge flow is low enough so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum *flow setpoint to allow the full system flow assumed in the accident analysis. The CS System also monitors the pressure in the reactor to ensure that, before the injection valves open, the reactor pressure has fallen to a value below the CS System's maximum design pressure. The variable is monitored by four redundant transmitters, which*. are, in turn, connected to four pressure* compensation instruments. The outputs of the pressure compensation instruments are connected to relays whose contacts are arranged in a one-out-of-two taken twice . logic. Low Pressure Coolant Injection System The LPCI is an operating mode of the Residual Heat Removal (RHR) System, with two LPCI subsystems. The LPCI subsystems may be initiated by automatic means. Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low (level 1); Drywell Pressure-High with a Reactor
• Pressure-Low (Injection Permissive). The drywell pressure variable is monitored by four redundant transmitters, which, in turn, are connected to four trip units. The reactor vessel water level and the reactor pressure variables are monitored by four redundant transmitters, which are, in . turn, connected to four pressure compensation instruments.
• The outputs of the trip units and pressure compensation instruments are connected to relays which send signals to *
• two trip systems, with each trip system arranged in a out-of-two taken twice logic (each trip unit sends a signal *to both trip systems). Each trip system can initiate all four LPCI pumps. (continued) B 3.3-93 Revision No. O I
• I I BASES BACKGROUND -... *;:. ' . ' .---:_.;_*. -PBAPS UNITZ ECCS Instrumentation B 3.3.5.1 Low Pressure Coolant Injection System (continued) Upon receipt of an initiation signal if normal AC power is available, the LPCI. A and B pumps start after a delay of approximately 2 seconds. The LPCI C and D pumps are started after a delay of approximately 8 seconds. If normal AC power is not available, the four LPCI pumps start simultaneously with no delay as soon as the standby power source is available *. Each LPCI subsystem's discharge flow is monitored by a differential pressure indicating switch. When a is running and discharge flow is low enough so that pump overheating may occur,**. the *respective mini mum fl ow return line valve is opened. If flow is above the minimum flow setpoint, the valve is automatically closed to allow the full system flow assumed in the analyses. The RHR test line suppression pool cooling isolation valve, suppression pool spray isolation valves, and containment spray. isolation valves (which are also PCIVs) are also closed on a LPCI in.it'iation signal to allow the full system flow assumed in the accident analyses and maintain primary. containment isolated in. the event LPCI is not operating. * *. . . . . ' ' *' . . . . . . . . .* . . The LPCI System monitors the pressure in the reactor to ensurettlat,.beforean injectfon valve opens, the reactor pressure has fallen to. a value below the LPCl System's * . maximum'.design pressure. The variable is monitored by four redundant transmitters, which are,* in turn, connected to f ou*r pressure compensation inst r*uments. ; The* outputs of . the pressure compensation instruments are comiected to relays . wh,ose conta¢ts .are arranged in a cme-out*of-two taken twice 1 'Additionally/.instruments are provided to close the recirculation pump di.scharge ,valves to ensure .that LPCI flow does .not bypass the core: when it. injects into the* . .. recir,-cul at ion Jj nes. The-variable *is. monitored by four whkh in turn, connected .. to***
• four *pressiire *comperisati on _ The outputs of the . **pressure compensation are to relays whose contacts are arranged in taken twice logtt: .* .. **-. ** .. ,:_* *A continued) *---* . ,, -' , . '* ._, ' . B 3.3-9_4 **Revision O BASES BACKGROUND . --; : . , .. PBAPS UNIT 2 ECCS Instrumentation B 3.3.5.1 Low Pressure Coolant Injection System (continued) Low reactor water level in the shroud is detected by two additional instruments. When the level is greater than the low level setpoint LPCI may no longer be required, therefore other modes of RHR suppression pool cooling) are allowed. Manual overrides for the isolations below the low level setpoint are provided. High Pressure Coolant Injection System The HPCI System may be initiated by automatic means. AutomatiC initiatfon occurs for conditions of Reactor Vessel Water Level -Low Low (Level 2) or* Drywel 1 Pressure-High. The reactor vessel water level variable is monitored by four -redundant transmitters, which are, in turn, connected to four pressure compensation instruments. Thedrywell pressure variable is monitored by four redundant -transmitters, which are, in turn, connected to four trip units. The outputs -of the pressure compensation instruments and the trip units are to relays whose contacts are arranged in a_one-out-of-two taken twice logic for*each Function. ---. -: --. . . ' . . . The HPCI pump discharge flow is monitored by a flow switch. When 'the pump is running. and.discharge flow is low enough so that pump overheating may occur, the minimum fl ow return line valve is opened. The valve is automatically closed_ if flow is_,above the minimum flow Setpointto allow the full system flow assumed in the safety analysis* * . the-HPCL_test .line isolation valve (which .also a PCIV) is closed upcin receipt of a HPCI initiation signal to allow the full system fl ow: ,*in. the accident analysis and *-* maintain priniary containment isolated -iil the event HPCI *is not operating. --The HPC(System alsomoni{ors*the water le-vels in the _ condensate-storage.t.ank .. (CST) and the suppression pool .because these are the two>sources of water for HPCI .--_ operation: _Reactor grade water in -the CST is the normal_---___ source. -Upon receipt of 'a HPCI initiation signal, the CST -' -. -. ---' * . . --(cont 1 nued) _ ---*'.. . .-.----. B -J .3-95 *-. -... Re*.v-ision No. o , ... _,-.. * . ..

BASES BACKGROUND .. PBAPS UN IT 2 . . .. -.:., ECCS Instrumentation B 3.3.5.1 High Pressure Coolant Injection System *(continued) suction valve is automatically signaled to open (it is normally in the position) unless both suppression pool suction valves are open. If the water level in the CST falls below a preselected level, first the suppression pool suction valves automatically open, and then the CST suction valve automatically closes. Two level switches are used to . detect low water level in the CST. Either switch can cause the suppression pool suction valves to open and the CST suction valve to close. The suppression pool suction valves also automatically open and the CST suction valve closes if high water level is detected in the suppression pool. To prevent losing suction to the pump, the suction valves are interlocked so that one suction path must be open before the other automatically closes.

• The HPCI provides makeup water to the reactor until the reactor vessel water level reaches the Reactor Vessel Water Level--High (Level 8) trip, at which time the HPCI turbine trips, which causes the turbine's stop valve and the control .to close. The logic is to provide high reliability of the HPCI System. The HPCI System automatically restarts if a Reactor Vessel Water Level--Low Low (Level 2) signal is subsequently received. Automatic Deoressurization System The ADS may be initiatec;I by automatic means. Automatic initiation occurs when signals indicating Reacto*r Vessel Water Level--Low Low Low (Level 1); Drywell Pressure--High or ADS Bypass Low Water Level Actuation Timer; Reactor Vessel.Water Confirmatory Level--Low (level 4); and CS or LPCI Pump Discharge Pressure--High are all present and the ADS_Initiation Timer has timed out. There are two transmitters each for Reactor Vessel Water Level--Low Low Low (Level 1) and Drywell :Pressure--High, and one transmitter for Reactor Vessel Water Confirmatory ( Level 4) in each of the two ADS trip systems*. Each of these transmitters connects to a trip unit, which then drives a relay whose cont.acts form the initiation logic. 'Each ADS trip system includes a time delay between satisfy-Ing the initiation logic and the actuation of the ADS valves. The ADS Initiation Timer time setpoint chosen is long enough that the HPCI has sufficient operating time (cont i mied l Revision o**** ' -' . . ' --------

BASES BACKGROUND PBAPS UNIT_ -2 ECCS Instrumentation B Automatic Depressurization System {continued) to recover to a level above Level 1, yet not so long that the LPCI.and CS Systems are unable to adequately cool the fuel if the HPCI fails to maintain that level. An alarm in the-control room is annunciated when either of the timers is timing. Resetting the ADS initiation signals resets the ADS Initiation Timers. The ADS also monitors the discharge pressures of the four LPCI pumps and the four CS pumps. Each ADS trip system includes two discharge pressure permissive switches from all four LPCI pumps and one discharge pressure permissive switch from all four CS pumps. The signals are used as a permissive for ADS actuation, indicating that there is a source of core coolant available once the ADS has depressurized the vessel. Two CS pumps in proper combination {C or D and A or B) or any one of the four LPCI *pumps_ is sufficient to permit automatic depressurization.

• The ADS logic in each trip system is arranged in two strings.
• Each string has a contact from each of the following variables: Reactor Vessel Water Level-Low Low Low {Level l); Drywell Pressure-High; Low Water Level Actuation Timer; and Reactor Vessel Water Level-Low -Low Low {Level 1) Permissive. One of the two strings in each trip
• system must also have a Reactor Vessel Water Confirmatory -_ -Level-Low (Level 4). After the contacts for the initiation signal from either drywell pressure or reactor vessel level (and the timer for vessel level timing out} close, the following must be present to initiate an ADS trip system: all other contacts in both logic strings must _close,.the ADS initiation timer must time: out, and a CS or
• LPCI pump discharge pressure signal must .be present. Either -*the A or B tri_p system wi 11 cause all the ADS relief valves* to .open. Once the Drywell -Pressure_:High signal, the ADS Low Water Level Actuation Timer, or the ADS initiation . is present, it individually sealed in until manually reset.-Manual inhibit switches are provided in the control room. for the ADS; however, their-function is not required for ADS -OPERABILITY (provided ADS is not inhibited when required_ to-. -be OPERABLE). . (continued)* . B 3.3-97 Revision No.* o

i. .,:,**. .BASES ECCS Instrumentation B 3.3.5.1 BACKGROUND . . Di ese 1 . Gener'ators .. (cont i.nued) * . ' TheDGs may be initiated by automatic Automatic *.initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low (Level 1) .or Drywell Pressure-High. The DGs are also initiated upon loss of voltage signals. (Refer to the Bases for LCD 3.3.8.1, "Loss of Power (LOP) Instrumentation," for a discussion of these signals.) The . reactor .vessel water 1 evel variable is monitored by four redundant transmitters, which are, in connected to four pressure compensation instruments. The drywell pressure variable is monitored by four redundant transmitters, which are, in turn, connected. to. four trip units; The outputs of the four pressure compensation ** . instruments.and units are to relays which send signals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic (each trip* unit sends a signal to both trip systems). The A trip system initiates all four DGs and the B trip system initiates all four DGs. The OGs* receive their initiation signals from the CS System initiation logic. The can also be started manually from the control room and locally from the associated DG room .. Upon receipt of a loss of coolant (LOCA) initiation signal, each DG is started, is ready to load. in approximately

• 10 seconds, and will run in standby conditions (rated voltage artd with the DG output breaker dpen). The .DGs will only energize their respective Engineered Safety **Feature: buses if a 1 ass of offsite power occurs. (Refer to *_Bases for LCD 3.3.8.1.) APPLICABLE The aC:tfons of the ECCS are exp.licitly assumed in the safety SAFETY ANALYSES, analyses of References 1, 2, and 3. The ECCS is initiated lCO, and* * * . to preserve the of the fuel cladding by limiting *APPLICABILITY
• the post LOCA peak cladding temperature to 1 ess than the . _ .*' ..... ' *.'_ :*: **10CFR50.46limits; .. ECCS instiumentation satisfies Criterion *3 of the NRC Policy . Statement. Certairt instrumentation Functions are retained for other are described below in the individual
• discussion. *
• OPERABILITY of-theECCS instrumentation is dependent .upon the OPERABILITY of the individual instrumentation * .channel *Functions specified in Table 3.3.5.1-1. Each . Function must have a required number of OPERABLE channels, (continued) .. 'j UN tr *2* * : . 8 3.3-98 *Revision No. 21 *-... . ...
• _*. ', .... : .... *. *--.. :

BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY (continued) . *,-.,-.-.. " .. -. . *-*: .. ' ...... _ .. *

• t
• PBAPS UNIT 2 ECCS Instrumentation B 3,3.5.1 with their setpoints within the. specified Allowable Values, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Table 3.3.5.1-1 is modified by two footnotes. Footnote (a) is* added to clarify that the associated functions are required to be OPERABLE in MODES 4 and 5 only when their supported ECCS are required to be operable per LCD 3.5.2, ECCS-Shutdown. Footnote Cb) is added to show that certain ECCS instrumentation Functions also perform DG initiation. Allowable are specified for each ECCS Function specified in the Table. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to that the settings do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting less coriservative than the trip setpoint, but within its Allowable Value, 'i*s acceptable. A channel. is inoperable if its actual trip setpoint is not within its required Allowable Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the process parameter (e.g., reactor vessel water level), and when the measured output value of the. process parameter exceeds the setpoint, the associated device .* trip unit) changes The analytic or design limits are derived from the limiting
• val0es of the procesi obtained from the safety
• analysis appropriate documents; The Allowable Values are dedved from the analytic or design limits, corrected for calibrationi and instrument . The are from analytical or design *limits, corrected for calibration, process, and instrument. errors, as.well as; instrument drifL. Ln se*lected cases, the Al l6wabl e V 1ffues and_ trip setpoi nts a re determined from engineering judgement -or hi storlcal 1 y accepted practice relative to the intended* ft.:incti ans of the channe 1 . The_ trip.* ihis manrier provide *
• protection* by assuming *instrume.nt and process uncertainties expected for the erivi ronments during the operating ti me of * *_ the ass*oci ated channels <are. accounted for .. For .the Core Spray and LPCI Pump Start-Jime*oelay Relays/ adequate\ . ma.rgiris for* applicable: setpo.int._methodologies are* i YicorpOrated 'into the Allowable Va 1 ues and* actual setpofnts* . Ih genera], 'theiridividual Functions -are required to be OPERABLE i.n the MODES 6r cond.jtions that may* requfre ECCS Cor DG),; ni ti ati on to mitigate the consequences **.'oTa'deslgn basis transient'or accident. Tb ensure reliable ECCS ... and DG. function, a coinbi nation of Functions is required to .. pro_vide**prjmary and sec9ndar.Y initi{tlon signals.. . . .. .. '-. *. ' . ' .( c 0 .n ti h u e d ) B 3.3-99 *Revision No. 57 j .

BASES . APPLICABLE SAFETY. ANALYSES, LCO, and AP PU CAB I LITY (continued). PBAPS UNIT .2 .* ECCS Instrumentation B 3.3.5.1 The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis. Core Spray and Low Pressure Coolant Injection Systems l.a. 2.a. Reactor Vessel Water Level-Low Low Low (Level 1) Low reactor pressure vessel CRPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too.far, fuel damage could result. The lciw pressure ECCS and associated DGs are initiated at Reactor Vessel Water Level-Low Low Low (Level 1) to ensure that core spray and flooding functions are available to prevent or minimize fuel damage. The DGs are initiated from Function l*.a signals. This Function, in conjunction with a Reactor Pressure-Low (Injection Permissive) signal, also the closure of the Recirculation Discharge Valves to ensure the LPCI subsystems inject into the proper RPV location .. The Reactor .Vessel Water Level-Low Low Low 1) is one of the assumed fo be .OPERABLE and capable of initiating the.£CCS during the transients analyzed in References 1 3. In addition, the Reactor Vessel Water Level-Low Low Low (Level 1) Function is directly assumed in the analysis of line* break (Ref. 4) and* the control rod drop accident CCRDA) analysis. The core the ECCS, along with the scram action of the Reactor Protection System that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Reactor Vessel Water Level-Low Low Lciw C Level 1) signals are* initiated ,.from_ four Jeyel transmitters *that sense the difference between the pressure* due *to a constant column of *wafer frete*rerice and the pressure due to ;the actual *.water level (variable leg} *in the vessel.. * . . -*. . . . . *The Vessel Level-Low Low .(tevel 1)

• Allowable Value is*chosen.to allow time for the low pr.e'ssure core flooding systems to activate_ and. provide adequate*
• cooling: *. -. -_*.* . . Four s ;of Reactor Water Level.:,_ Low Low. Low .(Levell) Fu.nctioh are only.required to.be OPERABLE when the.*. to be OPER1ABdLEEtCoCSensure ,that no single _ 1 *. __ . instrument._ ure can prec
• B 3.3-100 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY *. PBAPS 'UNIT .2
• ECCS Instrumentation B 3.3.5.1 l.a. 2.a. Reactor Water Level-Low Low Low (Level 1) (continued) initiation. Per footnote (a) to Table 3.3.5.1"1, this ECCS function is only required to be OPERABLE in MODES 4 and 5
• whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2, Shutdown," for Applicability Bases for the low pressure ECCS subsystems; LCO "AC Sources-Operating";. and LCO 3.8.2, "AC Sources-Shutdown," for Applicability Bases for the DGs. l.b. 2.b. Drywell Pressure-High High pressure in the drywell could indi.cate a break in the reactor coolant pressure boundary The low pressure ECCS and associated DGs are initiated upon receipt. of the Drywel 1 gh Function wHh a Reae:tor Pressure-Low Cinjectitin Permissive) in order to minimize the of fuel damage. The DGs are initiated from Function l.b signals. This Function also. initiates the closure of the recirculation discharge valves to ensure the subsystems inject irito the proper RPV location. The Drywell Pressure-High Function with a Reactor Pressure-Low (Injection Permissive), along with the Reactor Water Level-Low Low Low CLevel.1) Function, is directly assumed in the of the recirculation line break (Ref. 4). The core cooling function of ihe ECCS, along with the scram action of the*RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. High drywell pressure signals are initiated from four pressure tfansmitters that sense drywell Allowable Value selected to be as low possible and be of LOCA inside primary The Drywell Pressure-High Function is .required to be OPERABLE when the ECCS or DG is required to be OPERABLE in conjunction with when the primary containment is required to be OPERABLE. Thus, four channels of the CS and LPCI Drywell Pressure-High Function are required to be OPERABLE in MODES 1, 2, and 3 to ensure that no single instrument failure can preclude ECCS and DG initiation. In MODES 4 and 5, the Drywell Pressure-High Function is not required, since there is insufficient energy in the reactor tb pressurize the primary to Drywell High setpoint. Refer to LCO 3.5.1 for-Applicability Bases 'for pressure ECCS subsystems and tti LCD for .. App_l i ca bi l i ty Bases for the DGs. C cont i n u ed.) .*
• B 57
• I i I -** ... *. .. BASES APPLICABLE SAFETY ANALYSES, LCD; and APPU CAB IL ITY (continued) PBAPS UNIT 2 -ECCS Instrumentation B 3.3.5.1 1.c, 2.c. Reactor Pressure-Low (Injection Permissive) Low reactor pressure signals are used as permissives for the low pressure ECCS subsystems. This ensures that, prior to opening the injection valves of the low pressure ECCS subsystems or initiating the low pressure ECCS subsystems on a Drywell Pressure-High signal, the reactor pressure has fallen to a value below these subsystems' maximum design pressure and a break inside the RCPB has occurred respectively. This Function also provides permissive for the closure of the recirculation discharge valves to ensure the LPCI subsystems inject into the proper RPV location. The Reactor Pressure-Low is one of the Functi ans assumed to be OPERABLE and capable of permitting initiation of the ECCS during the analyzed in 1. and 3. In addition, the Reactor Pressure-Low Function is directly assumed in the analysis of the recirculation line break -(Ref. 4). The core cooling function of the ECCS, along the scram action of the RPS, ensures that the fuel peak temperature remains below the limits of 10 CFR 50.46. The Reactor Pressure-Low signals are initiated from four pressure transmitters that sense the reactor dome pressure. --The Allowable Value is-low enough to prevent overpressuring the equipment in the low pressure ECCS, but high enriugh to ensure that the ECCS injection prevents the fuel peak cladding from exteeding the limits of 10 CFR 50.46. _Four channels of Reactor Pressure-Low Function are only to be OPERABLE when ECCS is to be OPERABLE t6 ensure that no single instrument failure ECCS initiation. Per,foothote {a) to -this ECCS Function is only required to be OPERABLE in MODES 4 and 5 whenever t_he associated ECCS is required to_ be OPERABLE per LCD 3.5;2.: Refer to LC03.5.1 and LCD 3.5 .. 2 for Applicability Bases for the-low pressure ECCS subsystems. ----1. d. 2.q. Core Spray arid Low Pressure Coolant Injection Pump Di sch a rge Fl ow-Low (Bypass) --The minimum instruments are provided to protect the low ECCS pump from overheating when
• is the associated injection valve is not -full/open; The minimum flow line valve i_s opened when low is and the is closed when the -fl OW r*ate is adequate to protect the pump. The LPC I and . (continued.) --8 3.3-102 Revisiori'Nfr_ 57; BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UN IT 2 ECCS Instrumentation B 3.3.5.l l.d. 2.q. Core Spray and Low Pressure Coolant Injection Pump Discharge. Flow-Low (Bypass) (continued) CS Pump Di sch a rge Fl ow-Low Functions a re assumed to be OPERABLE and capable of closing the minimum flow valves to ensure that the low pressure fCCS flows assumed during the transients and accidents analjzed in References l, 2, and 3 are met. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. One differential pressure switch per ECCS pump is used to detect the associated subsystems' flow rates. The logic is arranged such that each switch causes its associated minimum flow valve to open. The logic will close the minimum flow valve once the closure setpoint is exceeded. The LPCI minimum flow valves are time delayed such that the valves will not open for 10 seconds after the switches detect low flow. The time delay is provided to limit reactor vessel inventory loss during the startup of the RHR shutdown cooling mode. The Pump Flow-Low Allowable Values high enough to ensure that the pump flow rate is *sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core. Each channel of Pump Discharge Flow-Low Function (four CS channels and four LPCI channels) is only to be OPERABLE when the ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude the ECCS function. Per footnote (a) to Table 3.3.5.1-1, this ECCS Function is only required to be OPERABLE in MODES 4 and 5 whenever.the associated ECCS is required to be OPERABLE per LCD 3.5.2: Refer to LCD 3.5.l and LCD 3.5.2 for Applicability Bases for the low pressure ECCS subsystems. l.e. l.f. Core Spray Pump Start-Time Delay Relay The purpose of this time delay is to stagger the start of the CS pumps that are in each of Divisions I and II to . prevent overloading the power source. This Function is necessary when power is being supplied from the offsite sources or the standby power sources COG). The CS Pump Start-Time Delay Relays are assumed to be OPERABLE in the accident and transient analyses requiring ECCS initiation. That the analyses that the pumps will initiate when required and excess l-0ading will not cause failure of the power sources. (continued) B 3. 3-103 Revision No. 57

. .. .* . (' *i BASES AP PU CABLE SAFETY ANALYSES, LCD, and APPLICABILITY * .... :._,. . .-***-. PBAPS UN IT 2 ECCS Instrumentation B 3*.3.5.1 l.e. 1.f. Core Spray Pump Start-Time Delay Relay (continued) There are eight Core Spray Pump Start-Time Delay Relays, two in each of the CS pump start logic circuits (one for when offsite is available and one for when offsite power is not available). One of each type of time delay relay is dedicated to a single pump start logic, such that a single failure.of a Core Spray Pump Start-Time Delay Relay will not result in the failure of more than one CS pump. In this condition, three of the four CS pumps will remain OPERABLE; thus, the single failure criterion is met Ci .e., lbss of 6ne instrument does not preclude ECCS initiation). The Allowable Value for the Core Spray Pump Start-Time Delay Relays is chosen to be long enough so that the power source will not be over1oaded and short enough so that ECCS is not degraded. Each channel of Core Spray Pump Start-Time Delay Relay Function is required to be OPERABLE only when the associated .CS subsistem is required to be OPERABLE. Per footnote (a) to Table 3.3.5.1-1, this ECCS Function is only required to be OPERABLE in MODES 4 and.5 whenever the assdciated ECCS is required:to be OPERABLE' per LCD 3.5.2. Refer to LCD 3.5.1 and LCD 3:5.2 for Applicability Bases.for the CS subsystems: 2.d. ReactO'r Pressure'-low Low (Recirculation Discharge Valve Permissiv-e)** Low reactor: pressure signals are used as permissives for r.ecircu-l<ltion discharge valve closure; -This ensures that th.e LPCJ subsystems inject into the proper *RPV lo"cati on as"sumed in the: safety The. Reactor Pressure-Low . Low is' one of the lunct:ions assumed be OPERABLE arid *capable o-f closing the: valve during analyzed in References 1 and'3. The -core cooling function of lh*e ECCS; aJorig wi*th -the_ scr.<fm action. of the RPS, ensures that the fue:l peak cladd1.ng temp_erature .rem.a1ns below the limits of *10 CFR** 50 ,45*.* .Thf :Reactor Pres

• to_w Function .is direCtly assumed in*the analysis of the recir.culation line break* (Ref. 4).'. T_he Low signals are initiated t'rom four *pre;:;sclre 'tr*ansmitters .that sense .the reactor pressu.re*. * -, . ' , . . . ' . . . . . . . -. . . . ' .. Allowffble Value is to ensure thatthe valves c=lo$e<pricir' to commencement of lPCI injeetion flow into the core,* as a$5'umed i"n*the safetyarialysis . .... ** * (continued) . I . -B 3'.3-104. Revision.No. 57 J_.

BASES .. APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY ,. : *-.--.. :.-. -.* -** .* -. PBAPS UNIT 2 ECCS Instrumentation B 3.3.5.l 2.d. Reactor Pressure-Low Low (Recirculation Discharge . Valve Permissive) (continued) * *

• Four channels of the Reactor Pressure-Low Low Function are only required to be .OPERABLE in MODES I , . 2, and 3 with the associated reci.rculation pump discharge valve open. With the valve(s) closed, the function of the instrumentation has been performed; thus, the Function is not required. In MODES 4 and 5, the loop injection location is not critical since LPCI injection through the recirculation loop in either direction will still ensure that LPCI flow reaches the core (Le., there is .no significant reactor back pressul'.'e). * * *
• 2.e., Reactor Vessel Shroud Level -Level 0 The Reactor Vessel Shroud Level-Level O Function is provided as a permissive to allow the RHR System to be manually aligned from. the LPCI mode to the suppression pool cooling/spray or drywell spray modes. The reactor vessel shroud level permissive ensures that water in the vessel is .approximately two thirds core height before the manual transfer is allowed.* This ensures that LPCI is available to* prevent or minimize fuel damage. This function may be overri dd.en during ace ident conditions as all owed by pl ant proc:edures .. Reactor Vessel Shroud Level _;Level O Function
• is implicitly assumed in the *analysis of the recirculation line break (Ref. 4) since the analysis* that no LPCI flow diversion occurs when reactor water level is below level . . . . *Reactor .Vessel* Shroud Level "'.""'""Level 0 signals are initiated . from two.level transmitters .that sense the difference between the pressure due to a constant co 1 limn of water * * .** (reference leg)** and due to the actual* water.
• level (variable leg) *in .the vessel. . The Reactor Vessel .* Sh.roud Allowable Value. is chosen to allow the low core flooding *systems to activate and provide .adequate. cooling before allowing a manual transfer. * . . . . ** . {confinuedl' . * ... **:-_,* .*-. :---. --:.* Revfsion 0 .--:-** .. ' -_*: ... :

BASES APPLICABLE SAFETY ANALYSES, LCO .* and APPLICABILITY P,BAPS UN IT 2 '*'*' _.-... ECCS Instrumentation B 3.3.5.l 2.e. Reactor Vessel Shroud Level-Level 0 (continued) Two channels of the Reactor Vessel s*hroud Level -Level 0 Function*are only required io be in MODES 1, 2, and 3. In MODES 4 and 5, the specified initiation time of the LPCI subsystems is not assumed, and other administrative controls are adequate to control the associated with this Function (since the systems that the valves are opened for are not required to be OPERABLE in MODES 4 and 5 are normally not used). 2.f. Low Pressure Coolant Injection Pump Start-Time Delay Relay -The purpose of this time delay is to stagger the start of the LPCI pumps that are i.n each of Divisions I and II, to overloading the power source. This Function is only necessary when power is being supplied from offsite sources. The LPCI pumps start simultaneously with no time delay as soon as the standby source is available. The LPCI Pump* Start-Time Delay Relays are assumed to be OPERABLE i_n the and transient analyses requiring ECCS initiation. That is, the analyses assume that.the pumps will initiate when required and loading will not cause failure of -the power sources.

• There are eight LPCI Pump Start-Time Dela-y Relays, two in each of the RHR pump start logic circuits. Two.time delay relays are to a single pump start logic. Both timers in the RHR pump start logic would have to fail to prevent RHR pump:ffom starting within the required time; therefore, the low ECCS pumps wi]l OPERABLE; thus, the single failure criterion is met {j.e., loss of one i'nstrument does not preclude ECCS i ni ti ati ori). Th'e Allowable Values for the L-PCI Pump Start-Time Delay Relays are chosen to be lting enough so that most of the starting transient of the first pump is complete before starting the second pump on the same 4 kV emergency bus and short enough so that ECCS operation is not degraded. Each channel of LPCI Pump Start-Time Delay Relay Function. is to be OPERABLE oniy when the associated LPCI subsystem is required to be OPERABLE. Per footnote (a) to Table 3.3.5.1-1, this ECCS Function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is .required to be OPERABLE per LCD 3.5.2; R'efer to LCD 3.5.1 LCD 3.5.2 for Applicability Bases.for the LPCI subsystems. (continued) .. B .3;3-106
• Rei.Ii si on No . .57

i. * ; 1.* BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UNIT.*2 . ECCS Instrumentation B 3.3.5.1 High Pressure Cool ant Injection CHPCI) System 3.a. Reactor Vessel Water Level-Low Low (Level 2) Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the HPCI System is initiated at Level 2 to maintain level above the top of the active fuel. The Reactor Vessel Water Level-Low Low (Level 2) is one of the Functions assumed to be OPERABLE and capable of initiating HPCI during the transients

• analyzed in References 1 and 3. Additionally, the Reactor Vessel Water Level-Low Low (Level 2) Function associated with HPCI is credited as a backup to the Drywell Pres*sure-High Function for initiating HPCI in the analysis of the recirculation line break. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Reactor Vessel Water Low (Level 2) signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of . water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Reactor Vessel Water Level-Low Low (Level 2) Allowable Value is high enough such that for complete loss of feedwater flow, the Reactor Core ISolation Cooling (RCIC) System flow with HPCI assumed to fail will be sufficient to . avoid initiation-Of low pressure ECCS at Reactor Vessel Water Level-Low .Low Low (Level l). ' .
• Four channels of Reacto.r Vessel Water Level.-Low Low *(Level 2) Function are required to be. OPERABLE only when * . HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.1 for .HPCI Applfcability Bases .. ' ' 3. b. Drvwel l Pressure-High . High pressure in the drywell could indicate a break iri the RCPB *. The HPCI System is initiated upon receipt of the . Drywell Pressure-High Function in order to minimize the . possibility of* fuel damage. Th.e Drywell Pressure--High *Function is directly assumed in the analysis of the (continued) B 3.3-107 .
• Revision No. o BASES
• APPLICABLE* SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UN IT .* 2 ECCS Instrumentation B 3.3.5.1 3.b. Drywell Pressure-High (continued) recirculation line break (Ref. 4). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible to be
• indicative of a LOCA inside primary containment. Four channels* of the Drywell Pressure-High Function are required to be OPERABLE when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. *Refer*to LCO 3.5.1 for the Applicability Bases for the HPCI System. 3.c. Reactor Vessel Water Level-High (Level 8) High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such that there is no danger to the fuel. Therefore, the Level 8 signal is used to trip the HPCI turbine to prevent overflow into the main steam lines (MSLs). The Reactor Vessel Water Level-High (Level 8) Function is assumed to trip the HPCI turbine in the feedwater controller failure transient analysis if HPCI is initiated. Reactor Vessel Water Level--'-High (Level 8) signals for HPCI are initiated from two level transmitters from the wide range water level measurement instrumentation. Both Level 8 signals are required in order to trip the HPCI turbine. This ensures that no single instrument failure can preclude HPCI initiation. The Reactor Vessel Water level-High (Level 8) Allowable Value is chosen to prevent flow from the HPCI System from overflowing into the MSls. Two channels of Reactor Vessel Water Level-High (Level 8) Function are required to be OPERABLE only when HPCI is requ_i red to be OPERABLE. Ref er to LCO 3. 5. l and LCO 3. 5. 2 for HPCI Applicability Bases. (continued) B 3 Revision No. 0

. : . -"*. BASES APPLICABLE _ SAFETY ANALYSES, LCO, and _ APPLICABILITY (continued) PBAPS UNIT 2 3.d. Condensate Storage Tank Level-Low ECCS Instrumentation B 3.3.5.l Low level in the CST indicates the unavailability of an. adequate supply of makeup water from this normal source. Normally the suction valves between HPCI and the CST are open and, upon receiving a HPCI initiation signal, water for HPCI injection would be taken from the CST. However, if the water level in the CST falls below a preselected level, first the suppression pool suction valves automatically open, and then the CST suction valve automatically closes. This ensures that an adequate supply of makeup water is available to the HPCI pump. To prevent losing suction to the pump;' the suction valves are interlocked so that the suppression pool suctfon valves must be open before the CST suction valve automatically closes. The Function is implicitly assumed in the accident and transient analyses (which take credit for HPCI) since the analyses assume that the HPCI source is the suppression pool. --Condensate Storage Tank Level-Low signals are_ initiated from two level switches. The logic is arranged. such that either level switch_can cause the suppression pool suction valves to open and the CST suction valve to close. The Condensate Storage Tank Level-Low Function Allowable Value is high enough to ensure adequate pump suction head while water is being_taken from the -Two channels of_the Condensate Storage Tank tevel::....Low Function are required to be .OPERABLE only when HPCI is to be OPERABLE to *ensure that no single instrument failure .. can preclude HPCI swap to suppression pool source. Ref er to. LCO 3. 5. I for HPC l App li ca bi l i ty Bases. 3 -*suppression* _;High ** Excessi.vely high pool water could result in the _ loads on the suppres'sion pool exceeding design values _should there a-blpwdown': of the reactor vessel pressure through __ -safety/relief valves._ Therefore, signals-indkating -* high suppression pooi water. level are used to transfer the -suction source of HPCI from the CST to the suppression pool to .el imirjate the possib.il i-ty of HPCl continuing to provide* addition_aJ water front a _source outside contajnmenL To .. p*reverit losing suctiolJ to the pump, suction valves are _ .-Jnterl ocked so that_ the suppress_; on pool suet ion valves must be open before-the CST suction valve automatically closes . . ,.* .* ;, . . rrned) -*,. *. ',:*.*

• B 3.3-l09 ** Revision No; o BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY ' . . . . PBAPS .UNIT 2 ECCS Instrumentation B 3.3.5.1 3.e. Suopression Pool Water Level-High {continued) Thfs Function is implicitly assumed in the accident and transient analyses (which take credit for HPCI) since the analyses assume that the HPCI suction source is the suppre*sion pool. Suppression Pool Water Level-High signals are initiated from two level switches. The logic is arranged such that either switch can cause the suppression pool suction valves to openand the CST suction valve to close. The Allowable *value for the Suppression Pool Water Level-High Function is chosen to ensure that HPCI will be aligned for suction from the suppression pool to prevent HPCI from contributing to any further increase in the suppression pool level. Two channels *of Suppression Pool Water Level-High Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI swap to suppression pool source. Refer to LCO 3.5.1 for HPCI Applicability Bases . . *. High.Pressure Coolant Injection Pump Discharge
• Fl ow-Low (Bypass) The minimum flow instrument is provided *to protect the HPCI pump
• frQm overheating when the pump_ is operating at reduced flow. The minimum flow line valve is opened when low flow is sensed, and the valve is automatically closed when the flow rate is protect the pump. The High Pressure Coolant Injection Pump Discharge* Flow-Low Function . is .assumed .to be OPERABLE and capable of closing the minimum flow . valve to ensure that the ECCS fl ow assumed d.uri ng the transients analyzed 'in Reference 4 is m*et. -The core cooling functi or( of *the *.ECCS, with* the sc:ram action of the RPS; ensures that the fuel'peak cladding temperature .remains below the llniits of 10 CFR 50.46. * *
• One: flow*.switch is used to detect the HPCt System's flow. :*The** logic rs*-arranged. such that the* transmitter .* causes.the minimum to open *. The-logic will close_ the valve<)nt:e the closure*setpoint is * . exceeded . -* * * '* *,. (continued) J *** Revision* No. 0 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY -.. :. }BAPS UN IT 2 ECCS Instrumentation B 3.3.5.1 3.f. High Pressure Coolant Iniection Pump Discharge Flow-Low (Bypass) (cbntinued) The High Pressure Coolant tnjection Pump Discharge Flow-Low Allowable Value is high enriugh to ensure that flow rate is sufficient to pr6tect the pump, yet low enough to that the closure of the minimum flow is initiated to allow full flow into the core. One channel is required to be OPERABLE when the HPCI is required to be OPERABLE. Refer to LCO 3.5.1 for HPCI Bases. -Automatic Depressurization System 4.a. 5.a. Reactor Vessel Water Level-Low Low Low (Level 1) Low RPV water level indicates that the capability to_ cool the fuel may be threatened. Should RPV water level d_ecrease too far, fuel damage could result. Therefore, ADS receives one of the signals necessary for initiation from this Function. This actuates the Function 4.h, 5.h The Reactor Vessel Water Level -Low Low Low (Level 1) is -one of the Functions assumed to be OPERABLE and capable of initiating the ADS during the accident analyzed in Reference 4 .. The core cboling of the ECCS, along with the scram of the RPS, ensures that the fuel peak cladding:temperature remains below the limits of -10 CFR 50.46. . . . . . . . . . . . . . Reactor Vessel Water Level-Low Low Low (Level 1) signals are initiated from fbur level that sense the -difference between the pressure due to a constint column of water leg) and the pressure due to the actual water level ( va ri al:il e leg) -in-the vessel. Four channels of Reactor Vessel Water Level-Low Low Low (Level 1) Function required to be OPERABLE only when ADS is required to be OPERABLE to ensure that no single instrument -failure can preclude ADS. initiation. Two input to ADS trip system A, while the other two channels input to ADS trip B. Refer to LCO 3.5.1 for ADS Applicability Bases. The Reactor Vessel_ Water Level -Low Low Low C Level 1) Allowable Value ts chosen to allow time fcir the low pressure core flgoding systemi to initiate and adequate coo_l i ng; --continued B Revision N0 .. _ 78 -*,,,_

-BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued} PBAPS 'UN.IT 2 4.b. 5.b. Drvwell Pressure-High ECCS Instrumentation B 3.3.5.1 High pressure in the drywell could indicate a break in the RCPB. Therefore, ADS receives one of the signals necessary for initiation from this Function in order to minimize the possibility of fuel damage. The Drywell Pressure-High is assumed to be OPERABLE and capable of initiating the ADS during the accidents analyzed in Reference 4. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 C.FR 50.46. Drywell Pressure-High signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be. indicative of a LOCA inside primary containment. Four channels of Drywell Pressure-High Function are only .

• requi.red to be OPERABLE when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A, while the other two channels input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases. 4.c, 5.c. Automatic Depressurization System Initiation Timer * *The purpose of the Automatic Depressurization System Initiation Timer is to delay depressurizat.ion of the reactor *vessel to allow theHPCI System time to maintain reactor vessel water level. Since the rapid depressurization caused by ADS.operation is one of the most severe transients on the . . reactor vessel, its occurrence should be limited. By .. delaying initiation of the ADS Function, the operator is given the chance to monitor the success or failure of the HPCI System to maintain water level, and then to decide
• whether or'not to allow ADS *to initiate, to delay initiation. * . further by recycling the* timer, or to inhibit initiatio_n
• permanently. The Automatic Depressuri zat ion System * *. .* . . . Initiation Timer Function is assumed to be OPERABLE for the accident analysis of Reference 4 that requires ECCS
• initiation and assumes failure of the HPCI System. (continued) B 3 .3-112 Revision No. o -----------

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY . PBAPS. UNIT 2 ECCS Instrumentation B 3.3.5.1. 4.c. Automatic Depressurization System Initiation Timer (continued) There are two Automatic Depressurization System Initiation Timer relays, one in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Initiation Timer is chosen so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling. Two channels of the Automatic Depressurization System Initiation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system B. Refer to LCO 3.5.l for ADS Applicability Bases. 4.d, 5.d. Reactor Vessel Water Level-Low Low Low (Level ll (Permissive} Low reactor water level signals are used as permissives in the ADS trip systems. This ensures after a high drywell pressure signal or a low reactor water level signal (Level 1) is received and the timer times out that a low **reactor water level (Level 1), signal is present to allow the ADS initiation (after a confirmatory Level 4 signal, see Bases for Functions 4.e, 5.e, Reactor Vessel Water Confirmatory Level-Low (Level 4). Reactor Vessel Water Level-Low Low Low (Level 1), signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure doe to the actual water level (variable leg) in the vessel. The Reactor Vessel Water Level-Low Low Low (Level l) Allowable Value is chosen to allow time for the low pressure core flooding system to initiate and provide adequate cooling. Four channels of the Reactor Vessel Water Level-Low Low Low (Level 1) Function are required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A while the other two ch*annels input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases. (continued} .B 3.3-113 Revision No. 0

• .* .< BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (cpntinued) .. .-. '. . ** .. ;. . -PBAPS. UN_IT 2 -ECCS Instrumentation B 3.3.5.1 4.e. 5.e. Reactor Vessel Water Confirmatory Level-Low (Level 4) The Reactor Vesse 1 Water Confirmatory Leve 1-Low (Level 4) Function is used by the ADS only as a confirmatory low water level signal. ADS receives one of the signals necessary for initiation from Reactor Vessel Water Level-Low Low Low (Level I) signals. In order to prevent initiation of ADS due to spurious Level I signals, a Level 4 signal must also be received before ADS initiation commences. Reactor Vessel Water Confirmatory Level-low (Level 4) *signals are initiated from two level transmitters that sense the difference between the pressure due to a constant column of _water (reference leg)_and the pressure due to the actual water level (variable leg) in the vessel. The Allowable Value for Reactor Vessel Water Confirmatory Level-Low . (Level 4) is selected to be above the RPS Level 3 scram Allowable Value for-convenience. Two channels of Reactor Vessel Water Confirmatory Level-Low '(Level 4") are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. One channel input$ to ADS trip system A, while the other channel inputs . to ADS trip system B. Refer to LCO 3*. 5 .1 for ADS Appl icabll ity Bases. 4.f, 5.g. Core Spray and Low Coolant Injection PumpDischarge Pressure-High The PumpD-ischarge signals from the cs and_ LPCl pumps are:used as permissives for ADS initiation, -ind'katirig that iS a source of low pressure cooling water available once ADS has depressurized the vessel. Pump_ Discharge Pressure.;;...:High-is one of the Functions as$umed J:o be <()PERABLE and capable of permitting* ADS *-lni t during the events analyzed in Reference 4 with an -_assumed HPCl failure;;* For these events the ADS --depressurizes so-that the low pressure -ECCS can* perform the core cool i ng-functions. Th is core __ -coo 1 i ng furicfi on of the ECCS; a 1 ong .with the* $Cram _ action of the RPS, --ensures* that the -fuel -peak cladding temperature remafns--Qelow-the li.mits of IP CFR 50.46. --(continued) -B 3 .3-114 .Revision o BASES ECCS Instrumentation B 3.3.5.1 APPLICABLE SAFETY ANALYSES, 4.f, 4.g. 5.f, 5.g. Core Spray and Low Pressure Coolant Injection Pumo Discharge Pressure_..:.High * (continued) Leo, and * . . . . APPLICABILITY* *_<:-(, --_-... . . PBAPS UNIT 2 ::-:. __ Pump discharge pressure signals are initiated from twelve pressure transmitters, two on the discharge side of each of the four LPCI pumps and one on the diScharge side of each CS pump. There are two ADS low pressure ECCS pump permissives in each *trip system. Each of the permissives receives inputs from all four LPCI pumps (different signals for each permissive) and two CS pumps, one from each subsystem (different pumps for each permissive). In order to generate an ADS permissive in one trip system, it is necessary that only one LPCI pump or two CS pumps in proper combination (C or D and A or B) indicate the high discharge pressure condition in each of the two permissives.
• The Pump DiScharge Allowable Value is less than the pump discharge pressure when the pump is operating in a full flow mode and high enough to avoid any condition that results in .a discharge pressure permissive when the CS and LPCI pumps are aligned for. injection and the pumps are not running. The actual operating point of this function is not assumed in any transient or accident analysis. However, this Function is indirectly assumed to operate {in Reference 4) to .provide the ADS permissive to depressurize the RCS to ow the ECCS 1 ow pressure systems to operate.
• Twelve channels of Core Spray and i..ow Pressure Coolant Injection Pump Discharge Pressure-High Function are only to be OPERABLE when the ADS is *required to be OPERABLE to ensure that no sing] e instrument failure can preclude ADS inithtfon *. Four CS channels associated with _CS.pumps A through D and eight LPCI channels associated with LPCI pl.Imps through D are required* for both trip systems.
• Refer to LCD 3. 5 .] . for ADS Appl i cabi li ty Bases. 4.h. *s.h>* Automatic Depressurization* System Low Water *1evel Actuation Timer *-* * * * *
• One of *the. signals required fpr ADS initiation ts Drywell * (>r_essure'."""".lligh *. ** if the event requiring ADS_* . initiiltioir occurs outside the dryweH
• main .. 1 ine * -* break.outside cQntainment), a high drywel l pressure s1gnal * * * .. may *-never be* present.
• Therefore, the Automatic . *. . . Depressurization System low.Water Level Actuation Timer ts used to .. bypass the.*orywell Pressure""."'."High .Function after a .. * (continued) -.*._, ' *: .. -' .. : : *. Revision* No. 0 BASES APPLICABLE SAFETY ANALYSES, LCO, .and APPLICABILITY ACTIONS . . . PBAPS. UNIT 2. ECCS Instrumentation B 3.3.5.1 4.h. 5.h. Automatic Depressurization System Low Water Level Actuation Timer (coritinued) *
• certain time period has elapsed. Operation of the Automatic Depressurization System Low Water Level Actuation Timer Function is assumed in the.accident analysis of Reference 4 that requires ECCS initiation and assumes failure of the HPCI.system. There are four Automatic Depressurization System Low Water Level Actuation Timer relays, two in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Low Water Level Actuation Timer is chosen to ensure that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling. Four channels of the Automatic Depressurization System Low Water Level Actuation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Refer to LCO for ADS Applicability Bases. A Note has been provided to modify the ACTIONS related to ECCS instrumentation .channels. Section 1.3, Completion Times, specifies that once a*condition has been entered, subsequent divisions, subsystems, components, or variables expressed* in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Section L3 also specifies that Required Act1ons of Condition continue to apply for . failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ECCS instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable ECCS instrumentation channel. Required Action A.l directs entry into the appropriate Condition referenced .in Table 3.3.5.1-1. The applicable Condition referenced in the table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides transfer to the subsequent Condition. . (cont ;"nued) . B 3.3-n6 *. Revision No. 0

,:*,., *.*.:.: BASES ACTIONS (continued) PBAPS UNIT Z 8.1, 8.2, and 8.3 ECCS Instrumentation B 3.3.5.1 Required.Actions 8.I and 8.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic initiation capability being lost for the feature(s). Required Action B.I features would be those that are initiated by Functions I.a, I.b, 2.a, and 2.b low pressure ECCS). The Required Action 8.2 system would be HPCI. For Required Action 8.I, redundant automatic initiation capability is lost if (a) two or more Function I.a channels are inoperable and untripped such that both trip systems lose initiation capability, (b) two or more Function 2.a channels are inoperable and untripped such that both trip systems lose initiation capability, (c) two or more Function I.b channels are inoperable and untripped such that both trip systems lose initiation capability, or (d) two or more Function 2.b channels are inoperable.and untripped such that both trip systems lose initiation capability. For lowpressure ECCS, since each inoperable channel would have Required Action B.I applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system of low pressure ECCS and.DGs to be declared inoperable. However, since channels in both associated low pressure ECCS subsystems (e.g., both CS subsystems) are inoperable and untripped, and the Completion* Times started concurrently for the channels in both subsystems, this results in the

• affected portions in the associated.low pressure ECCS and DGs being concurrently declared inoperable. For Action redundant automatic HPCI initiation. capability is lost if two or more Function 3. a or two .. Functio.n 3 .b channels are inoperable and untripped such* that the trip system loses initiation capability. In this . . situation (loss of redunda.nt automatic initiatfon capability)', the 24 hour allowance of Required Action 8.3 is .not appropriate and the HPCI System must. be declared .
• inoperable wjthin I hour. As noted (Note l to Required Action 8.I), Required Action 8.I is only applicable in MODES I, 2, and In MODES 4 and 5, the specific initiation time of the low pressure ECCS is not assumed and the probability of a LOCA is lower. *Thus, a total loss of (continued) B 3.3-117 Revision No. 0 BASES ACTIONS J' '._ .*. .... I I* !*,;,_ .. ***** PBAPS UNIT :z . : * , .. ,. ,, . : ' '.*.--,,. B.l; B.2. and B.3 (cont1nued) ECCS Instrumentation B .3 .3. 5. I initiation*capability for 24 hours (as allowed by Required ._Action is>allowed during MODES 4 and 5. There is no similar Note provided for Required Ac'l;ion B.2 since HPCI instrumentation is not required in MODES 4 and 5; thus, a
• Note is not necessary. -. Notes are also provided (Note 2 to Required Action B.l and . the Note to *Required Action B.2) to delineate whi.ch Required Action is applicable for each Function that requires entry into Condition B if an associated channel is inoperable. This ensures that the proper loss of initiation capability . check is performed *. Required Action B.l (the Required Action for certain inoperable channels in the low pressure ECCS subsystems) is not applicable to Function 2.e, since this Function provides. backup to administrative controls ensuring that operators do not divert LPCI flow from
• injecting into the core when needed *. Thus, a total loss of
• Function 2.e capability for 24 hours is allowed, since the * .. LPCI subsystems remain capable of performing their intended ** functio*n *. * *
• The Completion Time is intended *to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock.11 For Required Action 8.1, the Completion Time only begins upon discovery that*a redundant feature in the same system both CS subsystems) cannot be automatically initiated due to-inoperable, untrippedchannels within*the same FunctiOn -as described in the paragraph above. For Required Ac;tio.ri B.2, the Completion Time only begins upon discovery .that the HPCI cannot be automatically initiated due to two inoperable*, untripped channels for the associated *Function_ in the same trip system. The I hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
• Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an _ allowable out of service time of 24 hours has been shown to *. be acceptable (Ref. 5) to permit res to rat i ori . of any .*
• inoperable channel to OPERABLE status. ** If the i noperab 1 e channel cannot be restored to.OPERABLE status within the -(continued) . B 3.3-118 Revision No. 0 . :_ :

BASES ACTIONS , .. *-. :* ." '-= ... -'* . PBAPS UNIT 2 . B.l, and B.3 (continued) ECCS Instrumentation B 3.3.5.1 ' ' allowable out of service time, the channel must be placed in the tripped condition per Required Action B.3. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (.e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken. C.l and C.2 ' ' ' Required Action C.l is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same ,function result in redundant automatic initiation capability being lost for the feature(s). Required Action C.l features would be those that are initiated by Functions 1. c, 1. e, 1. f, 2. c, 2. d, and 2. f ( i . e , low pressure ECCS). Redundant automatic initiation capability is lost if either (a) two or more Function l.c channels are inoperabl_e in the same trip system such that the trip system loses initiation capability, (b) *two or more Function l.e .*channels are inoperable affecting CS .pumps in different subsystems, (c) two or more Function 1. f channels are inoperable affecting.CS pumps in different subsystems, (d)* , two or more Funetfon 2.c channels, are inoperable in the same ** .. trip system such that.the trip system lpses initiation

• capabiljty,* (e) 1;wo or more Function 2.d channels are* inoperable.in the, same trip system sµch that the ,trip system
• loses inlt i at ion capabi l i ty,. or {f) three or more * *Function. f .channels. are inoperable.
• In this situation**, . (loss of redundant automatic, initi,ation capability),
• 24 bout *a 11 owance . of Requ*i red Action C 2 is not appropriate . and the featur.e.tsJ with the inoperable
• channels ..
• inust be inoperable within l hour. :Since each
• would have Required #.\ction-C_ . .l applied_--__ ,,separately-(refer to ACTIONS Note), each inoperable .channel would only require the affected portion of the associated,* ... * *system to be dee la red i_noperab 1 e However, s i nee -channels
• for both low pressure ECCS subsystems are inoperable . *.
• both:CS sµbsystems)-,. and the Completion Times started * **;ccmcurrently for. the channels, in, both subsystems, ,. .. ' results in the._affected portions in both _subsystems being :' __ *.*: .* . (tontlnued) .. ; * .. ** .-_ ;* .. **-*' e* .3.3-119: ' * .. Revision No. 0 * '*

BASES . ACTIONS PBAPS .UNIT 2 .. .* *.* C.l and C.2 (continued) ECCS Instrumentation B 3.3.5.l declared inoperable .. For Furictions 1.c, l.e, l.f, 2.c, 2.d, and 2.f, the affected portions are the associated low pressure ECCS pumps. As noted (Note 1), Required Action C.l is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the ECCS is not assumed and the probability of a LOCA is lower. Thus,*a total loss of automatic initiation capability for *24 hours (as allowed by Required Action C.2) is allowed during MODES 4 and 5. Note 2 states that Required Action C.1 is only applicable for Functions l.c, l.e, l.f, 2.c, 2.d, and 2.L Required Action C.l is not applicable to Function 3.c (which also requires entry into. this Condition if a channel in this is inoperable), since the loss of one channel results* i.n a loss of the Function (two-out-of-two logic). This loss was considered.during the development of . Reference 5 andconsidered acceptable for the 24 hours allowed. by Required Action C.2. ' . *. ' The Completion Time is intended to allow the operator time. to evaluate and repair any* discovered inoperabil ities. This*** Completion Time also allows for an exception to the normal . "time zero" for beginning the allowed outage time "clock." For Required.Action the*Completion Tiine only begins upon. dfscovery that the same feature in both subsystems both. CS subsystems] cannot be autpmatically initiated dµe to inoperable channels within the same Function as

• described in'the paragraph above. The I :hour Completion Time from* discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.. * *
• Because of *thediver$*fty. of sensors available .to provide . 'initiation signals and' tbe redundancy of the ECCS design, an . allowable out of service time of 24 hours has been shown to. .
• acceptable 5) to . permit restoration of any . * .
• channel to OPERABLE status. l f the i n()perab le .. *channel cannot be restored to OPERABLLstatus within* the .. **allowable out of service time, Condition H must be entered its Requfred, Action taken.* The Required Actions do. not
• allow.placing the channel in trip .since* this action would *. either* cause the initiation or .it. would. IJOt: necessarily '*.*
• a safe state for the chanriel in all events. * * .-.. ,. (continued) . *._ .-.. ;--. . * * *s 3.3*J2Q **RevJsionNo. O**

,***. BASES ACTIONS (continued) ** .. UNIT 2 D.l. D.2.1. and D.2.2 ECCS Instrumentation B 3.3.5.l Required Action 0.1 is intended to ensu}"e that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic component initiation capability for the HPCI System. Automatic component initiation capability is lost if two Function 3.d channels or two Function 3.e channels are inoperable and untripped. Iri this situation (loss .of automatic .suction swap), the 24 hour allowance* of Required Actions D.2.1 and 0.2.2 is not appropriate and the HPCI System must be declared inoperable within I hour after discovery of loss of HPCl initiation capability *. As noted, Required Action D.l is only applicable if the HPCI pump suction is not aligned to the suppression pool, since, if aligned, the Function is already performed. . . The Completion Time .is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This ConipletiOn Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action D.l,.the Completion Time only begins upon discovery that the HPCI System cannot be automatically aligned to the suppression pool due to two inoperable, untripped channels iii the same Function. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. Because of the diversity of sensors available to provide initiation signals and the redundancy of the

• ECCS design, an
• allowable out o.f service time of 24 hours has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be. restored to OPERABLE status within the *.allowable out of service time, the channel must be placed in the tripped condition per Required Action D.2.1 or the suction source must be aligned to the suppression pool per Re.quired Action D.2.2. Placing the inoperable channel in trip performs the intended-function of the channel (shifting the suction source to the suppression pool). Performance of either of these two Required Actions will allow operation to continue. If Required Action D.2.1 or D.2.2 is performed,* measures*should be taken to ensure that the HPCI System (continued)
• Revision o * * .: '.:

BASES ACTIONS *-.. -* .. *.-: . . . . .. -PBAPS UN.IT-2 D.l. D.2.1. and D.2*.2 (continued) ECCS Instrumentation B 3.3.5.1 piping remains filled with water. Alternately, if it is not desired to perform Required Actions D.2.1 and D.2.2 (e.g., as in the case where shifting the suction source could drain down the HPCI suction piping), Condition H must be entered and its Required Action taken. E. l and E.2 Required Action E.l is intended to ensure that appropriate

• actions are taken if multiple, inoperable channels'within the Core Spray and Low Pressure Coolant Injection Pump, Discharge Flow -low (Bypass) Functions result in redµndant automatic initiation capability being 1 ost for the . feature(s). For* Required Action E.l, the features would be those that are initiated by Functions l.d and 2.g (e.g., low
• pressure ECCS) *.
• Redundant automatic. initiation capability is lost if (a) two or more Function l.d channels are inoperable affecting CS pumps in different subsystems or (b) three or mbre function 2.g channels are inoperable. . Since each inoperable channel would have Required Action E.l applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected low pressure _ECCS_. pump to be declared inoperable. However, since channels for .
• more than one 1 ow pressure ECCS pump are i noperab 1 e, and the
• Completion Times started y for the channe 1 s of the low pressure ECCS pumps, this results in the affected
• low _pressure* ECCS pumps being concurrently* declared , inoperable. * : In this situation (loss of redundant automatic initiation capabi 1 i ty) , the 7 day allowance of Required Action E. 2 is **not appropriate andthe associated with each .. illoperab 1 e channel must be dee 1 ared i noperab 1 e within . l
• As noted (Note J to Required Action E. l), Required . Act i on E. l i s only app l l¢ab 1 e in MODES l, 2, and 3
• In MODES 4 and 5, the specific initiation time of the ECC.S is .**. ne>t assumed and the probability of a LOCA
• is lower. Thus, a
• t9tal loss of initiation capability for 7 days (as allowed *by Required Action E.2) is allowed during MODES 4 and 5. A . Note is also provided (Note 2 to Required Action E.1) to _ _ delineate that Required 'Action E.l is only applicable to low (continued l B 3.3-122 *Revision No. o BASES ACTIONS PBAPS UNIT 2 E.l and E.2 (continued) ECCS Instrumentation B 3.3.5.1 pressure ECCS Functions. Required Action E.l is not applicable to HPCI Function 3.f since the loss of one channel results in a loss of function (one-out-of-one logic). This loss was considered during the development of Reference 5 and considered acceptable for the 7 days allowed . by Required Action E.2. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal time zero" for beginning the allowed outage time "clock. 11 For Required Action E.l, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels. If the instrumentation that controls the pump minimum flow valve is inoperable, such that the valve will not automatically open, extended pump operation with no injection path available could lead to pump .overheating and failure. If there were a failure of the instrumentation, such that the valve would not automatically close, a portion of the pump flow could be diverted from the reactor vessel injection path, causing insufficient core cooling. These consequences can be averted by the operator's manual control of the valve, which would be adequate to maintain ECCS pump protection and required flow. Furthermore; other ECCS pumps would be sufficient to complete the assumed safety function if no additional single failure were to occur. The 7 day Completion Time of Required Action E.2 to restore the inoperable channel to OPERABLE status is reasonable based on the remaining capability of the associated ECCS subsystems, the redundancy available in the ECCS design, and the low probability of a OBA occurring during the allowed out of .service time. If the inoperable channel cannot' be restored to OPERABLE status within the allowable out of service time, Condition H must be entered and its Required Action taken. The Required Actions do not allow placing the channel ill trip since this action would not necessarily result in a safe state for the channel in all events. (continued) B 3.3-123 Revision No. 0 I_** I BASES ACTIONS (continued) '-*.* -* .PBAPS UNIJ _2 F.1 and F.2 ECCS Instrumentation B 3.3.5.1 Action F.1 is to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within similar ADS trip system A and B Functions result in redundant automatic initiation capability being lost for the ADS. For example, redundant automatic -initiation capability is lost if either (a) one or more Functiori 4.a channel and one or more Function-5_a channel are inoperable and untripped, (b) one or more Function 4.b channel and one or more Function 5.b channel are inoperable and untripped, (c) one or more Function 4.d channel and one or more 5.d are inoperable and untripped, or (d) one Function 4.e channel and one Function 5.e channel are and untripped: In this situation Closs of automatic initiation capability), the 96 hour or 8 day allowance, as applicable, of Required Action F.2 is not appropriate and all ADS valves must be declared inoperable within.1 hour after discovery of loss of ADS initiation capability. . . The Completion Time is to allow the operator time to and repair any discovered inoperabilities. This Completion Time als6 for an exception to the zero" for beginhing lhe al1owed outage time "clock." For Requited-Action CompJetioh Time only begins _upon di$covery that the Abs cannot* be automatically initiated due to inoperable-, untripped channels within ADS trip system Functions is described in paragraph above.-The 1 hour Completion time from discovery of Joss of initiation_capabilityjs acceptable because it mihi mi zes *risk-while allowing time for restoration or tri ppin'g of channels'. -----6f .the .diversi t; of' sehsors available to prov:ide --*initiation: si gna*ls *and the redundancy-of theICCS design, an allowab-le out of service time of 8 days has. been. shown,to be ,. C)c;_ceptablEt tti-pefrri{t r(;!'stpratfon of ariy .inoperable . ch*annel to>OPERABLE tatus if both HPCI and RCIC are OPERABLE:,-_--.If.either HPCI o:r RCIC _is inoperaole, the time is shortened. to 96 hour's: -If the status of HPCI or RCIC . change$-such that th-e Compieti Time changes.from 8 days to 96 hours, .fhe* 96 *hours.begins upon di-scovery of HPC I or RCTC __ 'jnoperab1.1Hy) However, the.total-time for an inoperable;.* untripped c"hanriel cannot exceed 8 If the status of .. -.: .-(continued) __ *,---B N6. 58:

BASES ACTIONS *, .* ** .. _. *; .. *. :_ PBAPS. UN IT 2 . -F.1 and F.2 (continued} ECCS Instrumentation B 3.3.5.1 HPCI or RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zer6 for beginning the 8 day "clock" begins upon discovery of the inoperable, untri pped channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action F.2,. Placing the inoperable in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and to continue. Alternately, if it is :no£ desired to place the channel in trip (e.g., as in the tase where placing the inoperable channel in trip would resDlt in an initiation), Condition H must be entered and its Require*d Action taken. G.l and G.2 Required Action G.1 is .intended to ensure th_at appropriate actipns are taken if mult1ple, inoperable channels within ADS trip system result in automatic . capability being lost for the ADS. For example, automatic initiation capability is lost if efther Ca) one Function and one Functiori channel are inoperable, Cb) a tombinati6n of Function 4.f, 4.g, 5.f, and 5.g are irioperable such associated with five or lriw pressure ECCS pumps are i nope ra b l e , o r ( c ) on e oT mo re Fun ct i o n 4 ._ h ch a n n e l s a n d on e more Function 5.h are inoperable: -rn*_thi.s*s1tuation_ (l6ss '6f automatic ini.tiation capability), -the 96-h_our or 8 day' a_l l9wance; as.applicable, of Acti on_ is not *app'ropriate:*and all _ADS valves must be de cl a re_d inoperable *within l hour after discovery of loss of ADS initiation capability:.* -' ,* *. The is i'ntended to .allow th_e operator time to evaiuate and :repair any discovered i noperabi l i ties.* ,This Completfon Time also *al-lows* for an to the normal *itrme: ze-ro"--for*beg1nning the' allowed-outage time .clock." For Action G:1, the*complet-lon Time only begins Cconti nued) _: . *-** .. *. . *. Revisfon No. 83 I . ' I I I 1.-** BASES ACTIONS -. ,....;* . . UNIT: 2 . G.l and G.2 (continued) ECCS Instrumentation B 3.3.5.1 upon discovery that the ADS' cannot be automatically initiated due to inoperable channels within similar ADS trip system Functions as described in the paragraph above *.. *The* I hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE (Required Action G.2). If either HPCI or RCIC is inoperable, the ti me shortens to 96 hours.. If the status of HPCI or RCIC changes such that the. Completion Time changes from 8 days to 96_ hours, the 96 hours beg*i ns upon discovery of HPCI or RCIC inoperabil ity.

• However, the total time for an inoperable channel cannot exceed 8 days. If the status of HPCI or.RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zero" for . beginning the 8 day ."clock" begins upon discovery of the inoperable channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time; Condition H must be entered and its Required Action taken.* The Required Actions do not allow placing the channel in* trip since this action would not necessarily result in a safe state for the channel in all events. H. l * .. . . -. . With-any Required Action and associated Completion Time not met, the associated feature(s) may be incapable of
• performing the intended function, and the supported feature(s) associated with inoperable untripped channels must be declared inoperable immediately. (continued) ; .. * . . 83.3-126* O -

ECCS Instrumentation B 3.3.5.1 BASES (continued) SURVEILLANCE REQUIREMENTS -';-, As noted in the beginning of the SRs, the SRs for each ECCS instrumentation Function-are found in the SRs column of Table 3.3.5.1-1. The Surveillances are modified by a Note to indicate that a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours as follows: (a) for Functions 3.c and 3.f; and Cb) for Functions other than 3.c and 3.f provided the associated Function or the .redundant Function maintains .ECCS initiation capability. Upon of the Surveillance, or expiration of the 6 hour allowance, the channel must be. returned to OPERABLE status or .the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 5) assumption of the average time requi r_ed to perform channel survei 11 ance. That . analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the ECCS will when

• SR 3.3.5.1.1 Performance of the CHANNEL CHECK ensures that a gross of instrumentation has not occurred. A CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It ts* based on the that instrument channels monitoring _.the same parameter should read the value. *Significant deviations between the instrument channels could be an jndicati'on of excessive instrument drift in one of the , channels or something even more serious. A CKANNEL CHECK . . _guarantees that w:idetected outright channel failure is.
• l i mite d ; t h us ;-it i s key t o v e r lf y i n g t he ih s t r um en t a t i ci n I continues to opera:te properly between .each CHANNEL CA_LIBRAT ION. -. Agreement .c:riteri a* are determined_ by the plant staff, based< on a cbmbination of the* channel instrument uncerta1nties, including.indication and*-readability; If a channel is outside the criferia, it may be an indication that the _instrument has drifted outside its limit. continued B 3.3-127. Revision No. 86 BASES SURVEILLANCE REQUIREMENTS < **
• PBAPS UN]T 2 ECCS Instrumentation B 3.3.5.1 SR 3.3.5.1.1 (continued) The Frequency is controlled under the Surveillance Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated w1th the channels required by the LCO. SR 3.3.5.1.2 A CHANNEL FUNCTIONAL TEST is performed each required channel to ensure that the .channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 3.3.5.1.3 and SR 3.3.5.1.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured within the necessary .range and CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive with the assumptions of the current plant specific setpoint methodology. The Frequency is controlled under the Surveillance frequency Control Program. continued B 3.3-128 Revision No. 86

_.:,._ BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES .. , ,_,-:. -.. PBAPS UNH .2 SR 3.3.5.1.5 ECCS Instrumentation B 3.3.5.1 The LOGIC SYSTEM FUNCTJONAL TEST demonstrates the OPERABILITY of the initiation logic for a specific channel. system.functional testing performed in LCD 3.5.1, LCD 3.5.2, LCD 3.8.1, and LCD 3.8.2 overlaps this Surveillance to complete testing of the assumed safety function. The Frequency is controlled under the Survei 1.1 ance Frequency Control Program. 1. UFSAR, Sectiori 2. UFSAR, Section 7.4; 3. UFSAR, .Chapter 14. 4. NEDC-32163-P, "Peach Bottom Atomic Power Station Units 2 3, Loss-of-Coolant: Accident Januafy 1993.. . 5. "BWR Owners' Group Technical Specificaii6n Improvement Analyses for ECCS Actuation Instrumentation, . Pa rt 2, December. 1988. . . ' . . . -. . .*.,.;.-:.: -' **-.. -._*, -. .. '. --' .. --* : '*,_.* '*, . , .... ' .. --,: B 3 .. 3 -12 9 * .. ' . Re.vision No. 86. RCIC System Instrumentation B 3.3.5.2 B 3.3 INSTRUMENTATION B 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation BASES BACKGROUND PBAPS UNIT 2 The purpose of the RCIC System instrumentation is to initiate actions. to ensure adequate core cooling when the vessel is isolated from its primary heat sink (the main condenser) and normal coolant makeup flow from the* *Reactor Feedwater System is insufficient or unavailable, such that RCIC System initiation occurs and maintains sufficient reactor water level such that an initiat.ion of the low pressure Emergency Core Cooling Systems (ECCS) pumps does not occur. A more complete discussion of RCIC System operation .is provided in the Bases of LCO 3.5.3, "RCIC System." The.RCIC System may be initiated by automatic means. Automatic initiation occurs for conditions of Reactor.Vessel . Water Level-Low Low (Level 2). The variable is monitored by four. transmitters that are connected to four pressure compensation instruments.* The outputs of the pressure compensation .instruments are connected to relays whose contacts*. a*re arranged in a one-out-of-two taken twice logic arrangement. Once initiated, .the RCIC logic seals in and can be reset by the only when the reactor vessel . water level signals have. c.leared.

• The RCIC test line isolation valve is closed on a RCIC
• initiat1on signal to allow full *system flow and maintain* primary containment isolated in the event RCIC is not * *opera:ting. . . . . . . . The RCIC>System also monftors.the water level in the condensate storage tank (CST} since this is the initial . source of water for operation. Reactor grade water in the CST is the normal source.
• Upon receipt_ 'of a RCIC .. initicitio11 signal, the CST suction valve i.s automatically signaled to open (it *is. riormally in -the open position) unless pump suction from *the_ suppression pool. valve.s is : If the water level in the* CST falls below if *
• preselected-level, first .the. suppression pool suction valves . automatically open, and then the CST suction valve . *-*automatically Two level. switches are used *to detect low water level in-the CST. Either switch can cause the . * * * *suppression pool suction valves to open. : The opening of the. <cont iriued l 8.3.3-130 Revision No. O I I BASES BACKGROUND (continued} APPLICABLE SAFETY ANALYSES, LCO; and APPLICABILITY . . PBAPS ;UNIT 2 . -*'*.-. RCIC System Instrumentation B 3.3.5.2 suppression pool suction valves causes tne CST suction valve to close. *This prevents losing suction t.o. the pump when automatically transferring suction from the CST to the suppression pool on low CST level. The RCIC System makeup water to the reactor until the reactor vessel water level reaches the high water level (Level BJ.setting (two-out-of-two logic}, at which time the RCIC steam supply valve closes. The RCIC System restarts if vessel level again drops to the low level initiation point (Level 2). The function of the RCIC System is to respond to transient events by producing makeup coolant to the reactor. The RCIC System is not an Engineered Safeguard System and no credit is taken in the safety analyses for RCIC System operation. Based on its contribution to the reduction of overall plant risk, however, the system, *and therefore its instrumentation meets Criterion 4 of NRC Policy Statement. The OPERABILITY of the RCIC System instrumentation is dependent.upon the OPERABILITY of*the individual
• instrumentation channel Functions specified in Table Each Function must have a required number *of OPERABLE channels-with their setpoints within the specffied Allowable Values, where appropriate. A channel is inoperable if. its actual trip setting is not within its required Allowable Value.. The actual setpoint is cal consistent with applicable setpoint methodology assumptions; Allowable Values are specified for each RCIC System instrumentation Function specified in the Table. Trip
• setpohlts are specified in the setpoint calculations. The setpoints are selected to ensure that the settings do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting less conservative .than the trip setpoint, but within its Allowable Value, is
• acceptable. *Each Allowable Value specified accounts for instrument uncertainties appropriate to the Function. These uncertainties are described in the setpoint methodology. (continued) B *3 .3-131 **.* .

',, *.-BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS-UNIT 2 RCIC System Instrumentation B 3.3.5.2 The individual Functions are required to be OPERABLE in MODE 1, and in MODES 2 and 3 with reactor*steam dome pressure > 150 psig since this is when RCIC is required to be OPERABLE. (Refer to LCO 3.5.3 for Applicability Bases for the RCIC System.) The specific Applicable Safety Analyses, LCO, and App-licability discussions are listed below on a Function by Function basis. . . . *e 3.3-132 Revision 0 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) . PBAPS UN IT 2 RCIC System Instrumentation B 3.3.5.2 2. Reactor Vessel Water (Level 8) High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such. that there is no . danger to the fuel. Therefore, the Level 8 signal is used to close the RCIC steam supply valve to prevent overflow into the main steam lines (HSLs). Reactor Vessel Water (level 8) signals for RCIC are initiated from four level transmitters, which sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. These four level transmitters are connected to two pressure compensation instruments (channels).

• The Reactor Vessel Water (Level 8) Allowable Value is high enough to preclude isolating the injection valve of the RCIC during normal operation, yet low enough to trip the RCIC System prior to water overflowing into the MSLs. Two channels of Reactor Vessel Water (Level 8) Function are available and are required to be OPERABLE when
• RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC initiation. Refer to .LCO 3.5.3 for RCIC Applicability Bases. 3. Condensate Storage Tank Low level in the CST indicates the unavailability of an adequate supply of makeup water from this normal source. Normally, the suction valve between the RCIC pump and the CST is open and, upon receiving a RCIC initiation signal, water for RCIC injection would be taken from the CST. However, if the water level in the CST falls below a preselected level, first the suppression pool suction valves automatically open, and then the CST suction valve automatically closes. This ensures that an adequate supply of makeup water is available to the RCIC pump. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction valves must be open before the CST suction valve automatically closes. (continued) B 3.3-133 Revision No. O

• .. BASES APPLICABLE . SAFETY ANALYSES, LCO, and APPLICABILITY ACTIONS _ .. _.. RCIC System Instrumentation B 3.3.5.2 3. Condensate Storage Tank Level-Low (continued) Two level switches .are used to detect low water level in the CST. The Condensate Storage Tank Level -Low Function Allowable Value is set high enough to ensure adequate pump suction head whil_e water is being taken from the CST. Two channels of the CST Function are available and are required to be OPERABLE when RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC swap to suppression pool source. Refer to LCO 3.5.3 for RCIC Applicability Bases. A Note has provided to modify the ACTIONS related to RCIC System instrumentation 'channels. Section 1.3, Completion Times, specifies that once a Condition has been entered; subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. *Section 1.3 also specifies that Required Act.ions of the Condition continue. to apply for each additional failure, w*ith Completion Times based on initial entry into the Condition. However, the Required Actions_ for .*inoperable RCIC System instrumentation* channels provide appropriate compensatory measures for . *separate inoperable channels-.. As such, a Note _has provided that allows separate Condifion entry for each inoperable RCIC System instrumentation channel. * * * -A.1 Requfred Action A'.*l* d.itects entry into the appropriate -_ Coilditton referenced in Table The applicable _Condition refer:enced in the .is Function dependertL *

• Each t,ime a channel *;s discovered to be inoperable, . . Conditfon.A is *entere(l-for that channel. arid provides for *
• transfer to ihe appropriate** Condition. (continl.ledl ._ *. : : ..... . ' . . PBAPS . UNIT 2 . B 3.3-1_34-: Revision NcL 0
• f ** ** ** ,.>" i, . __ .;

I [ .. :. BASES ACTIONS. " PBAPS :2' B.1 and B.2 RCIC System Instrumentation B 3.3.5.2 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels.within the same Function result in a complete loss of automatic initiation capability for the RCIC System. In this case, automatic initiation capability. is lost if two Function 1 channels in the same trip sys-,:em are inoperable and untripped. In this situation (loss of automatic initiation capability), the 24 hour allowance of Required Action B.2 is not appropriate, and the RCICSystem must be declared inoperable within l hour after discovery of loss of RCIC initiation capability. The Completion Time .is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal *"time i.ero" for beginning the allowed outage time "clock.11 For Required Action 8.1, the Completion Time only begins upon discovery that the RCIC System cannot be automatically initi.ated due to two or more inoperable, untripped Reactor Vessel Water Level-Low Low (Level 2) channels such that the trip system loses initiation capability.* The 1 hour Completion Time from discoveryof loss of initiation capability is acceptable because it minimizes risk while allowing_ time for restoration or tripping of channels .. Becau.se the redundancy of* avail:able to provide initiation signals and the' fact that the RCIC System is not assumed in .any accident or transient analysis, an allowable out *of service time of 24 hours has been shown to be * (Ref. l) to permit-.* restoration -of_ any inoperable channel to OPERABLE status. If the i noperab 1 e channe 1 . cannot be restored.to OPERABLE status within the allowable out of service time, the channel must be placed'in-the tripped condition per Required Action B.2. Placing the .* inoperal::fle channel in trip *would conservatively compensate for the-*inoperability, *restore capabllity**to accommodate a single failure, _and allow operation to continue. . Al tern ate l y, if it is not desired to place-the char,me l in trip {e.g.,. as .in the case where placing the inoperable channel-in trip would result in an initiation), Condition E must be entered and. its. *Required Action taken. ,B 3 -Revision No. o BASES RCIC System Instrumentation B 3.3.5.2 ACTIONS C.1 (continued) A risk based analysis was. performed and determined that an allowable out of service time of 24 (Ref. 1) is acceptable to permit restoration of any inoperable channel to OPERABLE status (Required Action C.1). A Required Action (similar to Required Action 8.1) limiting the allowable out of service time, if a loss of automatic RCIC initiation capability exists, is not required. This Condition applies to the Reactor Vessel Water (Level 8) Function whose logic is arranged such that any inoperable channel will result in a loss of automatic RCIC initiation

• capability (closure of the RCIC steam supply valve). As stated above, this loss of automatic RCIC initiation capability was analyzed and determined to be acceptable. The. Required Action does not allow placing a channel in trip since this action would not necessarily result in a safe state for the channel in all events. 0.1. D.2.1. and D.2.2 Required ActionD.1 is intended to ensure that appropriate. actions are taken if multiple, inoperable, untripped channels w.ithin the same Function result in automatic component initiation.capability being lost for the feature(s). For Required Action D.1, the RCIC System is the only associated feature. In this case, automatic initiation capability is lost *if two Function 3 channels are inoperable and untripped. In this situation (loss of automatic suction swap), the.24 hour allowance of Required Actions D.2.1 and .* 2 ls only appropriate after Action D.1 has been performed. Action requires that the RCIC System be declared inoperable within 1 hour from discovery of loss of RCIC initiation capability.
• As noted, Required Action D .1 is only applicable if the RCIC pump suction is not aligned to the suppression pool since, if alignedi the Function is performed. (continued) ' . . . . B
• Revision .No. :o BASES ACTIONS PBAPS UNIT 2 RCIC System Instrumentation B 3.3.5.2 0.1. D.2.1. and 0.2.2 (continued) Tbe Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action 0.1, the Completion Time only begins upon discovery that the RCIC System cannot be automatically aligned to the suppression pool due to two inoperable, untripped channels in the same Function. The 1 hour. Completion Time from discovery of loss of initiation . capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. Because the RCIC System is not assumed in any accident or transient analysis, an allowable out of service time of 24 hours has been shown.to be acceptable (Ref. I) to permit.
• restoration of an.Y inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE *status .within the allowable out of service time, the channel must be placed in the tripped condition per Required Action 0.2.1, which performs the intended function of the channel. Alternatively, Required Action D.2.2 allows the manual alignment of the RCIC suction to the suppression pool, which also performs the intended function. If . Required Action D.2.1 is performed, measures should be taken to ensure that the RCIC System piping remCiins
• filled with water. If it is not desired t.o perform Required. Actions D.2.1 and D.2.2 (e.g.,. as in the case where shifting . the suction source could drain down the RCIC suction. *.. . * *** Condition E must be entered and its Required Action . taken. * *
• LI . With any Required Actfori and associated Completion Time not* met, the RCIC System may be incapable of performing the i.ntended function, and the RCIC System niust be declared inoperable ** (conttnued) ., ..
• B 3.3-137 Revision No. o I .. .... ** BASES (continued) SU RV EI LLAN CE REQUIREMENTS RCIC System Instrumentation B 3.3.5.2 As noted in the beginning of the SRs, the SRs for each RCIC System instrumentation Function are found in the SRs column of Table 3.3.5.2-1. The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Function 2 and (b) for up to 6 hours for Functioris 1 and 3, provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Acti.ons taken. This Note is based on the reliability analysis (Ref. 1) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary. SR 3.3.5.2.1 .Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred .. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a parameter on other similar channels. It is on the that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit. continued B 3. 3-138 Revision No. 86

.* __ , BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT *2 SR 3.3.5.2.1 (continued) RCIC System Instrumentation B 3.3.5.2 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO. SR 3.3.5.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the function .. Any setpoint adjustment shall consistent with the assumptions of the current plant specific setpoint methodology. The Frequency is controlled under the Frequency Control Program. SR 3.3.5.2.3 . . ' A is a complete check of the instrument loop ..

• Thit channel within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel * .ta accciunt for drifts between *cal i brati oris, consistent* wi'th the pl ant specific set point mettiodb-logy. ** * * **-. -Survei l{ance Frequency .is co_fitrol led under the Su rve i 11 a nee Frequency C-ont ro l Program. SR-::-_,3. 3 .:5 .:2. 4 :.::-,,:/*. -*-_* .... . Jbe SYSTEM TEST. t.he . ,* .* .. ' OPERABILITY 6f the required ini,tiationlogic:for.a specific channeJ: The .system* functional testirig performed in -LCO 3.5:3 overlaps this Surve:illance. to pro.vide complete* __ oJ'the ' -, * ... ,._ * *c continued) . . ' *' .---------.. '.: _.* .. * -,* -., .. *, .-. , . . **f: B 3. 3-139 **
• Revision No. 86 . . .. .* 1* . I I --. .BASES SURVEILLANCE REQUIREMENTS REFERENCES ..... :**. :-_** SR 3.3.5.2.4 (continued) RCIC System Instrumentation B 3.3.5.2 The Surveillance Frequency is controlled under the -Surveillance Frequency Control Program. 1. GENE-770-06-2, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service T1mes for Selected Instrumentation Technical Specifications," February 1991. ' .. -. . -, .,",. .,, .:' ._,_ .*:* ... *Revision No. 86

_Primary Containment Isolation Instrumentation B 3.3.6.1 B 3.3 INSTRUMENTATION B 3.3.6.1 Primary Containment Isolation Instrumentation BASES BACKGROUND -PBAPS UNIT_ 2 The primary containment isolation instrumentation automatically initiates of *appropriate primary isblation valves CPCIVs). The function of PCIVi, in combination with other_accident mitigation is to limit fissi6n product release and following postulated Design Basis Accidents CDBAs). Primary containment within the time limits specified fbr those isolation valves designed to close automatically ensures that the of radioactive material. to the *environment will be consistent the used in the analyses for a OBA.

• The isolation instrumentation includes the sensors, relays, and switches that are to cause initiation of primary containment and reactor coolant pressure boundary (RCPB) isolation. channels include equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates,* which then _outputs a primary containment isolation signal to the logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the i sol ati on l ogi.cs are (a) reactor vessel water ,l_evel, Cb) reactor pressure, (c) main steam line (MSL) flow measurement, (d) (deleted), (e) main steam line pressure, (f) drywell pressure, (g) high pressure
• coolant injection CHPCI) and reactor core isolation cooling -(RCIC) steam line flow; (h) HPCI and RCIC steam line pressure,-Ci) reactor water cleanup (RWCU) flow, (j) Standby Liquid Control (SLC).System initiation, (k) area ambient -temperatures,-(1) reattor building ventilation and refueling floor ventilation exhaust ridiation, and Cm) main stack radiation. Redundant sensor input signals from each parameter are provided for initiati_on of isolation. containment isolation instrumentation has inputs to the trip logic of the isolation functions listed below. . --B 3. 3-141 Revision No. 134 I BASES BACKGROUND (continued) . **. .. * ... -.-:. PBAPS UNIT 2 Primary Containment Isolation Instrumentation B 3.3.6.1 1. Main Steam Line Isolation Most MSL Isolation runctions receive inputs from four channels. The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of the Group I isolation valves (MSIVs and MSL drains, MSL sample lines, and recirculation loop sample line valves). To initiate a Group I isolation, both trip systems must be tripped. The exceptions to this arrangement are the Main Steam Line Flow-High: Function and.Turbine Building Main Steam Tunnel Temperature-High Functions. The Main Steam Line Flow-High Function uses 16 flow channels, four for each steam line. One channel from each *steam l,ine inputs to one of the four trip strings. Two trip strings make up each trip system and both trip systems must trip to cause an MSL isolation. Each trip string has :eourinputs (one per MSL), any one of which will trip the trip string. The trip systems are arranged in a taken twice This is effectively a taken twice, logic to initiate a Group I isolation. *The Turbine Build.i,ng Main Steam Tunnel Temperature-High Function receives inputs from twelve . Channels I .. fOUr . Channels at each Of the three different *. aiong, the stea,m line. High temperature on ahy channel is not r_elated to a MSL. The channeis are arranged ih' a 6ne-c::mt-o.f...:two *taken twice logic for* each loc;atiorL . 2 . Primary. Containment Isolation.* Most Primary Containrnent.Isolation'.Functions receive ;Lnputs from .four The outputs from these channels are arranged .in* a taken twice *logic. of :i-hboard .and 'oµtboarc:L p.dmary isolat_ion valves *.when trip* systems are in ... , . .. :'The :to thifl arrangement' 'is the Main_ Stack Monifor Radiation:_ High function. This Function' has t'wo channels, ' 'whose are in two trip systems which use a logic*. *Each* trip system isolates one valve . pe*r ,penetration. . The Main Stack Mbhi tor
• will.' isolate. ve'nt and purge valves
• than t.wo .*inches in dl.aineter durin.g_ corttainment
• pu_rging (Ref. 2) , * ** .. ' , ..* The .valves *isolated by .each of' the Primary Containment .isolation Functions are listed in i. (continuedi B 3 ._3-142 Revision No .. 48 .

BASES BACKGROUND (continued) ... ' .. p'BAPS UNIT 2 Primary Containment Isolation Instrumentation B 3.3.6.1 3., 4. High Pressure Coolant Injection System Isolation and Reactor Core Isolation Cooling System Isolation The Steam Line Flow-High Functions that isolate HPCI and RCIC receive input from two channels, with each channel comprising one trip system using a one-out-of-one logic. Each of the two trip systems in each isolation group (HPCI and RCIC) is connected to the two valves on each associated penetration. Each HPCI and RCIC Steam Line Flow-High channel has a time cielay relay to prevent is.olation due to flow transients during startup. The HPCI 'and RCIC Isolation Functions for Drywell Pressure-High and Steam Supply Line Pressure-Low receive inputs from four.* channels. The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of the associated valves. The HPCI and RCIC Compartment and Steam Line Area Temperature_:_High. Functions receive input from 16 channels, four .channels at each of four different locations. The channels are arranged in a one-out-of:--two. taken twice l_ogi_c for each location: The HPCI and RCIC. Steam Line .Flow-High Functions, Steam Supply Pressure-Low Fun_ctions, and* Compartment and. St.earn Li.ne Area Temperature-High Functions_ isolate the associate_d steam supply and turbine exhaust. valves and pump suctionvalves. The HPCI and RCIC Drywell Pressure-High. Functions isolate and RCIC test return line .valves. The_ HPCI*. and RCIC* Drywell *Pressure_:_High FU:nctions, in **.conjunction wi.th the Steam Supply Line Pressure-Low

• Functibns,
• the HPCI arid. RCIC turbine. exhaust vacuum --relief** vc{Ive:?*-. .: . . ' . . ' 5;. *Reactor water Cleam.ip*. system Isolation Th.e React6r: Vessel .Water Level::_Low (Level 3) Isolation* Function*receives input' from four reactor vessel.water level_ The from the reacto,r vessel water level" channels are connected :Lnto aone-out'-c-of-two*taken twice logic which isolates both *the arid outboard. isolatiqn *.
• The RWCU,. Flow-High Fuficti.on 'receives input .. ' tv.o with' \:harinel in t:tip system using a one-out"-b:f...:.one iogic; with one channel tripping the inboard v.alve *arid one channel tripping the. outboard valves. The SLC (continued) Revision No. 4 B,.*.

BASES BACKGROUND PBAPs-: UN IT 2 _.*.,* Primary Containment Isolation Instrumentation B 3.3.6.1 5. Reactor Water Cleari0p System Isolation (continued) System Isolation receives input from two channels with each channel _in one trip system using a* one-out-of-one logic. When either SLC pump is started remotely, one channel trips the inboard isolation valve and one channel isolates the outboard isolation valves. The RWCU Isolation Function isolates the inboard and outboard RWCU pump suction penetration.and the outboard* valve the RWCU connection to reactor feedwater. 6. Shutdown Cooling System Isolation The Reactor Vessel Water Level-Low (Level 3) Function input from four reactor vessel* water level channels. -The outputs the channels are cbnnected to a one-out-of-two taken twice logic, which isolates both valves on-the RHR shutdown cooling pump suction penetration. The Reactor Pressure-High Function receives input from two channels, with each channel in one trip system using a logic. Each trip system is connected to both valves on the RHR shutdown cooling pump suction penetration. 7. Feedwater Recirculation Isolation . . -. The Reactor Function inputs from four channels. The outputs from the four channels are connected into a one-out-of-two taken twice which isolates the recirculation valves. ---8. -Traversing Incore Probe System I sol at ion The Reactor Vessel Water Level-Low, Level 3 Function receives input frcim two reactor vessel water level channels. The outputs from-the reactor vessel water level are connected into one two-out-of-two logic trip system. The Isolation function receives input from two pressure channels. The outputs from the drywell pressure channels are connected into one two-out-of-two logic trip system. When either Isolation Function actuates, the TIP drive mechanisms will withdraw the TIPs, if inserted, and close the TIP system isolation ball valves when the TIPs are fully withdrawn. The redundant TIP system isolation valves. are rrianua 1--shear va_l ves TIP System Isoiation Functions iso-late :the Group IICD) TIP valves (-isolation ball valves). (continued) Revision-No. 5Z .,.* J _,_-;* . " *, .-BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UNIT 2 Primary Containment Isolation Instrumentation B 3.3.6.1 The i$olation signals generated by the primary containment isolation instrumentation are implicitly assumed in the safety analyses of References 1 and 3 to initiate closure of valves to limit offsite doses. Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves CPCIVs)," Applicable Safety Analyses Bases for more detail of the safety analyses. Primary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. Certain instrumentati.on Functions are retained for other reasons and are described below in the individual Functions discussion. The OPERABILITY of the primary containment instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified .in Table 3.3.6.1-1. Each Function must have a required number of OPERABLE.channels, with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setting is not within its required Allowable Value. The actual setpoint is calibrated tonsistent with applicable setpoint methodology assumptions. Allowable Valuesr where applicable, are specified for each Primary Containment Isolation Function specified in the Table. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the setpoints do not exceed the Allowable Value CHANNEL CALIBRATIONS. Operation with a trip setting less .. than the trip setpoint, but within its . . Allowable Value, is acceptable .. Trip setpoints are those values of output at which an action should

• take place. The are compared to the actual process parameter (e.g., reactor vessel level), and when the.measured output value of the process exceeds the the associated device (e.g., trip unit) state; analytit or design limits are derived from the limiting values of the process parameters -Obtained-from the safety ahalysis or other appropriate , documents. The Allowabl.e Values are from the
• analytic or design limits, corrected for calibration, process, and instrument*errors. The trip setpoints are determined from analytical or design limits, corrected for calibration, pr6cess, iristrument as well as; *. instruinent'drift. *In selected cases, the Allowable .. *.*. and trip setpoints determined by engineering judgement or historically accepted practice relative to the intended function_ of the channel. The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties for the environments duririg the :Operating time of the assoc'iated channels are atcounted for:. ' . *--' . Certain Emergency Core Systems CECCS) and RCIC vahes (e_;g-., minimum flow) also serve the dual function of: automatic PCIVs.*. The signals that isolate these valves are .. also assoctated the automatic initiation of the ECCS (continued} B 3.3-145 Revision No .. 57.

BASES APPLICJD.BLE SAFETY ANALYSES, LCO, a1rtd APPLICJD.BILITY (continued) PBAPS UN tr 2 Primary Containment Isolation Instrumentation B 3.3.6.l and RCIC. The instrumentation requirements and ACTIONS associated with these signals are addressed in LCO 3.3.5.1, "Emergency Core Cooling Systems (ECCS) Instrumentation," and LCO 3.3.5.2, "Reactor Core Isolation Cooling (RCIC) System Instrumentation," and are not included in this LCO. In general, the individual Functions are required to be OPERABLE in MODES 1, 2, and 3 consistent with the Applicability for LCO 3.6.1.1, "Primary Containment." Functions that have different Applicabilities are discussed below in the individual Functions discussion. The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis. Main Steam Line Isolation 1.a. Reactor Vessel Water Low Low (Level ll

• Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore,. isolation of the MSIVs and other interfaces with . the reactor vessel occurs to prevent offsite dose limits from being exceeded. The Reactor Vessel Water Low Low. (Level 1) Function is one* of the many Functions assumed to be OPERABLE and capable of providing isolation signals. The Reactor Vessel Water Low Low {Level 1) Function associated with isolation is assumed in the analysis of the recirculation line break (Ref. 1). The isolation of the MSLs on Level 1 supports actions to ensure that offsite dose limits are not exceeded for a OBA. Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a*constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water . Low Low (Level 1) Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. (continued) B 3.3-146 Rev i s ion No . 0 BASES APPLIU1BLE SAFETY ANALYSES, LCO, and APPLIC.l1BILITY **-_ .... PBAPS llNIT 2 Prim.ary Containment Isolation Instrumentation B 3.3.6.1 l.a. Reactor Vessel Water Level-Low Low Low (Level 1) (continued) The Reactor Vessel Water Level -Low Low Low (Level 1) Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite doses from exceeding 10 CFR 50.67 limits. This Function isolates MSIVs, MSL drains, MSL sample lines and recirculation loop sample line valves. l.b. Main Steam Line Pressure-Low Low MSL pressure indicates that there may be a problem with the turbine regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than l00°F/hr if the pressure loss is allowed to continue. The Main Steam .Line Pressure-Low Function is . directly assumed in_ the analysis of the pressure regulator failure (Ref. 3). F6r this event, the closure -Of the MSIVs ensures that the. RPV temperature change limit (l00°F/hr) 1s not reached. In addition, this Fu.nction supports actions to* ensure.that Safety Limit 2.1.1.1 is not* exceeded. (This Function closes the MSIVs during the depressurizat.ion 'transient. i ri .order to mai nta*i n reactor steam dome pressue. 700 psta.
• The MSIV cl osi.Jre results in a scram, thus reducing reattor power-to< 23% RTP:). The MSL lbw pressure signals are initiate.d from four transmitters that are connected to .. the .MSL header. The transmitters are ar'ranged such that, even though physically. separated *from each *other *.. each *transmitter is able. to . detect lo'w MSL pressure. Four channels of Main Steam Line* Pressure-.::. Low Function* ar_e avan able and are required to be o'PE'RABLE to en.sure th*af no sj.ngle instrument failure can . : preclude t_he i'solati 6rr-funct'i on:' -** ** *i ' . *-The A 11 owabl e Value sel.ecteci°' to be* high enough to . I ' *
• Mai'n .*SteaiilL i ne. Pr'essure-:Low Fu net ion is.only re qui red . to be:oPERABLE.; in.MOD.E *1 strice this is when the ass1:.1m.ed ._ * * ****.*.transient'can occur (Ref. JL -* . :< .*. --. This on .isolates *.MSIV*s: MSL: drai ris, MSL .sample.lines. and recfrculation loop sampJe line vaives,> (continued) **' .. B 3-147 *Revision NQ; 128 . i..
• .. ' '**.-. .. * -*.. -.. ** .. >.*.* BASES APPLICABLE SAFETY ANALYSES, . LCO, and . APPLICABILITY * .. (continued} Primary Containment Is.al ati on Instrumentation '8 3.3.6.1 l.C; MajrJ Steam Line Elow...:..Hiqh. Main steam Line Flow-High is provided to detect a break of the MSL and to initiate closure Of the MSIVs. If the steam were allo\.,ied to continue.flowing out of the break, the.* reattor.would depressurize and the core could uncover. If the RPV*water l.evel decreases too far, damage could *occur. Therefore, the isolation is initiated on high flow to prevent* or minimize core damage*. The Main Steam Line .Flow-High* Function is 'directly assumed in the analysis of the main break CMSLBl (Ref. 3). The 1solatiori action: ii with function of Reactor Protecti*on System (RPS)', ensures that the fuel. peak cladding temperature remains. below the limits of lOCFR.50.46 and offsfte doses db' not exceed the 10 CFR 50.61 l.fmits. ' ' ihe signals are initiated from 16 that . are connected to the four MSLs. The transmitters are arranged, such that, even 'thoughphysicalJy separated from.' .
• each other, .all *four. conneeted to one MSL would be able to
• the htgh flow .. Fou*r channels o.f Main Steam Line ea.ch MSLCtwo channels per trip .. system) are avafla'bl e and are required to be OPERABLE so *that no, single instrument fai.1 µre will preclude detecttng a
• any 1ndividualMSt:.; ** * ** * * * 'rhe Value-'is to ensu,re that dffsite dose* ' *. *li!nits are not .exceeded.due. to the break.* "' This .Function* MSiVs, MSL drains, MSL. sample 1 i nes and retlrculati on 1 oop sample line valve's. ""*.* .. *-.*.-. *. . ' : '. . : . ' ' . . . ... *'. < copti nSed) .* ** : ** ... ,, . ,. .... *. :. *'.**: _:: .. :*:-.:. :" .:,*_.; .. _*: . -:?.* :.-.:**-.. : ____ ;*. _: :.**. ' : .. .. ,. _., .. _-*, PBAPS'.l.JNIT 2 :**. ,;.****-. . _.-*. *, ... . *"1., ......... . '*** ... * **, ... * . *. ) -. ' *.' .. *./*-* ** ... * ::.:-' .: s 3 .3-:14a>** .**.-; .. ::: .* '*'* *--! . _* .' .. ',.: * .. * .. -::_.-* .**-.. *.::*-.. I .**.* ...

BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UNIT 2 _.-:,*, ... -Primary Containment Isolation Instrumentation B 3.3.6.1 l,e

• Building Main Steam Tunnel Temperature-High The Turbine Building Main Steam Tunnel Temperature Function is provided to detect a break in a main steam line and provides diversity to the high f1 ow instrumentation. _Turbine Building Main Steam Tunnel Temperature signals are .initiated from resistance temperature detectors (RTDs) located along the main steam line between the Reactor Building and the turbine. Twelve channels of Turbine Building Main Steam Tunnel Temperature-High Function are. and are required tb be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The All.owable Value ls* chosen to detect a leak equivalent to between 1% and 10% rated steam flow. This.Ftinction isolates MSIVs, MSL drains, MSL lines and recirculation loop sample line valves. 1.f.* Reactor Building Main Steam Tunnel Temperature-High The Reactor Building Main Steam Tunnel* Temperature Function is provided to detect a break in a main steam lirie and provides diversity to the high flow instrumentation. ' . ' . . . ' ' Reactor Building Main Steam Tunnel Temperature signals are initiated.from resistance temperature detectors (RTDs) located in the Main Steam Line Tunnel ventilation exhaust duct. Four channels of Reactor Building Main Steam Tunnel. Temperature-High Function are available and are required to be OPERABLE tb ensure that no single instrument failure can preclude the function.
• Ccontjnued) B 3.3-'149 Revision Nci .. 134

':, :* *:-' * .. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY Primary Containment Isolation Instrumentation B 3.3.6.1 1.f Reactor Building Main Steam Tunnel Temperature-High (continued) The Allowable Value is chosen to detect a leak equivalent to between 1% and 10% rated steam flow. This Function isolates MSIVs, MSL drains, MSL sample lines and recirculation loop sample line valves. Primary Containment Isolation 2:a. Reactor Vessel Water Level-Low (Level 3) Low RPV water 1 evel indicates that the capabi 1 i ty to cool the fuel may be threatened. The valves. whose penetrations communicate with the primary containment are isolated to limit the release of fission products. The isolation of the. containment on Level 3 supports actions to ensure that offsite dose limits of 10 CFR 50.67 are not (continued) .B 3.3-149a. Revision Np. 75 I * ... -* . . -. '. ,* -;. -:*. *: '*. _.*, BASES APPLICABLE SAFETY.ANALYSES, LCD, and APPLICABitITY Primary Containment Isolation Instrumentation B 2.a. Reactor Vessel Water Level-Low (Level 3) (continued) The Reactor Vessel Water (Level 3) Function associated with isolation is -Implicitly assumed in the UFSAR analysis as these leakage paths are assumed to be isolated post Reactor Vessel Water Level-Low (Level* 3). signals are initiated from level transmitters that sense the difference between the due to a constant column of water (reference leg) and the pressure due to the a6tual water .level (variable leg) in the Four channels of Reactor Vessel Water Level -Low (Level 3) Function are * *avai 1 able and are required to be* OPERABLE to ensure that no* -single instrument failure can the isolation function. The Reactor Vessel Level -Low (Level 3) Allowable Value was choseri to be the same as the RPS 3 scram Allowable Value (LCD 3.3.1 :n I since isolation of these valves i.s not cri t.i cal to orderly pl ant shutdown. This isolates the Group II(A) valves. listed i.n Reference 1 *with the exception of RWCU isolation valves and ) ,*RHR shutdown cooling pump suction valves which-are addressed '.***. : .. * ' .. *. ,,.* ... , PBAPS UNiT 2 ,',

• iri Functibns 5.c and 6.b, 2.b, *Drywall Pressure-High Hi gti drywel 1 pressure can indicate a break in the RCPB * -Inside the primary The isolation of some -0f the primary containment is.elation valves on high drywall actibris tb ensure that offsite dose limits of 10 CFR 50.67 are not exceeded. The Drywall Pressure-High .*
• Fur:iction, as.so.ciated with isolation of the primary. *containment, is i mpl i ci tl y assumed in the UFSAR accident analysis as these leakage are as*umed to be isolated post LOCA. . .. High drywel l pressure signals i ni ti ated from pressure transmitters that sense the pressure in the drywall . Four *.channels of Drywall Pressure-High are available and are Tequired to.be OPERABLE to ensure that no single instrument * .. failure can preclude the isolation function. (continued) B 3.3-150 .Revision No.75

. . . -,. -i,.,_, .. -* .. *; <-, .. ** .... ' :>--BASES --=.-----;--------Primary Containment Isolation Instrumentation B 3.3.6.l . . APPLICABLE 2.b. Drvwell Pressure-H1qh *(continued) SAFETY ANALYSES, . LCO, and The Allowable Value was selected to be the same as the ECCS APPLICABlLITY Drywell Pressure....;High Allowable Value (LCO 3.3 .. 5.1), since this*may be indicative of.a LOCA inside primary containment. ** .... ,.*.--* **: .. _*,:.:. .. *:*** . . . . . *'*.r: '**.:: : ";.' '* This Function isolates the Group II(B) valves listed in Reference I. . . . . . Main Stack Monitor .Radiation-High* *Ma.in stack monitor radiation is an indication that the release of radioactive material may exceed established limits. Therefore,. when Main Stack Monitor Radiation-High is detected when there *is flow through the Standby Gas * .Treatment* .an isolation of primary* containment purge supply and exhaust .penetrations is initiated to limit the* release of,f1ssion products. However, this Function is not assumed in.any accident or transient analysis .in the UFSAR other .leakage paths.(e.g., MSIVs)are.more limiting .. * **-. ' . . **. . . . . . . The drywell radiat.ion .are initiated. from radiation* detectors. that isokinetiCall.Y sample the main stack * * .

• utilizing '.'Sample pum1l's Two lchanne ls of Ma in Stack . . . *.*. >: Raaiatfon:...High FunctiOJ1 are. available. and are required to be OPERABLE 'to.*ensure that no. single tnstrument failure can ** .. precl ude***the j_sol atiori tµrlction. * * *. . . -* : . *:1:*' . The is .* set all * .... * . . rel ease' 1 jnfit in with the: Off site Dose .*
• Calc.ul atjon. Manual: (ODCM) ** **-*. . . .*,:.. -'* ... -.. '.* .,__ ,. . '* *.' : * : * * *. * .... :* ... Tfii s '.Functiori: *isol at'es itie** arid 'purge ... valves; "* ** ** ... *and'othet Group*l(l(E):\ialves listed*in Reference I>.* *, * ." I --. ,. *: -' .. .-: .. -. .'. -> . . . *' '*. . -. --. ::*' . . :(d.-.: 2.i. .Reactor'Buildhig Ventilation and *Refueling Floor' . . _ -;-Veiitilafioh ExhaustiRadiation.--Hiqh .**.* :* .. -. * * * -*<*: : ... -', -. -: . -. . . *' .. -**:* . .'. *.. . i .. :-* **." .. *. *. : . :_:,, ... ; : .. :,:.: -_*_ :, . i . '* *.* -*.* ." -: ** .,_.-_ _. .. ;-.:_,*-,\.:High secondary.:contafnnient ******, *_ : *.* * ; fodicatioft gross .fan ure of the-fuel. cl . ' , . -Th_e reJease. ma.Y.have origill.ated. from the primary containment** . _ .* .. due tc( a;:break i.n :the. *wheri Reactor Building *or* -.
• ReJuellngJl9or ventflati:o'ri Radiation-Jiigh is .. :: * . the pathway and primary_ ... * :_ *-** ... *-*" ....... ,_-_*:*"_: ***:-*._, _-: . -" **, *.* -.. . :_::: .. ': :--*_ .. *. * *** * . ** . *. * . . .. , .--* . * -.. ";._ :.' .. *::*'*.-*:" :-. -._ '* "-* ... . .. .*_:.:--<°, '. ' -.* * *: -. . . .**_:**** -*-.... . -;.< :. ' ... --. --* * ..... *. Revision ... . -._ '* . PBAPs UN fr .2 ** .. * * *--* .-' *. -* .... _. -.* *-' -_ ...... . :*:* -.-'*** **.* :.-; *.; -. .*.::* . .. ,. *.. -.... : *-* -,_._*.*

BASES APPLICABLE SAFETY LCO, and . APPLICABILITY Primary Containment Isolation Instrumentation B 3.3.6.l 2.d .* 2.e. Reactor Building Ventilation and Refueling Floor Ventilation Exhaust Radiation-High (continued) containment purge supply and exhaust valves are isolated to limit the release .of fission products. Additionally, Ventilation Exhaust Radiation-High Functi'on initiates Standby Gas Treatment System. The Ventilation Exhaust Radiation-High signals are initiated from radiation detectors that are located on the ventilation exhaust piping coming from the reactor building and the refueling floor zones, respectively. The from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel. Four channels of Reactor Building Ventilation Exhaust-High Function and four channels of Refueling Floor Ventilation Exhaust-High Function are available and are required to be OPERABLE to ensure .that no single instrument failure can preclude the isolation function. The Allowable Values are chosen to promptly detect gross failure of the fuel cl add.ing during a refueling accident. These Functions isolate the Group IIl(C)" and Ill(D) valves l i sted fr1 Reference 1. * . High Pressure Coolant Injection and Reactor Core Isolation Cool inq Systems Isolation .. *

• 3.a .* 3.b .* 4.a .* HPCI and RCIC Steam tfoe Flow-High *and Time Delay Relays
• Steam.Line*.* Fl ow-:-Hi gh. Functions are provided. to detect a* break of the RCIC-or-HPCI:steam lines and-initiate closure of .. the steam line isolati.on valves of the appropriate system.* . If the steam is* allowed to flowing -out of the break, the reactor will depressurize and the core can Li.ncover*.-the isolations *are int:tiated on high flow to prevent:or minimize core damage *. The isolation action, along with-* the scram function of the RPS, ensures .. that.the fuel peak cladding temperature remains below the PBAPS UNIT 2 * . limits of 10 CFR 50.46. *.Specific credit for these Functions
• is not assumed in .any UFSAR accident analyses since the . *, ' . -": .. *RevisionNo. 0

--BASES -APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY . . . . . . . --._ PBAPS UNil 2 _ -c .* -. '-.:*.: :.' .. *., ... : Primary Containment Isolation Instrumentation B 3.3.6.1 3.a., 3.b., 4.a., 4.b. -HPCI and RCIC Steam Line Flow-High and Time Delay Relays (continued) * -bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments prevent the RCIC or HPCI steam line breaks from becoming bounding. The HPCI and RCIC Steam Line Flow-High signals are initiated from transmitters (two for HPCI and two for RCIC) that are connected to the system steam lines. A time delay is provided to prevent isolation due to high flow transients during startup with one Time Delay Relay channel associated with each Steam Line Flow-High channel. Two channels of both HPCI and RCIC Steam Line Flow-High Functions and_ the assoc_iated Time Delay Relays are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Allowable Values for Steam Line Flow-High Function and associated Time Delay Relay Function are chosen to be low enough to ensure that the trip occurs to maintain the MSLB event as the bounding event. -These Functions isolate the associated HPCI and RCIC steam supply and turbine exhaust valves and pump suction valves. 3.c., 4.c. HPCl and RCIC SteamSupoly Line Pressure-Low _ Low MSL pressur_e indicates that the pressure of the steam in the-HPCI or RCIC turbine may be too low to continue _

• operation of the_ associated system's -These isolations prevent radioactive gases and steam from escaping through the pump .shaft seals into the reactor building but are primarily for.equipment protection and are also assumed for long term containment.isolation. However, they also provide a diverse signal to indic;ate a possible system break. These instruments are included _in Technical Specifications (TS) because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 4). The HPCI and RCIC Steam Supply Line Pressure-Low signals are. initiated from transmitters (four for HPCI and four for RCIC) that are connected to the system steam line. -Four {continued) B 3.-3-153-Revision .o * -

,* ... BASES APPLICABLE SAtETY ANALYSES, LCO, a1rad APPLICABILITY Primary Containment Isolation Instrumentation B 3.3.6.1 3.c .* 4.c. HPCI and RCIC Steam Supply Line Pressure-Low (continued} channels of both HPCI and RCIC Steam Supply Line Pressure--Low Functions are available and are required to be OPERABLE to ensure that.no single instrument failure can preclude the isolation function. The Allowable Values are selected to be high enough to prevent damage to the system's turbine. These Functions isolate the associated HPCI and RCIC steam supply and turbine exhaust valves and pump suction valves; 3.d., 4.d. Drvwell Pressure-High (Vacuum Breakers) High drywell pressure can indicate a break in the RCPB. The HPCI and RCIC isolation of the turbine exhaust vacuum breakers is provided to prevent communication with the drywell when high drywell pressure exists. The HPCI and RCIC turbine exhaust vacuum breaker isolation occurs following a permissive froni the associated Steam Supply Line Pressure-Low Function which indicates that the system is no

• longer required or capab 1 e of performing coo 1 ant injection.' The isolation of the HPCI and RCIC turbine exhaust vacuum breakers by Drywell Pressure-High is indirectly assumed ,in the UFSAR accident analysis because the turbine exhaust **leakage path is not assumed to contribute to offsite doses. High drywell pressure signals are initiated. from pressure
• transmitters that_ sense the pressure in the drywell. Four channels for both HPCI and RCIC Drywell Pressure-High (Vacuum Breakers) Funct i oris are available and are required -to be OPERABLE to ensure that no single instrument failure PBAPS .*UNIT. -2 * *can prec 1 ude t_he isolation function. *
• The Allowable Value was selected to be the same as the ECCS . Drywell Pressure7'"High Allowable Value (LCO 3.3.S.i), since this is indicative of a lOCA inside primary .. This Function isolates the associated HPCI and RCIC vacuum -. relief valves and test return line valves. . . . (continued} B 3.3-154 Revision No-. o

. *-**-. . :'::** *' ,: .. ' -.* ... :** BASES . APPLICABLE SAFETV ANALYSES, LCO, arid . APPLICABILITY * (continued) Primary Containment Isolation Instrumentation

• B 3.3.6.1 3.e .* 4.e. HPCI and RCIC Compartment and Steam Line Area Temperature -Hi qh HPCI arid,RCIC Compartment and Steam Line Area temperatures are provided to detect a leak from the associated steam piping. The isolation* occurs when a very small leak has occurred and is diverse to the high flow
• instrumentation. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions not assumed in any UFSAR transient or accident analysis; since bounding analyses are performed for large breaks such as recirculation or MSL breaks. HPCI and RCIC Compartment and Steam Line Area
• Temperature.-High signals are initiated from resistance temperature detectors (RTDs) that are appropriately located *
• to protect the system that is being monitored. The HPCI and RCIC Compartment and Steam Line Area Temperature -High *Functions each use 16 temperature channels. Sixteen channels for each.HPCI and RCIC Compa.rtment and Steam line Area Temperature-High Function are available* and are *required to be OP.ERABLE to ensure that .no single instrument failure can preclude the isolation function. *
• The Allowable Values are.set low enough to detect a leak . . . These Functions isolate the associated HPCI and RCIC steam* and. and pump suction Reactor (RWCU) System Isolation. 5.a.
• RWCU Flow-High . ihe high flow signal is provided to detect a break in the . RWCU System. Should. the reactor coo 1 ant continue to fl ow 'PBAPS UNIT. 2 *. -'
• out bf the break, offsite dose limits may be exceeded. Therefore, isolation of the RWCU System is initiated when high RWCU flow is sensed to prevent exceeding offsite doses. This Function is not in any UFSAR transient or . ace ident analysis,
• s i nee bounding ana 1 yses are performed for *Jarge such as MSLBs. (continued) B 3 .. 3-'-155 Revision No. 32.

I 1. *** .. >*' : .. , .. ,;.. ,*,.*' .. ;_,_ .... :*.* BASES Primary tontainment.Isolation Instrumentation B 3.3.6.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 5.a. RWCU*Flow-High (continued) 'The high RWCUflow signals are initiated from transmitters that are connected to the pump suction line of the RWCU System. Two channel.s of .RWCU Function are available and are required to be OPERABLE to ensure that no single instrument failure can the isolation .,., *.:**., **,._; .. * ..... . '*." '** . ,.,*,_ **-,. function. *

• The RWCU:Flow-High Allowable Value ensures that a break of the RWCU. p1 pi rig is .. ' Thi.s *Function isolates. the. inboard and outboard RWCU pump suction pehetrati on and the. *outboard valve at the RWCU connection.to reactor
• Standby L1quid Control. (SLC) System Initiation **. The isolation. of the RWCU System is required when the SLC *System has. been i ni .tiated to prevent dilution. and removal of .*. the boron so 1 ution by the RWCU System (Ref. 5) . SLC System initiatipn .. signals are ini.tiated from the remote SLC System start switch.*** * * * ** * * * .. there i*s Allowable Valu.e assoCiated with 0th-ls Function **
• si nee* the. channels afe mechanically actuated based Solely on *
• the position of *.the :SLC System i ni ti at ion switch ... * . -. . . . -. . . .* . . . . ' . . . . . ., For vi ty. insertion I, two s. of the SLC . *Sy$tem.Intt-il3tion Func.tiori avail.able and. are r*equi,redtd* ; . , be in: MODES f and .2. since these are.*the only .MODES *
• where *the>reactor can* be* criti'cal .' In addition, for accidents 1 nvo1vi119 si 9n1 fi cant 'fission proauct reJ eases; both channels .
• are required to be :OPERABLE in. MODES +; '2; ahd. 3. The SLC * . Sys:tein is. designed to mai r1tai n suppressi;oh pool pH at qr * ** ab6ve :7 JfolloiN,i'iig a JOCA, to:, enSufe that sLlf.fi 91 ent. i adj ne .* * .. :*: wi 11 ' be retained.in fhei"'5Uppressi<)h. pool : water. These-MODES* . . . ,:, .. ., :** *'*,**:.-** .. :*.:.;,'. ... , ..... :'** ._. _..: *: ' *., .. .. -i:_::. *:': ->. : *. *::*.*. . '.'" . :._ PBAPS UN:fr .. -; ' .. * . .with thELApphcability fot the:SLC :system. (Lcq .. 3.1 7); . c -*... . * ._, .... ** .. . .*. ;,._-. .... , .. . *J .. * : Thi l:! . Functjqr) 1 i:;oi ates .th:e. j nboarci *.and. ou.tboqrd . RWCU : pµrnp : . *a\ Rwcu* * .*=*: .. ****.*. *,. *;-.. :r*:
• 5.'. c .. **** Reactor 'Vess;ei *water Leve 1 _.:.Low (i_eve i'. 3) .*.. ',.** , **:. **.' Lc:iw RPV :,1 S\lel :.i ndi ci:ites that. the: capabfti ty to cool . *. toe .. ftiel. rn*ay be th'r:eatened .:. .Shaul d .. RPV: ... water**.l evel deCrease ** fa(;" *:.darh(ige:cou] d. fesuJt ; .. Therefore;.*. isolation o.f' .. ir)"f:er.faces* wjth the reader vesse*l OCCUrs:*.to isolafe .: .. the. pqtent*ial,.sources of: a:br1;Hik;'.* '*The ;i'solation of the RWCU *.* Syi:freni on level <l supports 'actiohs to *ensure that the' fuel * . ... ;*.: .. '.:::* .. * ... * . . .. ,*' ... * * . * '** . . . ., . B :Li-156
• R.evi-s*i on No. ifr'. .* * *'..: .'. . : ;.,_._. -*

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 2 Primary Containment Isolation Instrumentation B 3.3.6.1 5.c. Reactor Vessel Water Level-Low <Level 3) (continued) peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Vessel Water Level -Low (Level 3) Function associated with RWCU isolation is not directly assumed in the UFSAR safety analyses because the RWCU System line break is bounded by breaks of larger systems (recirculation and MSL breaks are more limiting). Reactor Vessel Water Level-Low (Level 3) signals are initiated from transmitters that iense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water 1 evel ( variable 1 eg) in the vessel. Four channels of Reactor Vessel Water Level -Low (Level 3) Function are available and are* required to be OPERABLE to ensure that no single instrument failure can the isolation function. The Reactor Vessel Water Level-Low (Level 3) Allowable Value was chbsen to be the same as the RPS Reactor Vessel Water Level--Low (Level 3) Allowable Value (LCO 3.3.1.1), since the capability to cooi the fuel may be threatened. This Funitioh isolates the and outboard RWCU suction ¢enetration and the outboard valve at the to reactor feedwater. Shutdown Cooling System Isol1tion* 6. a.

• Reactor gh * *
• I
• The Reactor High Function is provi to isolate the shutdown cooling portion of the Residual Heat Removal CRHR) System.* Th.is. Fuhcti,o.n.is provided onh for equipment protectioiltb LOCA and _ credit for the Fi.tncti on* is not assumed iii the acci.dent or * -transient-analysis_in the-UFSAR. , The Pressu-re.,..High signals are initiated from two relays driven by -trip units associated with. pressure --_ . _ _ I transmitters that *sens*e RPV pressur_e at different taps on RPV. Two channels of Reactor Pressure-High Fun*ction are avail a)Jl e and are required to be .OPERABLE to ensure. that no single -instrument failure can preclude the.fsolation -_ _ function.-.---The_Furictioh 1so11ly required to.beOPERABLEin*** * .. -, ' (continued) B 3.3--f57 _ Revis i.on 'No .135*

BASES APPLIC.ABLE SAFETY ANALYSES,

• LCO, and APPLICABILITY . P8APS 'UNIT 2 Primary Containment Isolation Instrumentation B 3.3.6.l 6.a. Reactor Pressure-High (continued) MODES 1, 2, and 3, since these are the only MODES in which the reactor can be pressurized; thus, equipment protection is needed. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization. This Function isolates both RHR shutdown cooling pump suction valves. 6.b. Reactor Vessel Water Level-Low (level 3) Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some reactor vessel interfaces occurs to begin isolating the potential sources of a break. The Reactor Vessel Water Level-Low (Level 3) Function associated with RHR Shutdown Cooling System isolation is not directly assumed in safety analyses because a break of the RHR Shutdown Cooling System is bounded by breaks of the __ recirculation and MSL. The RHR Shutdown Cooling System isolation ori Level 3 supports
• actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RtlR Shutdown Cooling System. Reactor Vessel WaterLevel-Low (Level 3) signals are initiated-from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual. water (variable leg) in the Four channels (two Channels per trip system) of the Reactor Vessel Water -Level-Low (Level 3) Function are available and are required to be OPERABLE to.ensure that no single instrument failure
• can preclude the isolation function. As noted (footnote (a) to Table 3.3.6.1-1), only one channel per trip system (with an isolation signal available to one shutdown cooling pump suction isolation valve) of the ReactorVessel Water Level-Low (Level 3) Function are required to be OPERABLE in MODES 4 and 5, provided the RHR Shutdown Cooling System integrity is maintained. System integrity'is maintained provided the piping is intact and no maintenance is being performed that has the potential for draining the reactor vessel through the system. {continued) . ; .* B 3.3-158 -Revision No.>o

. *,' -* BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UNIT 2 * *Primary Contairiment Isolation Instrumentation B 3.3.6.1 6.b. Reactor Vessel Water Level-Low (Level 3) (continued) The Reactor Vessel Water Level-Low (Level 3) Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low (Level 3) Allowable Value (LCD 3.3.1.1), since the capability to cool the fuel may be threatened. The Reactor Vessel. Water Level-Low (Level 3) Function is only required to be OPERABLE in MODES 3, 4, and 5 to prevent this potential flow path from lowering the reactor vessel level to the top of the fuel. In MODES 1 and 2, another . isolation .* Reactor Pressure-High) and.administrative controls ensure that this flow path remains isolated to prevent unexpected loss of inventory via this flow path. This Function isolates both RHR shutdown cooling pump suction valves. Feedwater Recirculatinn Isolation 7.a. Reactor Pressure-High The Reactor Pressure-High Function is provided to isolate the feedwater recirculation line. This interlock is

• provided only for equipment protection to prevent an intersystem LOCA scenario, and credit for the interlock is not assumed in* the accident or transient analysis in the UFSAR. . . The Reactor signals are initiated from four trcinsmitters that are conriected to different taps on the RPV .. Four channels of Reactor Pressure-High Function are *available and are required to be OPERABLE to ensure that no* instrumerit failure can pretlude the isolation .. :func.tion. The Function is .. only required to be OPERABLE in MODES 1, 2, and 3, *since these are the only MODES in which the teactor can be pressurized; equipment protection is needed. The Allowable Value was chosen to be low enough to_protect the system equipment from overpressurization. This Function i5olates the feedwater rec.irculation valves. Traversing Incore. Probe SVstem Isolation *8.a. Vessel Water Level-Low. 3 . . . . ** Low RPV water ievel indicates thatthe capabiiity to cool the fuel may be.threatened.** The valves whose communicate with the priJnary containment are isolated to C cont.i nued) I B 3.3-159 . Revision No.

I* BASES APPLICABLE SAFETY ANALYSES, LCO, and (continued) PBAPS. UN IT 2 Primary Containment Isolation Instrumentation B 3.3.6.1 limit the release of fission products. The isolation of the primary containment on Level 3 supports actions to ensure that offsite dose limits of 10 CFR 100 are not exceeded. The Reactor Vessel Water Level-Low, Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA. Reactor Vessel Water Level-Low, Level 3 signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Two channels of Reactor Vessel Water Level-Low, *Level 3 Function are available and required to be OPERABLE to that no single instrument failure can initiate an inadvertent isolatinn actuation. The isolation function is ensured by the manual shear valve in each penetration. The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCD 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown. This Function isolates the Group IICD) TIP valves. 8.b. Drywell Pressure-High High drywell pressure can a break in the RCPB inside the primary containment: The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 are not The Drywell Pressure-High Function, associated with isolation of the primary containment, is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA. High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Two channels of Drywell Pressure-High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent actuation. The isolation function is ensured by the manual shear valve in each .Penetration. **The allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCD 3.3.5.1), since this may be indicative of a LOCA inside primary This Function isolates the Group IICD) TIP valves. (continued)

• B 3.3-159a Revision No. 57 Primary Containment Isolation Instrumentation B 3.3.6.1 BASES (continued) ACTIONS The ACTIONS are modified by two Notes. Note 1 allows penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated. Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, _will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condttion continue to apply for each additional failure, with Complefion Times based nn initial entry into the Condition. However, the Required Actions for inoperable primary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channel_s. As such, a Note has been provided that allows separate Condition entry for each inoperable primary isolation instrumentation channel. -: -.-*. PBAPS UNIT 2 the diversity of serisors to provide isolationsignals and the redundancy of the isolation _ design,<an allowable'out ofservicetime of 12 hoursfor Functfons 1.d, 2.a, and 2.b and 24 hours for Functions other fhan Functions l;d, 2;a, and 2.b has been shown to be (Refs; 6 and 7) to permit restoration of any -i noperabJe channe 1 to OPERABLE status .. -This . out of service time is* only acceptable provided fhe associated Function is -still maintaining isolation capabili.ty (refer to Required_ Action B.l Bases). If the-inoperable channel c-annot be_ restored t6 OPERABLE within the out of , service.time, the-channel tnust be placed* in the tripped -*condition per Req-uired-Acti.OnA,J. Placing the.inoperable channel in tri'p would *conse-rvati \feTy compensate lor. the. i noperabflity", 'restore capabi 1 i ty to accommodate a sing] e failure, ,and allow operation.to_continue with-no further restrictiqns. Alternately, :.if it is not-desired to place t,he chanD°el<in-trip (e._g .. , as in the case.where placing the <inoperable channel in trip would r.esuH-ir:i an isolation), -Condition'( must be entered and its Required Action *._-, --(.continued)_ -)"_ . . .. ' . .... :' . .. ., . -.. -B 3.3-160 * */' '. *_ .. * -

I BASES ACTIO},TS (continued) PBAPS UNIT 2 Primary Containment Isolation Instrumentation B 3.3.6.1 B.1 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant isolation capability being lost for the associated penetration flow path(s). For those MSL, Primary Containment, HPCI, RCIC, RWCU, SDC, and Feedwater Recirculation Isolation Functions, where actuation of both trip systems is needed to isolate a penetration, the Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip (or the associated trip system in trip), such that both trip systems will generate a trip signal from the given Function on a valid signal.. For ._those Primary Containment, HPCI, RCIC, RWCU, and SDC isolation functions, where actuation of one trip system is needed to isolate a penetration, the Functions are considered to be maintaining isolation

• capability when sufficient channels are OPERABLE or in trip, such that ohe trip system will generate a trip signal from the given signal. This ensures that at least one o.f the PCIVs in* the associated penetration flow. path an signal the given .. Function. For all Functions except 1.c, 1.e, 2.c, 3.a, 3.b, 3.e, 4.;a, 4.b, 4.e, _5.a, *5;b,* and 6.a, this would require both trip to.have one channel.OPERABLE or in trip. For .Fun*c:tion 1. C( this would both. trip systems to have one'channel,* associated with each MSL; OPERABLE or.in trip ..
• For Functions 1: e,* *3. e and 4. e, . each Function consists of channels that monitor.several locations within a _given area (e.g., different locations within the Turbine Building* main steam.tunnel area);; Therefp.r:-e, this would require both trip.systems. to one channel per location OPERABLE:*or in trip. :For *Functions 2.i:::, 3.a, 3.b, 4.a,* 4.b, 5.a, **and 6.c;;.,* tlJ.ls-would.requireone. tripsystem*to have one channel** OPERABLE. in trip .. .. -. : *-.--*. *. -.. ' The:*Coir:ipletion Time is intended to. allow the operator tlme to and repaii: any. discovered inoperabilities. The . 1 hour Time* ls
• becaus*e it min_imizes risk wliiie all_qwing time for. restoration or tripping of channe*ls. < B 3.3-7161. Revision No. 48 *.-.'**

BASES ACTIONS PBAP S UNIT *2 Primary Containment Isolation Instrumentation B 3.3.6.1 B.1 (continued) Entry into Condition Band Required.Action may be necessary to avoid an MSL isolation transient resulting from a temporary loss of ventilation in the main steam line tunnel area. As allowed by LCO 3.0.2 (and discussed in the Bases of LCO 3.0.2), the plant. may intentionally enter this Condition to avoid an MSL isolation transient following the of ventilation flow, and then raise the setpoints for the Main Steam Tunnel Function to 250°F causing all channels of Main Steam Tunnel Temperature-High Function to be inoperable. However, during the period that multiple Main Steam Tunnel Temperature-High Function channels ate inoperable due to *this intentional action, an additional compensatory measure is deemed and shall be taken: ah operator shall observe control room indications of the duct temperature so the main steam line isolation valves may be promptly closed in the of a rapid increase in MSL tunnel temperature indicative of Jine break. C.l ReqUited Action C.l:directs entry into the appropriate in Table 3.3.6.1-1. The applicable Condition specified in Table 3.3.6.1-1 is Function and MODE or. dther specified condition dependent and may as the Required Act1on of a previous Condition is completed. Each t.ime an *inoperable channel has not met any Required Action of Cond{tion A or 8 and the associated Completion Time has expired; Condition C will .be entered for that channel and provides for transfer to the appropriate subsequent Condition. *

• D.1. D.2.1. and D.Z.2 If the channel is not restored to OPERABLE status or placed in trip withi.n the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by. placing the plant in at least MODE 3 within 12 hours and in MODE 4 within 36 hours (Required Actions D.2.1 and D.2.2). Alternately, the associated MSLs may be isolated Action D.1), continued B* 3.3-162 Revision No.45:

BASES ACTIONS i PBAPS UNIT 2 ,. ' ,,-* Primary Containment Isolation Instrumentation B 3.3.6.l D.l. D.2.1. and D.2.2 (continued) and, if allowed (i.e., plant safety analysis allows operation with an MSL isolated), operation with that MSL isolated may continue. Isolating the affected MSL accomplishes the safety function of the inoperable channel. The Completion Times are reasonable, based on operating . experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which. the LCO does not apply. This is done by placing the plant.

• in at least MODE 2 within 6 hours. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 2 from full power conditions in an orderly manner and without challenging
• pl ant systems. *
• F.I
• If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path(s). accomplishe*s the safety function of the inoperable channels . . Alternately, if it is not desir.ed to the affected
• penetration flow path ( s) (e.g. , as in the case where *.isolating the penetration flow path(s) c'ould result in a . reactor scram), Condition G must be entered and its Required Actions taken.: The 1 hour Completion Time is acc.eptable. **.
• because it minimizes risk while allowing sufficient time for* plant operations personnel to isolate the affected * *
• penetration fl ow (continued) B 3.3-163 Revision No. 0 BASES ACTIONS *(continued) PBAPS UNIT 2 G.l and G.2 Primary Containment Isolation Instrumentation B 3*.3.6.l If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, or the Required Action of Condition F is not met and the associated Completion Time has expired, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours and in MODE 4 within 36.hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. H.l and H.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated SLC subsystem(s) is declared inoperable or the RWCU System -is isolated. Since this Function is required to ensure that **the SLC System perfoms its intended function, sufficient remedial measures are provided by declaring the associated SLC subsystems inoperable or isolating the RWCU System. The I hour Completion Time is acceptable because it minimizes risk while allowing sufficient time for personnel to isolate the RWCU System. I.I and 1.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed. However, if the
• shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is inunediately initiated to restore the channel to OPERABLE status or to isolate the RHR Shutdown Cooling System (i.e., provide alternate decay heat removal capabilities so the penetration flow path can be isolated). Actions must continue until the channel is restored to OPERABLE status or the RHR Shutdown Cooling System is isolated. (continued) B 3.3-164 Revision No. O Primary Containment Isolation Instrumentation B 3.3.6.1 BASES (continued) SURVEILLANCE REQUIREMENTS . ::, PBAPS UNIT 2 As noted at the beginning of the SRs, the SRs for each Primary Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1 . . The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allbwance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis.(Refs. 6 and 7) assumption of the . average time required to perform channel surveillance. That *.analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the PCIVs will isolate the* penetration flow path(s) when necessary. S R 3 .; 3 ; 6 . 1 . 1 . Performance of the CHANNEL CHECK ensures that a gross . failure of instrumentation has not occurred. A CHANNEL CHECK is normally* a *comparison of the parameter indicated.on *o'ne channel to a similar parameter on either channels.* It is based on :the *assumpti ori th.at i'nstrument channels monitoring the same parameter should read approximately the same value. Si gni fi cant deviations behieen* the instrument channels could b.e an indication of excessive instrument,drift in one of the c h a n n el !?*: o r o f s om et h i n g even mo re s e r i o u s . A CH AN N E L C H EC K wil.l detect gross char.ine.l failure} thus' it is. key to verifying the .instrumentation continues tOoperate properly between* each tHANNEL' CALfBR,ATION, . *. **.. ' . . . Agre_ement criteria *are determined by the pl ant staff based :o.n a *combhiati on of the channel i.nstrument
• Uncertainties, .including in di cati,on* and rea.dabi 1 ity.. If. a *Channel is '
• rilaycbe*.9i1 iri'dicatioh*that the . fristrurilerit 'has drifted outside 1ts 1 imi.t, ...*.. *. *. The Survefl lance Freguency fs controlled under the Survei 11 ance. Frequency .Cor:it'rol '.Program. The CHANNEL CHECK emen:ts 'less fcirfnal.; but more frequent, checks Of *chanhelsdur:-ing normal operational use of. :the .displays .. assoc-i ated* with. the channels required by the LCO .* . . * ..... _.: . Revision No. 86 J:.

I I BASES SURVEILLANCE" REQUIREMENTS (continued) PBAP s lJN IT 2 SR 3.3.6.1.2 Primary Containment Isolation Instrumentation B 3.3.6.l A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. For F.unction l.e, l.f, 3.e, and 4.e channels, verification that trip settings are less *than equal to the specified Allowable Value during the FUNCTIONAL TEST is not required since the installed indication instrumentation does not provide accurate indication of the trip setting. This is considered accepiable since the magnitude of drift assumed in the setpoint calculation is based on a 24 month calibration interval.

• The Surveillance Frequency is controlled under the Survei 11 a nee Frequency Control Program. SR SR and SR 3.3.6.1.5 (SB. 3.3,6.1,6 Deleted) A CHANNEL CALIBRATION is a complete check of the instrument .loop*and the sensor. This test verifies the channel responds to the measured parameter wi.thin the _ . range and
• tHANNEL CALIBRATION the channel* adjusted *to .account for instrument drifts between with the the setpoint method6logy. *
• I -sp*ecific to Main SteamLiiie Pressure-LowCTechnical . Specification*Table Function 1.b) and the Main Steam Line Specification Table 3.3.6.1-1. Function .Le) I there is a'oplant specific program*which . . verifies that* th:i s* i channel functions. as* required* by-verifying the .as-left an.ct settings are *
• co.nststent with. those* established by the setpOint *methodology. * (Continued)* ' ... ' .. ,-,*., ... _._ ..
• No. 134 . 'i 1
• BAS E.S SURVEILLANCE REQUIREMENTS REFERENCES P S lJ N IT 2
• Primary Containment Isolation Instrumentation B 3.3.6.1 SR 3.3.6.1.3. SR 3.3.6.1.4. SR* and SR 3.3.6.1.6 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.6.1.7 The LOGIC FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 overlaps this to provide complete testing of the assumed safety function. The Surveillance is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 7.3. 2. NRC Safety Evaluation Report for Amendment Numbers 156 and 158 to Facility Operating License Numbers DPR-44 DPR-56, Peach Bottom Atomic Power Station, Unit 2 and 3, September 7, 1990. 3. UFSAR, Chapter 14. 4. NED0-31466, "Technical Specification Screening .Criteria Application and Risk Assessment," November 1987. 5. UFSAR, Section 4.9.3; continued B Nb. 114 .*,:*.

BASES -.... ;: .* ' ' ... . **: PBAPS UNIT 2 Primary Containment Isolation Instrumentation* B 3 .. 3.6.1 . 6. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990. 7. NEDC-30851P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989. *.*.,. B 3.3-168 Revision No. -1 Secondary Containment Isolation Instrumentation B 3.3.6.2 B 3.3 INSTRUMENTATION B 3.3.6.2 Secondary Containment Isolation Instrumentation BASES BACKGROUND PBAPS UNIT. 2 The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation Systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1). Secondary containment isolation and establishment of vacuum with the SGT System within the required time limits ensures that fission products that leak from primary containment. following a DBA, or are released outside primary containment, or are released during certain operations when primary containment is not required to be OPERABLE are maintained within applicable limits. The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of secondary containment isolation. Most channels include .electronic equipment trip units) that compares measured input signals with pre-established setpoints; When the setpoint is exceeded, the channel output relay actuates, which then outputs a secondary containment isolation signal to the isolation logic.* Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (1) reactor vessel water level, (2) drywell pressure, (3) reactor building ventilation exhaust high radiation, and (4) refueling floor ventilation exhaust high Redundant sensor input signals from each parameter are provided for initiation of isolation. The outputs of the channels are arranged in a one-out-of-two.* taken twice logic. Automatic isolation valves (dampers) isolate and SGT subsystems start when both trip systems are in trip. Operation of both trip systems is required to isolate the secondary containment and provide for the necessary filtration of fission products. (continued) B 3.3-169 Revision No. 1 '. . . *' . *, .. 2 *:. '* '* . ' . -** ; ***.*. *. .. .. , *,: _:* ' "* . . Secondary Containment lsolati.on Instrumentation . B 3.3.6.2

• BASES *(continued) . . .APPLICABLE SAFETY. ANALYSES, . LCO, cind .. APPLIC:ABILITY The i s*o 1 at ion s i gna 1 s generated by the secondary containment isolation instrumentation are implicitly assumed' in the safety analyses of References 1 and 2 to initiate closure of valves and start the SGT System to limit offsite doses. ',* **, ..*.. *" .. . . ... ' Refer to LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs>',11 and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System,11 Applicable Safety-Analyses Bases for more .detail of the safety * .. The secondary containment isolation instrumentation *satisfies* Criterfon.3 of the NRC Policy Statement. Certain instrumentation Functions are retained for other reasons and are described below in the iridividu(ll Functions discussion. . ' The OPERABILITY of the secondary .containment iSo 1 at ion * *. instrumentation is dependent on the OPERABILITY of *the instrumentation channel Functit>ns ... Each Function must have the required number of OPERABLE channels with their setpoints* set within the specified Values, *. ' as' shown :Jn.Table 3 .3 2-J. The actual setpoint i S. ' . . .calibrated cons i sterit with. app l i cable set point methodology * ** . c:m.s. A. channel* is inoperable . if its actua 1 trip .* * . setting is not within jts required Value. ' : , . .... . . ; . . :* "'.
• Al 1 owable *Values are* specified for each Functton specified ... in the Trip setpoints;. are specified' Jn the setpolrit. < cal cul ati olis. The trip set points,; are .se 1 ected to ensure that th.e. setpoints do'not .e'xceed :the:Allowable Val.ue betwe_en Operation with a:*trip' setting less *.co.J1servatiye. than trip setpot11t, butwithin. its .. * .. * :Allowable .is ... * . *.-*: .' ** ... **.* ... * .. * .*.** _ *.Trip nts pfedefermi ned *. values _of .otitput-.at *.which an ac:ti0n* should. :place.*. :The .are < * . . . ; P.fo.cess i>.arameter reactor . : . , -* -* ,
• vessel water* 1eve1)
• tind
• wh.en the. measured J>titput value. pf*. 'tre, setpoint, .th¢: devic*e*(.e."g.,':trip unit} charige.s. The*arialytic or** design*Jimits.*are**derived from the* limfting\t'alues of the.: .. * .* ..... I.'* . ::. :, .. '* .. -.*.* *. -*._process<parameters obtained: from* the,safety_ analysis or.-*,* *. * ' . other appropriate documents. 'The A 11 ow able . Values are . * .. * .. * * *. .from the analytlc: or design corrected *for * *process, and instrument The trip_.. . setpoii:1ts:are then. determined from analyt1cal :or design\ process,-and .:*.,.*. ,_ -:! **.** .:. * .. *" . . . '** .... * . . . ;:., .. ,..., t *-,:.,*: " .. *, .* .. _-: : *. : -*. . ."* .-. **.'. : .. **, .** . :** ; *.. . .. :, . * . *.,:'. . B 3*. f-1}0 ., . *. .. *:-.. :*:;: .' ,'* , ... *, *ccoiltinued) .. . , * .. *.*:,**; .:, ; _:-.'.-: Revl s i ori****No *.. '-< ' .. * . ' .. .* .. * .... ***.I BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICJ\BILITY (continued) PBAPS UNIT 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 errors, as .well as, instrument drift. In selected cases, the Allowable Values and trip setpoints are determined by engineering judgement or historically accepted practice* relative to the intended function of the channel. The trip setpoints determin-ed in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environments during the operating time of the associated channels are accounted for. In general, the individual Functions are required to be OPERABLE in the MODES or other specified conditions when SCIVs and the SGT System are required. Thespecific Applicable Safety Analyses, LCO, a_nd Applicability discussions are listed below on a Function by Function basis. 1. Reactor Vessel Water Level-Low (Level 3) Low reactor pressure vessel (RPV) water level indicates that the capability to.cool the* fuel may be threatened. Should RPV water le.vel decrease too far, fuel damage could result. An isolation of the secondary containment and actuation of the SGT System are initiated in order to minimize the potential of an offsite dose release. The Reactor Vessel Water Level ... Low (Leve 1 3) . Function is one_ of the Functions assumed to be OPERABLE and capable of providing isolation and The isolation and initiation systems on Reactor Vessel Water Level -Low (Level 3) support acttoris to:erisure that ani offsite are within the *. limits .calculated* in the *safety analysis .. *. '. * * *. . . I . ' . ,* Reactor Vessel: Water Le_vel'.;_Low* (Level 3) *signals are initiated-from level transmitters that sense the difference* between 'the pressure. due_ to a constant col limn Of water.
• and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Leve.l (Level 3) Function are available and are requfred to be OPERABLE .iii MODES I, 2, and
• 3* to ensure that'no s_ingle instrument failure can preclude
• the fao lat ion function.* * *Ccorltiriuedl * '.* .. . -*.. . B*3.3-17l* RevJsi on No .. I I L__.* BASES APPLICABLE . SAFETY ANALYSES, LCO, and APPLICABILITY . PBAPS; IJNIT 2 Secondary Containment Isolation Instrumentation B 3.3.6.2 I. Reactor Vessel Water Level -Low (Level 3) {continued) The Reactor Vessel Water Level -Low {Level 3) Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value {LCO 3.3.1.1), since isolation of these valves and SGT System start are not critical to orderly plant shutdown.
• The Reactor Vessel Water Level -Low {Level 3) Function is required to be OPERABLE in MODES 1, 2, and 3 where
• considerable energy exists in the Reactor Coolant System {RCS); thus, there is a probability of pipe breaks resulting in releases of radioactive steam and gas. In MODES 4 and the probability and consequences of these events.are low due to.the RCS pressure .and temperature limitations of these MODES; thus, this Function is not required. In addition, the Function is also required to be OPERABLE during.operations with a potential for draining the reactor vessel {OPDRVs) because the capability of isolating potential sources of leakage must be provided to .ensure that offsite dose limits are not exceeded if core damage occurs. 2 .. Drywell Pressure-High . . . High drywell can indicate a break in the. reacto.r coolant pressure boundary {RCPB). An isolation of the -secondary containment and actuation of the SGT System are initiated in order to minimize the potential of an offsite dose release. The isolation on high drywell pressure
• supports actions *to ensure that any offsite releases are withiri the limits calculated in the safety analysis. The Drywell Pressure-High Function associated with isolation is not assumed in any UFSAR accident or transient analyses but will provide an isolation and initiation signal. It is retained for the overall redundancy and diversity of the secondary containment isolation instrumentation as required by.the NRC approved licensing basis. (continued) .. B 3.3-172
• Revision No. ;1 ****:.

I . I I I I I. I ':. **-*: * ... BASES APPLICABLE SAFETY ANALYSES, LCO, and . APPLICA.BILITV PBAPS UNIT .2 . -. ---------Secondary Containment Isolation Instrumentation B 3.3.6.2 2. Drywell Pressure-High (continued) High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell.

• Four channels of Drywell Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude performance of the isolation function. The Allowable Value was chosen to be the same as the ECCS Drywel 1 Pressure-High Function Allowable Value (LCD 3.3.5.1) since this is indicative of a loss of coolant accident (LOCA). The Drywell Pressure-High Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the RCS; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. This Function is not required in MODES 4 and 5 because the. probability and consequences of these events are low due. to the RCS pressure and temperature limitations of these MODES. 3 .* 4. -Reactor Bu1ldinq Ventilation and Refueling Floor Ventilation Exhaust Radiation ...,High High secondary containment exhaust radiation is an indication of possible gross failure of the fuel cladding. The release may have originated from the primary due to a break in the RCPB or dtiring refueling due to a fuel handling accident. When Ventilation Exhaust Radiation-High is detected, secondary containment isolation and actuation the SGT System are initiated to limit the release of
• fi*sion products as assumed in the UFSAR safety analyses (Ref. 4). . . The Ventilation Exhaust Radiation-High signals are .... initiated from radiation that ate located on the ventilation exhaust piping coming from the reactor building. and the refueling floor zones, respectively. The signal from each is input to an individual monitor whose trip outputs are *assigned to an isolation channel.* Four.** (continue.d) ** -*. B 3.3-173 Revision No. 1 I ' ' ;.,.,.-*.*. BASES -APPLICABLE SAf=ETY ANALYSES, LCO, and APPLICABILITY --1-. ' -ACTIONS . . . . _**. -. ---_ . PBAPS _UNIT 2. '-* .. -'-. *-** Secondary Containment Isolation Instrumentation B 3.3.6.2 3,
• 4. Reactor Building Ventilation and Refueling Floor Ventilation Exhaust Radiation-High (continued) channels bf Reactor Buildiilg Ventilatioh Exhaust -*Radiation-High Function and four channels of Refueling Floor Ventilation Exhaust Radiation-High Function are avai 1 a.bl e ahd are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
• The Allowable Values are chosen to promptly detect gross failure of the fuel ciadding. The Reactor Building Ventilation and Refueling Floor Venti 1 ati on Exhaust Radi ati oh-High Functions are required to be OPERABLE in MODES 1,,2, and 3 where considerable. energy exists; thus, there is a probability of pipe breaks resulting in sigriificant releases of radioactive and gas. In MODES 4 and 5, the probability and consequences of thes.e events. are 1 ow due to the RCS pressure .and temperature limitations of these MODES; thus, these are not required. In addition, .the Functions are also.required to be OPERABLE'during OPDRVs and movement of RECENTLY :IRRADIATED FUEL assemblies in.the secondary containment, the of detecting radiation eases due to fuel 1a1lures to fuel uncovery or dtcipped assemblies) must be provided to ensure that off site dose.** limiti are not exceeded. ANote*has been provided to modify the ACTIONS related to 'secoildary containment isolatibn instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsystems, components, or variables expressed in the Condition, to be inoperable or not limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Conditioh c6ntinue to apply for each additional failure, Times based on initial entry into the Condition. However, the Required Actions for inoperable secondary containment isolation instrumentation channels -provide appropriate compensatbry for separate As such, a Note has been provided that allows separate Condition entry for each inbperable secondary containment instri.mientation channel . :-:*.: (continued) B 3*.3-174 . Revision No. 75

.:--,_-: BASES Secondary Containment Isol.ation Instrumentation B 3.3.6.2 ACTIONS A.I (continued) PBAPS UN lT 2 Because of the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of I2 hours for Functions I and 2, and 24 hours for Functions other than Functions I and 2, has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining i sol at ion capability (refer to Required Action B.l Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time; the channel must be placed in the tripped condition per Required Action A.I. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. if it is not desired to place the channel in trip as in the case where placing the inoperable channel in trip would result in an isolation), Condition C must be entered and its Required Actions taken.

• I is intended to ensure that appropriate actions*are taken if multiple, inoperable, untripped within the same Function result in a complete loss 'of isolation capability for the associated penetration flow pa:th(s) Or a: complete loss of automatic _initiation capability for the SGT System. */\_,function is considered to be maintaining secondary containme*nt isolation capability' when sufficient channels ar:-e .. OPERABLE or in trip, such that. both trip systems will a trip 'signal from the given -_ function a valid signal. This ensures *that at 1 east one -of the two SCIVs in the associated penetration flow path and **.*.*at least .one SGT* subsystem 'can-be-initiated on an isolation s'ignal **from the _given Function. '.For Functions 1, 2, .3, and 4; this wc)uld require both trip systems to have one
• chanrie 1 *oPERABLE or in trip. ** (continued} :. -* , ..... . * :"**,.*:. B 3.3:...175 * .* Revis i ori No. *_ L . I i I BASES ACTimlS SURVEILLANCE *. . -. . PBAPS . UN IT 2 . _:* .. _ Secondary Containment Isolation Instrumentation B 3.3.6.2 B.1 (continued) The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. C.1.1. C.1.2. C.2.1. and C.2.2 If any Required Action and associated Completion Time of Condition A or Bare not met, the ability to isolate the secondary containment and start the SGT System cannot be ensured. Therefore, further actions must be performed to ensure the ability to maintain the secondary containment function. Isolating the associated secondary containment penetration flow path(s) and starting the associated SGT subsystem (Required Actions C.1.1 and C.2.1) performs the intended function of the instrumentation and a 11 ows operation to continue.
• declaring associated SCIVs or SGT subsystem(s) inoperable (Required Actions C.1.2 and C.2.2) is al so a.cceptab 1 e s i nee the Required Actions of the respective LCOs (LCD 3.6.4.2 and LCD 3.6.4.3) provide appropriate actions for the inoperable components. One is for plant operations personnel to establish required. plant tonditions or to detlare the .. associated components inoperable without unnecessarily *challenging plant systems. .. * ... * .. ' As* noted**at the beginning of th.e SRs, the SRs for each
• Containment *Isolation.instrumentation Function are located in the *sRs column of Table (continued) -' : .. B 3.3-176
• Rev.i s i on , No
• 1 BASES SURVEILLANCE REQUIREMENTS (continued) Secondary Containment Isolation Instrumentation B 3.3.6.2 The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains secondary contain_ment isolation capability. Upon completion of the -Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable tondition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 5 and 6) that of the average time required to -perform channel -surveillance. That analysis demonstrated hour testing allowance does not significantly reduce the probability that the SCIVs will isolate the associated penetration flow paths and that the SGT will initiate when necessary. SR 3.3.6.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a simi]ar parameter on other channels. It is based on the assumption that instrument the same parameter should read approximately the same value. Significant deviations the channels
• could be an indication of excessive instrument drift in one of the channels or something even more serious. CHECK will detect gross failure; thus, it is key verifying-the instrumentation continues _to operate properly between each CHANNEL CALIBRATION. -Agreement criteria are by the plant staff on a combination of the channel uncertainties, including and readability. If a channel is outside the criteria, may be an ind1cation that the has drifted outside its limit. The Surveillance Frequency is controlled under the Surveillance Frequency Control The CHANNEL tHECK supplements less formal, but more frequent, checks of channel during normal operational use of the displays associated with channels required by the LC6. continued B 3.3"177 --Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UNIT 2 ..
• SR 3.3.6.2.2 Containment Isolation Instrumentation B 3.3.6.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodolbgy. The Surveillance Frequericy is controlled under the Surveillance Frequency Control Program. SR 3.3.6.2.3 and SR 3.3.6.2.4T A tHANNEL CALIBRATION is a complete check of the instrument loop and the This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between sutcessive calibrations, consistent with the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.6.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific *channel. The system functional testing performed on SCI Vs and the SGT System in LCO 3.6.4.Z and LCO 3.6.4.3, respectively, overlaps this Survei Hance to provide coriipl ete testing of the function. The Surveillance Frequency is controlled under the Survei 11 a nee Frequency Control Program. . I (continued) ..
• B 3.3-178 Rev i s i on No : .8 6 BASES (continued} REFERENCES . * :-.---.-.* PBAPS UNIT 2 . Secondary Containment Isolation Instrumentation B 3.3.6.2 1. UFSAR, Section 14. 6. 2. UFSAR, Chapter 14. 3. UFSAR, Section 14.6.5. 4. UFSAR, Sections 14.6.3 and 14.6.4. 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990. 6. NEDC-30851P-A Supplement 2, "Technical Specifications : Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation,11 March 1989 . B 3.3-179 Revision No. 1 ..

MCREV System Instrumentation B 3.3.7.l B 3.3 INSTRUMENTATION B 3.3.7.1 Main Control Room Emergency Ventilation (MCREV) System Instrumentation BASES BACKGROUND The MCREV System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all pl ant conditions. Two independent MCREV subsystems are each capable of fulfilling the stated safety function. The instrumentation and controls for the MCREV System automatically initiate action to pressurize the main control room (MCR) to minimize the consequences of radioactive material in the control room environment. In the event of a Control Room Air Intake Radiation-High signal, the MCREV System is automatically started in the mode. The outside air from the normal ventilation intake is then passed through one of the charcoal filter subsystems. Sufficient outside air is drawn fo through the normal ventilation intake to maintain the MCR slightly pressurized with respect to the turbine bui1ding . .

• MCREV: System instrumentation has two trip systems with . '-_*., APPLICABLE . _ . SAFETY ANALYSES, LCO, and* . . * -APPLICl\BILITY two Control Room Air Intake Radiation..;.High channels in each trip -The outputs of the Control Room Air. Intake Radiation,:...High .channels are arranged in two trip systems, which us*e a one-out-of....,two logic. The tripping of both trip iniiiate subsystems. *The channels foclude .electronic equipment (e.g., trip* units) that input signals with setpoints *.. When the setpoint is exceeded, the channel output relay actuates, which theri outputs a MCREV System
• initia1.ion signal to the i_nit.iation logic. The ability of the MCREV System-to maintain the habitability of the MCR -is explicitly assumed for.certain-accidents as discussecj in the UFSAR safety arjalyses (Refs. I;, 2, and*3). MCREV System operation ensures that the radiation exposure **Of control room personnel, through the duration of any one of the postulated accidents, does not exceed atceptabl e . lirnits --.. . * (continued) . ' ; ._ -*-.. -*-. . : -__ . . . ' : . . PBAPS UINIT 2. -B --Revision No. L ,.*

I. BASES APPL I C1"BLE *SAFETY ANALYSES, LCO, airid APPLICABILITY . (continued) PBAPS UIN IT 2 MCREV System Instrumentation B 3.3.7.1 MCREV System instrumentation satisfies Criterion 3 of the NRC Policy Statement.

• The OPERABILITY of the MCREV System instrumentation is dependent upon the OPERABILITY of the Control Room Air Intake Radiation-High instrumentation channel Function. The Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setting is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Allowable Values are specified for* the MCREV System Control Room Air Intake Radiation-High Function. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setting *conservative than the trip setpoint, but within its Allowable Value, is Trip setpoints are those predetermined values of output at which an action should take.place. The setpoints are compared to the actual process parameter (e.g., control room air intake radiation), and when the measured* output value of the process parameter exceeds the setpoint, the associated device changes state. The analytic limits are from the limiting values of the process parameters obtained from the analysis. The Allowable Values are derived from the analytic limits, corrected for calibratiofi, process, and instrument errors. The trip setpoints aredetermined from analytical or design limits, corrected for calibration, process, and instrument . errors;. as well as, instrument drift. The.tr.ip setpoints derived i_n this manner provide adequate protection by . .* ensuring 'instrument. and. process* uncertainties expected for
• the* environments during the operating time of the *associated. channelS .are accou.nted for.* * * ., . ' : *-. . . *. *,* . .* .. *_ .
• The . l room air intake radiation monitors measure radiatfon levels ii1 t;he fresh air supply plenum. A high radiatipn level may pose a threat to* MCR *personnel; .
• automatically the MCREV System .. * * {continued), .*. . . *. .. . . . . -. . . B 3.:3-181* Revision .1 i ..... BASES . APPLICABLE . SAFETY ANAL VSES, *.Leo, and APPLICABI LITV * *{continued) . ACTIONS
• MCREV System Instrumentation
• B 3.3.7.1 -.. * . The Control Room Air Intake Radiation -High Function consistS of four independel"!t monitors. Two channels of C_ontrol Room Air Intake Radiation -High per trip system are available and a:re required to be OPERABLE to ensure that no . single instrument failure can preclude MCREV System ** initiation.* The Allowable Value was selected to ensure protection of the control room personnel. -. . . . . . . The Control Room Air Intake Radiation-High Function is* required to be OPERABLE in MODES l, 2, and 3 and during CORE * . ALTERATIONS, OPDRVs, and movement of irradiated fuel .
• asseinbl i es in the secondary containment, to ensure that -.*control room personnel *are protected during a LOCA, fuel*.
• handling event, or vessel draindown event. During MODES 4 and 5, these spec.ified conditions are not in progress {e.g.; CORE the probability of *a LOCA o.r fuel* damage is low; thus, the Function is not required. * * ' . . A *Note has been provided to modify the ACTIONS related to . MCREV System* instrumentation* channels.. * .. Section L 3, *
• Completion Times, specifies that once a Condifion has* been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, w.ill not result in separate : .. '.* *_ . entry into the C.ondition. Section 1.3 also specifies that*. *. **.Required Actions of the Condition continue to .apply for each *additional failure, with Completion Times based on initial*
• entry* into the However, the Required Actions for .. inoperable MCREV System instrument a ti on* channels provide appropriate compensatory measures for separate inoperable ' .. As stich, a has been provided that allows separate Condition entry for each.inoperable MCREV System . . >.- ....... : * ...... ... _; ',""' ... , . . .** .. : .. * . : ...... *_ .. -.,., * .. * .. ** *-;._, instrumentation channel .. **.** * * * * * -.* -..... .* * .. . -. .* ** A. l and A-.2. Because of.the redundancy of sensors avajlable to provide initiation signal s and .. the . redundancy of the MC REV. System design, an allowable OIJt of service time of 6.hours has been shown to be acceptable :(Ref. 4), to permit restoration of * *any inoperable channel.to OPERABLE However; this out .of service time is only *acceptable provided the Control . Room Air Intake Radiation:.High Function is still . maintaining MCREV System initiation capabiJ ity. The F-unction is cons1dered to b.e maintaining MCREV System {cont i nuedl .. ***" . ":. .*:. '-* :*-* . .:_*** .. .
• B* 3*.3;..,182 .o * .. ** * "--*-* ":;** :; **. :* ... -:* .. . ' .... :,1 .. **-** ..*;** ... -*-

BASES ACTIOMS I* PBAPS UNIT* 2 A.I and A.2 (continued) MCREV System Instrumentation B 3.3.7.I initiation capability when sufficient channels are OPERABLE or in trip such that the two trip systems will generate an initiation signal from the given Function on a valid signal. For the Control Room Air Intake Radiation-High Function, this would require the two trip systems to have one channel per trip system OPERABLE or in trip. In this situation (loss of MCREV System initiation capability), the 6 hour a 11 owance of Required Action A. 2 is _not appropriate. If the Function is not maintaining MCREV System initiation capabil i ty, the MC REV System must be dee 1 ared i noperab 1 e* within I hour of discovery of the loss of MCREV System initiation capability in both trip systems. The I hour Completion Time (A.I) is acceptable because it minimizes risk while allowing time for restoring or tripping of channe 1 s. If the i noperab 1 e channe 1 cannot be restored to OPERABLE: . . status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and a 11 ow . ; to Continue. Alternately, if it is not desired to .Place the channel in trip (e.g., as in the case where

• placing the inoperable channel in trip would result in an *initiation), Condition B must be entered and its Required* Action taken . . B. l and B.2
• With> any Required Action and associated Completion Time not. met, the associated MCREV subsystem(s) must be placed in operation per Required Action B.I to ensurfa that control room personne 1 .will be protected in the event of a Design Basis Accident. The method used to place the MCREV subsystem(s) in must provide for * **** re-initiating the subsystem(s) upon restoration of power following a loss.of power to the MCREV subsystem{s). Alternately, if it is not desired to start the subsystem(s),
• the MCREV subsystem(s) associated with inoperable,_ untripped * (continued l B 3.3-I83 Revision No. 1 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 B.l and B.2 (continued) MCREV System Instrumentation B 3.3.7.1 channels must be declared inoperable within 1 hour. Since each trip system can affect both MCREV Required Actions B.l and B.2 can be performed independently on each MCREV subsystem. That is, one MCREV subsystem can be placed in operation (Required Action B.l) while the other MCREV subsystem can be declared inoperable (Required Action B.2). The 1 hour Completion Time is intended to allow the operator time to place the MCREV subsystem(s) in operation. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for placing the associated MCREV subsystem(s) in operation, or for entering the applicable Conditions and Actions for the inoperable MCREV subsystem(s). The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains MCREV System initiation *Upon completion of the .Surveillance, or of the 6 hour allowance, the .. channel must be returned to OPERABLE status or the
• applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 4) assumption of the time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the MCREV System will initiate when necessary. SR 3.3.7.1.l Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same Significant deviations between the instrument channels *could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect continued B 3.3-184 Revision No. 86 BASES SURVEILLANCE REQUIRl::MENTS ',:::.-: .** .'* -, . . --.* -.... PBAPS UNIT '2 SR 3.3.7.1.l (continued) MCREV System Instrumentation B 3.3.7.1 gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted ouiside its limit. . . The Frequency is controlled under the Surveillanie Frequency tontrol Program. The CHANNEL CHECK supplements less formal, but frequent, checks of charinel status during normal operational use of the displays associated with channels required bY the LCO. SR. 3.3.7.1.2 A CHANNEL-FUNCTIONA4 TEST is performed on each required chC1nnel to ensure that the entire channel wi 11 perform *the i ntenaed fun ct i o.n. Ariy set poi r:it adjustment s ha 11 be assumptions of the current plant *s*peci fi c set point met ho do logy; . . -.. ** . *. . :*, . . . The Surveill ante Frequency is control led under the Surveil hnce Frequency Contrcil Program. * *' SR A CHANNElCALr'BRATION is:a check of the instrument loop an.d the *sensor .. This test Verifies the resp,orids to the measured: parameter within the .necessary _ r_ange. and -accura-t:y .. CHANNEL CALIBRATION leaves the channel . adjusted to acc()unt.'lor instrument drifts betwee_n successive i brations' .cons'i ste'nt wi t,h. the assumpti ans of the pl ant.* speci n*c_setpoi nt methodology*, -. . . . . The s'urvej l
• Freque.ncy. is :controlled under the' Survei 11 ance Frequen'cy* Control -Program.: :,_ . C cont i nl.ied) . -**' . -Revision NO. 86 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES . ' PBAPS UNIT.2 SR 3.3.7.l.4 MCREV System Instrumentation B 3.3.7.1 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.7.4, "Main Control Room Emergency Ventilation CMCREV) System," overlaps this Surveillance to provide complete testing of the assumed safety function. The Surveillance is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 10.13. 2. UFSAR, Section 12.3.4 . . . 3,
• UFSAR, Section 14.9,1.5. 4. GENE-770-06-1, for Changes to Surveillance Test .**Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," Febq.1ary 1991. -* ',. -.** .. -.**-* .. :._ ... ' . :. -. . . . B 3.Jd8.6. Revision No. 86 I-LOP Instrumentation B 3.3.8.1 B 3.3 INSTRUMENTATION B 3.3.8.1 Loss of Power (LOP) Instrumentation BASES BACKGROUND
• UINil 2 -., . Successful operation of the required safety functions of the *Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power for energizing various components such as pump motors, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4 kV emergency buses voltage. Offsite power is the preferred source of power for the 4 kV emergency buses. If the LOP instrumentation detects that voltage levels are too low, the buses are disconnected from the offsite power sources and connected to.the onsite diesel generator (DG) power sources. Each Unit 2 4 kV emergency bus has its own independent LOP instrumentation and associated trip logic. The voltage for each bus is monitored at five levels, which can be
• considered as two different undervoltage Functions: one level of .loss of voltage ahd four levels of degraded voltage. The Functions cause various bus transfers and disconnects. The degraded voltage Function is monitored by four undervoltage relays per source and the loss of voltage* Function is.monitored-by one undervoltage relay for each
• emergency bus.
• The degraded vo 1 tage outputs and the loss of voltag*e outputs are arranged in a one-out-of-one trip logic configuration. Each channel consists of four protective relays that compare offsite source voltages with _ setpoints. When the sensed voltage is below the setpoint for a degraded voltage channel, the preferred* offsite source breaker to the 4 kV emergency bus.is tripped and autotransfer to the alternate offsite source is initiated. If the *lternate source does not provide adequate vo 1 tage to the bus as s.ensed by its degraded grid relays, a diesel generator start s_ignal is initiated. A description of the Unit 3 LOP instrumentation is provided in the Bases for Unit 3 LCO 3 . 3. 8. 1. (continued) B 3 .3"'.""187 * -Rev i s i on
• No . .5 LOP Instrumentation. B 3.3.8.1 (continued) APPLIU1BLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT. 2 The LOP instrumentation is required for Engineered Safety Features to function in any accident with a loss of offsite power. The required channels of LOP instrumentation ensure that the ECCS and other assumed systems powered from the DGs, provide plant protection in the event of any of the Reference 1 (UFSAR) analyzed accidents in which a loss of offsite power is assumed. The first level is loss of voltage. This loss of voltage level detects and disconnects the Class lE buses from the offsite power source upon a total loss of voltage. The second level of undervoltage protection is provided by the four levels of degraded grid voltage relays which are set to detect a sustained low voltage condition. These degraded grid relays disconnect the Class lE buses from the offsite power source if the degraded voltage condition exists for a time interval which could prevent the Class lE equipment from achieving its safety function. The degraded grid relays also prevent the Class lE from sustaining damage from prolonged operation at reduced voltage. The combination of the loss bf voltage relaying and the degraded grid relaying provides protection to the Class lE distribution system for all credible conditions of voltage collapse or sustained voltage degradation. The initiation of the DGs on loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. . . Accident analyses *credit loading of the DG based on thi loss of offsite power during a of coolant accident .. dieiel starting and loading times have been included in the delay time with each safety component requiring DG supplied power following a loss. of offsite * *
• The LOP instrumentation satisfies Criteri6n 3 of the NRC Policy Statement. The OPERABILITY of fhe *LoP i nstrumentati ori i*s dependent upon OPERABILITY of the individual instrumentation relay channel Fun'ctions specified in Table 3.3.8.1-1. .* Each
• Fun ct i on mu s t h a v e a re q u i red n um be r of OP ERA B LE c h a n n e l s . *per 4 kV bus, with thei.r setpoints within 'specified Allowable"Values except the bus relay which does not have an Allowable Value. A degraded voltage .* channel is if its actual trip setpoint is not. within required Allowable Value. Setpoints are . . . .. *calibrated consistent with the Improved .Instrument Setpoint
• Control Program_ (IISCP) _methodology assumptions. ,1
• continued B 3.3-188 Revision No. 88 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS LOP Instrumentation B 3.3.8.1 The loss of voltage channel is inoperable if it will not start the diesel on a loss of power to a 4 kV emergency bus. The Allowable Values are specified for each applicable Function in the Table 3.3.8.1-1. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint within the Allowable Value, is acceptable. Trip setpoints are predetermined Values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., voltage), and when the output value of the process parameter exceeds the setpoint, the protective relay output changes state. The Allowable Values were set equal to the limiting values determined by the voltage regulation calculation. The setpoints were corrected using IISCP methodology to account for relay drift, relay accuracy, potential transformer accuracy, measuring and test equipment accuracy margin, and includes a calibration leave alone zone. IISCP methodology utilizes the square root of the sum of the squares to combine random non-directional accuracy values. IISCP then includes drift, calibration leave alone z6nes, and margins. The setpoint assumes a nominal 35/1 potential transformer ratio. The specifit Safety Analyses, LCO, and *Applicability discussions for Unit 2 LOP instrumentation are listed below on a Function by Function basis. In addition, since some equipment required by Unit 2 is powered from Unit 3 sources, the Unit 3 LOP instrumentation supporting the required sources must also be OPERABLE. The OPERABILITY requirements for the Unit 3 LOP instrumentation is the same as described in this section, except Function 4 (4 kV Emergency Bus Undervoltage, Degraded Voltage LOCA) is not required to be OPERABLE, since this Function is related to a LOCA on Unit 3 only. The Unit 3 instrumentation is listed in Unit 3 Table 3.3.8.1-1. 1. 4 kV Emergency Bus Undervoltage Closs of Voltage) When both offsite sources are lost, a loss of voltage condition on a 4 kV emergency bus indicates that the . respective emergency bus is unable to supply sufficient power for proper operation of the applicable equipment. Therefore, the power supply to the bus is transferred from offsite power to DG power. This ensures that adequate power will be available to the required equipment. continued B 3.3-189 Revision No. 88 BASES AP PU CABLE SAFETY ANALYSIS, LCO, and APPLICABILITY .-'.* **: LOP Instrumentation B 3.3.8.1 1. 4. kV Emergency Bus Undervoltage Closs of Voltage) (continued) The single channel of 4 kV Emergency Bus Undervoltage Closs of Voltage) Function per associated emergency bus is only required to be OPERABLE when the associated DG and circuit are required to be OPERABLE. This ensures no single instrument failure can preclude the start of three of four_ DGs. (One channel inputs to each of the four DGs.) Refer to LCO 3.8.1, "AC Sources-Operating," and 3.8.2, "AC Sources -Shutdown," for Applicability Bases for the DGs. 2 .. 3 .. 4 .. 5. 4kV Emergency Bus Undervoltage (Degraded Voltage) A degraded voltage condition on a 4 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficjent for starting large ECCS*motors without risking damage to the motors thit could disable the ECCS function. Therefore, power to the bus is transferred from offsite power to onsite DG power when there is insufficient offsite power to the .bus .. This transfer will occur only if .the voltage of the preferred and alternate power sources drop the -Degraded Voltage* Function Allowable Values voltage with a time delay) and the breakers .. trip.which causes the bus undervoltage relay to initiate the DG. ensures that adequate power be available to the retjui red equipment. * ** ** .. .., .* . Four are provided to mon_itor degraded voltage at .. four different* levels;;* These Functions.are the Degraded
• lciCA, Degraded Voltage High Settihg, and Low Settirig. These re*1 ays tnoni tor the following voltage levels with the fol lowing hme delays:* the FunC:ti ori 2 relay, 2286 -2706 vo-lts.iri approximately:.2 seconds when source voltage is redu_ced abruptly fozero*volts (.inverse**time delay); the.* Functi.on._3 relay, 3409 volts in.approximately 30_ :seconds when-source .voltage is. reduced at>rup:tl y to 2940. volts. (:inverse t_ime,g_elay);-. the 4 .relay, 3766 *-* . }836 in approxirhatelflff<secorids; *an_d the' Function 5 relay, 411.6 -4186 volts in approximately 60. The I Function) .. and 3 relays are inverse time delay relays. These relays operate :along a *repeatable characteristic. curve.* With relay operation .being inverse w_ith time, for . ** .. . -. :,_ . *(continued). '*.-* ; . ,.*::* . , . ' PBAPS' UNJT 2 B J.3-190 Revision No. 88 I BASES APPLICJ\BLE SAFETY ANALYSES, LCO, and APPLIC#\BI LITV ACTIONS* PBAPS UNIT 2 LOP Instrumentation B 3.3.8.1 2 .* 3 .* 4 .* 5. 4 kV Emergency Bus Undervoltage <Degraded Voltage) (continued) an abrupt reduction in voltage the relay operating time will be short; conversely, for a slight reduction in voltage, the . operating time delay will be long. The Degraded Voltage LOCA Function preserves the assumptions *of the LOCA analysis and the combined Functions of the other relays preserves the assumptions of the accident sequence analysis in the UFSAR. The Degraded Voltage Non-LOCA Function provides assurance that equipment powered from the 4kV emergency buses is not damaged by degraded voltage that might occur under other than LOCA conditions. This degraded grid non-LOCA relay has an associated 60 second timer. This timer allows for offsite source transformer load tap changer operation. Degraded voltage conditions can be mitigated by tap changer operations and other manual actions. The 60 second timer provides the time for these actions to take place.
• The degraded grid voltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required equipment. The Time Delay Allowable Values are long enough to provide time for. the offsite power supply to recover to . normal voltages, but short enough to ensure that sufficient power is'available to the required equipment; Two channels (one channel per source) of 4 kV Emergency Bus Degraded Voltage (Functions 2, 3, 4, and 5) per associated . bus .are required to be OPERABLE when the associated DG and ** offsite -circuit are required to be OPERABLE. This ,ensures no single in.strument failure can preclude.the start of three 9f four DGs*(each logic: inputs.to-each of.the* four DGs).* Refer to *LCO and LCO 3 .. 8.2 for Applicability Bases for the DGs . . A. Note *been pr9vided .{Note l) to modifythe ACTIONS .* rel at ed. to LOP i nstrumeritat ion channels, Sect iOn 1_. 3, : ... . Completion. specifies that once .a Condition has been **.entered; subsequerit divisions,. subsystems, components, or. variables expressed in the Condition, d.iscovered to be . inoperable or not within. l,1mits, will not result in separate . entry into the Sectfon 1.3 also specifies that . Actions of the Condition continue 'to apply for each additional failure; *with Completion Times based on fnitial ** * * (continued) .. B 3 .. 3q91 Re.vision .5 BASES . (continued) -. . . PBAPS UNIT 2 .. * .. *** LOP Instrumentation B 3.3.8.1 entry into the Condition. However, the Required Actions for* inoperable LOP instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable LOP instrumentation channel. A.1 Pursuant to* LCO 3.0.6, the AC Sources-Operating ACTIONS would not have to be entered even if the LOP instrumentation inoperability resulted in an inoperable offsite circuit. Therefore, the Required Action of Condition A is modified by a Note to indicate that .when performance of a Required Action results in the inoperability of an offsite circuit, Actions for LCO 3.8.1, 11AC Sources-Operating," must be inunediately entered. *A Unit 2 offsite *circuit is considered to be inoperable if it is not supplying or not capable of supplying (due to*loss of autotransfer capability) at least three Unit 2 4 kV emergency buses when the other offsite circuit is providing power or capable of supplying power to all four Unit 2 4 kV emergency buses. A Unit2 offsite circuit is also considered to be inoperable if the Unit 2 4 kV emergency buses being powered. or capable of being powered from the two offsite circuits are all the same when at least one of the two circuits does riot provide power or is not capable of supplying power to all four Unit 2 4 kV emergency.buses. Inoperability of a Unit 3 offsite circuit . is the same as described for a Unit 2 offsite circuit, except that. the circuit path is to the Unit 3 4 kV emergency buses required to be OPERABLE by LCO "Distribution Systems--Pperating.11 The Note allows Condition A to provide *requirements for the loss*of a LOP instrumentation channel without regard to whether an offsite circuit is rendered inoperable. LCO 3.8.1 provides appropriate restriction for .an inoperable offsite circuit. Required Action A.I is appltcable when one 4 kV emergency bus has one or two required Function 3 (Degraded Voltage . Hfgh Setting) channels inoperable or when one 4 kV emergency bus has one or two required Function 5 (Degraded Voltage Non-LOCA) channels In this Condition, the affected Function may not be capable of performing its intended function automatically for these buses. However, the operators would still receive indication in the control . room degraded voltage condition on the unaffected buses and a manual transfer of the affected bus* power supply to {continued) B 3 .3"'.'.192 Revision No.:5-.*.,'..

BASES ACTIOl\JIS I I PBAPS. UNIT_-2 A.I (continued) LOP Instrumentation B 3.3.8.l the alternate source could be made without damaging plant equipment. Therefore, Required Action A.I allows 14 days to restore the inoperable channel(s) to OPERABLE status or place the inoperable channel(s) in trip. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore design trip capability to the LOP instrumentation, and allow operation t'o continue. Alternatively, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in DG initiation), Condition D must be entered and its Required Action taken. The 14 day Completion Time is intended to allow time to restore the channel(s) to OPERABLE status. The Completion Time takes into consideration the diversity of the Degraded Voltage Functions, the capabilities of the remaining OPERABLE LOP Instrumentation Functions on the affected 4 kV emergency bus and on the other 4 kV emergency buses (only one 4 kV emergency bus is affected by the inoperable channels),-the-fact that the Degraded Voltage-High Setting and Degraded Voltage Non-LOCA Functions provide only a marginal increase in the protection provided by the voltage monitoring scheme, the low probability of the grid in the voltage band protected by these Functions; and the ability of the operators to perform the Functions manually. B.1 Pursuant to LCO 3.0 .6, the AC Sources -Operating ACTIONS would not have to be entered even if the.LOP instrumentation _ resulted in an inoperable offsite circuit. -Therefore, the Required Action of Condition B is modified by a No_te to indi_cate that when performance of a Required * . Act.ion results in the inoperabil ity of an offsite circuit, Actions for LCO "AC Sources-Operating," must be _immediately entered. A Unit 2 offsite circuit is considered to be_ inoperable if it is hot *supplying or not _ supplying (due to loss of autotransfer capability) at.least three Unit 2 4 kV emergency buses when the other offsite circuit is providing power or capable of supplying power_ to all four Unit 2 4 kV emergency A Unit 2 offsite -circuit is also to be inoperable if the Unit 2 -4 kV emergency buses being powered or capable of being powerE!d from the two off site circuits are al 1 the *same when at least one of the two-circuits does not provide power or (continued). B 3.3-193 Revision No. 5 BASES ACTIOHS PBAPS UNIT 2 B.1 (continued) LOP Instrumentation B 3.3.8.1 is not capable of supplying power to all four Unit 2 4 kV emergency buses. Inoperability of a Unit .3 offsite circuit is the same as described for a Unit 2 offsite circuit, except that the circuit path is to the Unit 3 4 kV emergency buses required to be OPERABLE by LCO 3.8.7, "Distribution Systems -Operating." This allows Condition B to provide requirements for the loss of a LOP .instrumentation channel without regard to whether an offsite circuit is rendered inoperable. LCO 3.8.1 provides appropriate restriction for an inoperable circuit. Required Action B.1 is applicable.when two 4 kV emergency buses have one required Function 3 (Degraded Voltage High Setting) channel inoperable, or when two 4 kV emergency buses have one required Function 5 (Degraded Voltage LOCA) channel inoperable, or when one 4 kV emergency bus has one required Function 3 channel inoperable and a different 4 kV emergency bus has one required Function 5 channel inoperable. In this Condition, the affected Function may be capable of performing its intended function automatically for these buses. However, the operators would still indicati-0n in the control room of a degraded voltage condition on the unaffected buses and a manual ** transfer of the affected bus power supply to the alternate source could be niade without damaging plant equipment. Therefore, Required Action B.1 allows 24 hours to restore the inoperable channels to OPERABLE status or place the inoperable channels in trip. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore design trip capability to the LOP instrumentation, and allow operation to continue. Alternatively, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in DG initiation), Condition D must be entered and its Required Action taken.

• The 24 hour Completion Time is intended to allow time to restore the channel(s) to OPERABLE status. The Completion *Time takes into consideration the diversity of the Degraded Voltage Functions, the capabilities of the remaining OPERABLE LOP Instrumentation Functions on the affected 4 kV . emergency buses and on the other 4 kV emergency buses (only
• two 4 kV emergency buses are affected by the inoperable
• channels), the fact that the Degraded Voltage High Setting and Degraded Voltage Non-LOCA Functions provide only a (continued) B 3.3-194 Revision No. 5

---,---------BASES ACTIONS .*. ,* ... *.* .*. PBAPS UNIT 2 B.L (continued) LOP Instrumentation B 3.3.8.1 marginal increase in the protection provided by the voltage monitoring scheme, the low probability of the grid operating in the voltage band protected by these Functions, and the ability of the operators to perform the Functions manually. Pursuant to LCO 3.0.6, the AC Sources-Operating ACTIONS would not have to be entered even if the LOP Instrumentation inoperability resulted in an inoperable offsite circuit. Therefore, the Required Action of Condition C is modified by a Note to indicate that when performance of the Required Action in the inoperability of an offsite circuit, Actions for LCO 3.8.1,*"AC Sources-Operating," must be immediately entered. A Unit 2 offsite circuit is considered to be inoperable if it is not supplying or not capable of supplying (due to loss of capability) at least three Unit 2 4 kV emergency buses when the other offsite circuit is providing power or capable of supplying power to al 1. four Unit 2 4 kV emergen*cy buses. A Unit 2 offsite circuit is also considered to be inopercible . if Unit 2 4 kV buses being powered or capable qf being powered from the two offsite circuits are all the cit least one of the does not provide power cir is not capable of supplying power to all four . Unit 2 4 kV emergency buses, Inoperabi 1 ity of a Unit *3 offsite circuit is the same.as for a Unit 2 offsite' circuit, except that the circuit path is to the Unit 3 buses reqGired to be OPERABLE by LCQ 3. 8 .), "Di stri but:i ori Systems .-Operating.;, Tbe Note aliows ]ciriditiori C to provide for the loss of a LOP in*strumeritation 'channel without regard to whether* an

• offsite circuit is. inoperable.*. LCO 3.8.1 app_rcipriate restriction for an i hoperabl e off site circuit. Requireil Action:*C .. T is.*applicable when orieor.more 4 kV . . emergency 'buses Ii ave *:one or:mor.e. required Fund ion 1, 2, or 4 (the Loss of V,_olta'ge, the Degraded Voltage L*ow Setting, and the Degr:aded.Voitage LOCA Functions, respectiv.ely) channels inoperable ..
• or* when cine* 4 kV emergency bus has on*e required-.Fµnction 3 (Degraded Voltage High Setting) channel _a,nd. one req'ui red Function 5. (Degraded Voltage Non-.LOCA) ... *. C'.hann'el inoperable, or When'.any combination Of three or more* required Fu.nctfon 3 .and/o*r Functici.n 5 channels* are* I inope*rable'.* In this Conditicin, fhe affe'cted Function may not be* e: * * . (continued) "* '.-**B 3.3-195 Revision No. 77 BASES ACTIONS: . . . SURVEILLANCE-. PBAPS UNIT 2 C.l (continued) LOP Instrumentation B 3.3.8.l of perfo.rmi ng the intended function and the potential consequences associated with the inoperable channel(s) are greater than those resulting from Condition A or Condition B. Therefore, only 1 hour is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action C.l. Placing the inoperable channel in trip would conservatively
• compensate for the inoperability, restore design trip capability to the LOP instrumentation, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation), Condition D must be entered and its Required Action taken. The Completion Time is based on the potential consequences -associated with the inoperable channel(s) and is intended to allow the operator time to evaluate and repair any discovered The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. . . If any Required Action and associated Completion Time are not met, the associated .Function is not capable of performing the intended furiction. Therefore, the associated DG('s) is declared inoperable immediately. This requires
• entry into applicable Conditions and* Required Actions of
• and LCO 3.8.2, which provide approptiate actions for* the* i noper*abl e DG ( s) . . _As n.oted* at the the SRs, *the SRs for each Unit 2-LOP instrumentation Function are located in the SRs column of Table SR 3.3.8.-1.5 :isapplicable only to the Unlt 3 LOP instrumentation. * * . also modified by a Note to indicate *. that when a. channel is placed. in an inoperable status solely for performance ()f required Surveillance, entry into . ated Condit ions and Required Actions may be* delayed for up 2 hours* provided:: (a) for FunctiOn 1, the -assoc"i ated Function maintains* initiation ity for . . . . . . Ccontinuedl B 3.3-196 Revision No. 5 *:.*.-* ..

BASES SURVEILLANCE REQUIREMENTS (continued) UN IT 2 LOP Instrumentation B 3.3.8.1 three DGs; and Cb) for 2, 4, 5, associated Function maintains undervoltage transfer for three 4 kV emergency buses. The loss of function for one DG or undervoltage transfer capability for the 4 kV emergency bus for this short period is appropriate sirice only three of four DGs are required to start within the required times and because there is no appreciable impact on risk. Also, upon completiori of the Surveillance, or expiration of the i hour allowance, channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken,

• SR and SR 3.3.8.1.3 A CHANNEL FUNCTIONAL TEST is performed-on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance frequency contro11ed under the Surveillance Frequency Control Program. SR* 3.3.8.L2 A CHANNEL CALIBRATION is a complete check of. the relay circuitry -associated time delay relays .. This test verifies the channel responds to the measured parameter, within the necessary*range and accuracy. CALIBRATION leaves the channel adjusted to account instrument drifts between successive calibrations, consfstent with the assumptions of the current plant specific setpofnt methodology. The Surveillance Frequency is controlled under the Frequency Control Program: . . B continued BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES : . . PBAPS UNIT .2 SR 3.3.8.1.4 LOP Instrumentation B 3.3.8.l The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific* channel. The system functional testing performed in LCD 3.8.l and LCD 3.8.2 overlaps this Surveillance to provide complete of the assumed safety functions. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.8.1.5 With the exception of this Surveillance, all other of this Specification CSR 3.3.8.1.1 through SR 3.3.8.1.4) are applied .only to the Unit 2 LOP instrumentation. This is provided to direct that the appropriate Surveillance for the required Unit 3 *LOP instrumentation are governed by the Unit 3 Technical Specifications.* Performance of the applicable Unit 3 Surveillances will satisfy Unit 3 requirements, as we1l as satisfying this Unit 2 Surveillance Requirement. required by the applicable Unit 3 SR also governs performance of that SR for Unit 2. 1. UFSAR, Chapter 14. B 3.:3-198. Revision No>-86 *1 ., .1,

.. *:,:*-RPS Electric Power Monitoring B 3.3.8.2 B 3.3 . INSTRUMENTATION B 3.3.a.2* Reactor.Protection System (RPS) Electric Power Monitoring . BASES BACKGROUND .**' .-****.i .. ** .. *.-:: . . RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG). set or an .alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus against unacceptable voltage and frequency conditions (Ref. I) and. forms an important

• part.of the primary success path of the essential safety ciy-cuits .. Some of the essential equipment powered from the RPS buses includes the RPS logic and scram solenoids. RPS electric power monitoring assembly will detect any abnormal high or low voltage or.low frequency condition in the outputs of the two MG set.s or the alternate power supply and will de-energize its respective RPS bus, thereby causing all safety functions normally powered by this bus to *de-energize.. * . I.n the event of of an RPS Electric Monitoring .System (e.g., both in series electric power monitoring assemblies), the RPS loads ma.Y experience significant . effects from the unregulated power supply. Deviation from the nominal conditions can .potentially cause damage to the scram solenoids and other Class IE devices.
• of a low condition, the scram solenoids can.chatter and potentially lose their pneumatic control capability; resultingin a loss of primary scram action. . . . . ' . . In.the event of an overvoltage condition, the RPS logic rel ays and scram solenoids* may experience a voltage higher than* their design voltage. If.the overvciltage condition . persists for an extended time period, it *may cause equipment
• degradation and the loss of plant safety function. Two redundant Class IE circuit breakers are connected in .series between each RPS bus and its MG set, and between each . RPS bus and its alternate power supply if in service. Each of these circuit breakers has an associated independent set * (continued) * * .. UNIT.2:' B 3.3-I99
• Revision 1 .. *. . ' . *. * .
  • .:-. BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES LCO ..* .,-.*'--.. ** .. . -PBAPS UNIT 2 RPS Electric Power Monitoring B 3.3.8.2 of Class IE overvoltage, underfrequency relays, time delay relays (MG sets only), and sensing logic. Together, a circuit breaker, its associated relays, and sensing logic constitute an electric power monitoring assembly. If the output of the MG set or alternate power supply exceeds predetermined limits of overvoltage, undervoltage, or underfrequency, a trip coil driven by this logic circuitry opens the circuit breaker, which removes the associated power supply from service. The RPS electric power monitoring is necessary to meet the assumptions of the safety analyses by ensuring that the equipment powered from the RPS buses can perform its intended function. RPS electric power monitoring provides *protection to.the RPS components that receive power from the RPS buses, by acting to disconnect the RPS from the power supply under specified conditions that could damage the RPS equipment. *
• RPS electric power monitoring satisfies CriteriOn 3 of the . NRC Pol icy Statement. * .*. The OPERABILITY of each RPS electr.ic power monitoring . assembly is dependent on the OPERABILITY of the overvoltage, undervoltage,-and underfrequent:y logic, as well as the . OPERABILITY of the associated circuit breaker. Two electric power monitoring' assemb.l i es are required to be OPERABLE for
• each ihservice power supply. This provides redundant *protection against any abnormal voltage or frequency to ensure* that no single RPS electric power monitoring *assembly failure can preclude* the function of RPS components. Each "inservtce electric power monitoring . . assembly's trip lOgic are required to be within * *the speCified Allowable Value. The actual setpoint is> calibrated :conslstent wi:th ap.pl icabl e set point methodology assumptJons .. . *Aliowable Values for ea.ch RPS power monitoring ass.e_mbly. trip logic (refer to SR 3.3.8.2.2). . Trip setpoi nts are-spec if i ed i h design documents. The tri.p selected*based on engineering judgement and operattorfa} .. experience to ensure that the setpoints do not : exceed the Allowable Valu*e between CHANNEL CALIBRATIONS.** _Operation with a trip setting less coriserv(ltive than the trip setpoint, but within its.Allowable:Value, is ,. '* .. " :* ,*,* .. *-. *:,-:.*" (continued) ' ":* .. ,*_, . .,: B
• Revision** No.* I **. '.

BASES LCO (continued) . APPLICJ\BILITY . -* .. ;*._,-' . PBAPS'LINIT *2 RPS Electric Power Monitoring B 3.3.8.2 acceptable. A channel is inoperable if iis actual trip setting is not within its required Allowable Value. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., overvoltage), and when the measured output value of the process parameter exceeds the setpoint, the associated device changes state. The overvoltage Allowable Values for the RPS electrical power monitoring assembly-trip logic are derived from vendor specified voltage requirements. The underfrequency Allowable Values for the RPS electrical power monitoring assembly* trip logic are based on tests performed at Peach Bottom which concluded that the lowest frequency which would be.reached was 54.4 Hz in 7.5 to 11.0 seconds depending load. Bench tests were also performed on RPS components (HFA relays, scram contactors, and scram solenoid valves) under conditi-0ns more severe than those

• expected in the pl ant { 53 Hz during 11. 0 and 15. O second intervals). Examination of these components concluded that the functioned:correctly under these conditions. The undervoltage Allowable Values for the RPS electrical power mon.itoring assembly trip logic were confirmed to be acceptable through testing. Testing has shown the scram pilot solenoid valves can be subjected to voltages below 95 volts with no degradation in their ability_to perform their safety function. It was concluded the RPS logic relays and scram contactors will not be adversely affected by voltage below 95 volts since these components will dropout under .these voltage conditions thereby satisfying their safety fi.mction*.
• The*operationof the RPS electric power.monitoring is essential to disconnect the_ RPS components
• from the *MG set* or alternate. power supply during abnormal
• vo-1 tage *or frequency cond.it ions. Si nee the *degradation of a rionclass lE source supplying power to the RPS bus can _occur as a result of any random single the OPERABILITY of the* RPS electric power monitoring assemblies is required * * . when the RPS components are required to be OPERABLL This results in the RPS Electric. Power Mani tori ng System . * .. . .* :OPERABILITY being required in MODES 1. and 2; and in MODES 3, 4, and with any control rod withdrawn from.a core tell * . con ta i nfng *one o*r more fuel
• as seilib 1 i es. * * (continued} -. _ . .-. B 3i3:-201 Revision No .. 1 ---'*.* ..

BASES (continued) AC TI OMS ', .. 1 ' ' PBAPS UN IT 2 RPS Electric Power Monitoring B 3.3.8.2 If one RPS electric power monitoring assembly for an inservice power supply (MG set or alternate) is inoperable, or one RPS electric power monitoririg assembly on each inservice power supply is inoperable, the OPERABLE assembly will ,still provide protection to the RPS components under degraded voltage or frequency conditions. However, the reliability and redundancy of the RPS Electric Power Monitoring System is reduced, and only a limited time (72 hours) is allowed to restore the inoperable assembly to OPERABLE status. If the inoperable assembly cannot be restored to OPERABLE status, the associated power supply(s) must be removed from service {Required Action A.I). This places the RPS bus in a safe condition. An alternate power supply,with OPERABLE powering monitoring assemblies may then be used to power the RPS bus.

• The 72 hour Completion Time takes into account the remaining OPERABLE* electric power monitoring assembly and the low probability of an event requiring RPS electric power monitoring protection occurring during this period. It allows time for plant operations personnel to, take, corrective actions or to place plant in the required conditi,on in an orderly manner and without challenging plant systems.
• Alternately, if it is not desired to remove the power supply from service {e.g., as in the case where removing the power supply{s) from service would result in a scram or Condition C or D, as applicable, must be entered and its Required Actions taken. If both power monitoring assemblies for an inservice power supply {MG set or alternate} are inoperable or both power monitoring assemblies in each inservice power supply are inoperable, the system protective function is lost. In this condition, I hour is allowed to restore one to OPERABLE status for each inservice power supply. If one inoperable assembly for each inservice power supply cannot be restored to OPERABLE status, the associated power supply{s} *must be removed from service within I hour {Required Action B.l}. An alternate power supply with OPERABLE assemblies may then be used to power one RPS bus. **. (continued) Revfsion No. 1 BASES ACTIONS PBAPS *uN IT 2 .B.......l (continued) RPS Electric Power Monitoring B 3.3.8.2 *The 1 Completion Time is sufficient for the plant operations personnel to take corrective actions and is because it minimizes risk while allowing time for restoration or removal from service of the electric power monitoring assemblies. Alternately, if it is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C or D, as applicable, must be entered and its Required Actions taken . . If any Required Action and associated Completion Time of Condition A or B are not met in MODE l or 2, the plant must be brought to a MODE in which overall plant risk is minimiied. The shutdown is accomplished by placing the plant in MODE 3 within 12 h6urs. Remaining in the* Applicability of the .LCO is acceptable because the plant in MODE 3 is to or lower than the risk in MODE. 4 (Ref. 3) and betause the time spent in MODE 3 to perftirm the necessary repairs to restore the system *to OPERABLE *status will be short. However, entry into MOD£ 4 may be made as it is an low-risk The aliowed Completion T.ime is reasonable, based on operating . experience, to reach the tequired plant conditidns from fµll power conditions in an orderly manner and with6ut challenging plaht . D .1 . If* Required Action associated Completton Time of Condition A or B are not met ih MODE 3, 4, or 5 with any control rod withdrawn from a core* cell containing one or. fuel assemblies, the operator must immediately initiate action to fully *insert all insertable control rods i.n core cells containing one or more fUel assemblies .. Required: *Action D.l in the least reactive condition for the reactor tore and ensures that safety function of the RPS* (e.g., scram of* control rods) is not required .. (Continued) B. 3.3-203. * " Rev i s ion No. 6 6
• BASES (continued) SURVEILLANCE REQUIREMENTS SR 3.3.8.2.l RPS Electric Power Monitoring B 3.3.8.2 A CHANNEL FUNCTIONAL TEST is performed on each overvoltage, undervoltage, and underfrequency channel to ensure that the entire channel will perform the intended Any setpoint adjustment shall be consistent with design documents. As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is only requ{red to be performed while the plant is in a condition in which the loss of the RPS bus will not jeopardize steady state power operation (the design of the system is such that the power source must be removed from service to conduct the Surveillance). As such, this Surveillance is required to be performed when the unit is ih MODE 4 for 24 hours and the test has not been performed within the Frequency specified in the Surveillance Frequency Control Program. This Surveillance must be performed prior to entering MODE 2 or 3 from MODE 4 if a performance is required. The 24 hours is intended to indicate an outage of_ sufficient duration tb allow for scheduling and proper performance of the Surveillance. The Note in the Surveillance is based on guidance provided in Generic Letter 91-09 (Ref. 2). The Frequency is under the Surveillance Frequency Control Program. SR 3.3.8.2.2 and SR 3.3.8.2.3 CALIBRATION is a complete check of the and applicable time delay relays. This test that the channel responds to the measured parameter within the necessary range and accuracy*. CHANNEL CALIBRATION the channel adjusted between successive calibrations consistent with the plant design documents. The Surveillance Frequency is controlled under the Sur_veillance Frequency Control Program. *SR 3.3.8.2.4 P BA P S U N I_ T 2 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, the logic of the system will automatically trip open the power monitoring assembly. Only one signal continued B 3._3-204 Revision No. 86 I BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2. RPS Electric Power Monitoring B 3.3.8.2 SR 3.3.8.2.4 (continued) per power monitoring assembly is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class lE circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable. The Frequency is controlled under the Surveil l.ance Frequency Control Program. 1. 2. UFSAR, Section 7.2.3.2. NRC Generic Letter 91-09, "Modificati6n of Interval for the Electrical Protective in .Power Supplies for the Reactor Protection Syitem." 3.,. NEDC-32988-A, Revision 2; Technical Justification to Support' Modification to Selected Required *End: states for 2002. ' ., .. . *.:. ,.* :* '* .. ;. . ,*'* B J.3-205 Revision No,, 86

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• SPECIFICATIONS (UNIT #2 BASES) .* .. * . . . *. -.* . . . . . . *-.---. . -. . -. -:; ' : : ': . :* -. . :"; . --. :*-*,. :* ,*\ . . . .,. -* , ... __ ., . ** . . . ** .. *.*.*_ .... :* ..... * * ... * *. .":--' .. **"7---* ... . *. .. * . : . . ' -. -.-: __ ._. .;, . . . " . -.* .* . *. -. : .-* .. -.-* ... ::-. '* .* *,'_ .' . :_ **. . ; -. -. . . . *... . . .. -.. -* --... . . .. ..... _. --. . ' -* . ) .. ' .. :. -* .. , . . ... . . . . *.* . . .. .. . . . . . ' . . -_,. . . *_-.*

PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B TABLE OF CONTENTS page(s) i ..................................................................................................................... Rev 25 ii .................................................................................................................. Rev 106 B 2.0 SAFETY LIMITS (SLs) page(s) 2.0-1 ................................................................*...............*............................ Rev 98 2.0-2 ....................*...................................................................................... Rev 128 2.0-3 ..........................................*...............................................**............... Rev 128 2;0-4 ......................... *, ..................................................................... : .............. Rev 47 2.0-5 ...*.........................*.......................*............................... ; ....................... Rev 75 2.0-6 ........................................................................................................... Rev 128 2.0-7 ............................................. : ............. : ................................................. Rev 75 2.0-8 .................*......*..............................................................*..................... Rev 57 2.0-9 **. ; .......................................................................................................... Rev 75 2.0-1 o ....................... .' ..... , ............................................................ ; .................. Rev 75 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY page(s) 3.0-1 ....***.*...*.......*............... : ......................*.*...*........*..*............. * **............... Rev 100 . 3.0-5 ....*..... ; ............................................*..........*.............*............................ Rev 52 3.0-5a .................*......................................*.....*...............................*........*... Rev 52 3.0-6 ............. ; *..... ....................... : ... : .....*................................ ; .......**............. Rev 52 3.0-9 ....................*.*................* : .............*.......................................*..*.......... Rev 100 3.0-9a ................. : .*.....*.. , ............................................................ : *.. , ............ Rev 100 3.0-9b ... ,* ... , .....*.....*....... : ........... : *.... , .... ; ......................*....*..*..*.*....... : .......... Rev 107 3.0.:12 ...*.. ; ...... ; .. : *.......* , ................. : ... ; .......... .... ; .....*. ;.: ... .............*................. Rev 6 3.0-13 *........ : .*. , .........*..........*........... ; .. : ...................................... ,"" ........ ; .. ; .. , *.... Rev 1 *3.0-14 .... ; .. : ....... * ... .: .......... ; .... ; ....................... , ............... , ..................... : .............. Rev 52 3.0-1S* .......... ....... ; ......................................................... ; .............. ............... Rev 52 B 3.1 REACTIVITY CONTROLS:VSTEMS . . . . -. 3.1*5*-: ...*.....*...............*.**........**. : ...*. : .... : .............*.. * ....... u ............. -******************** Rev 72 * ........... ................ ;* *. : ....* ...... ::: .......... ; ........ ; ....... * ... ; .... ; ... : ...................... Rev 72 page(s) .3.1-7 *... , .................. * ....*................. ; .. , ..*. ; .. ,.* *........*.......*... :., ........................ , .... Rev 72

• 3.1-8 ...... -............. , .............. .-... : ...*.............**....*... ; .......*. ;.; ....................... , .... R.ev '113 3.1-9 .; ... *.* .... * ...... ... : ...... : ... ,: ........ ; .. ; ..... .....*........ : *............ ; .. , ... * ...............*....... Rev.113 .3.1-1*0 ..... *.. : ...... : ... -.. : .......................... * ... :.; ................ ....... : .... ;; ..*... ; ..... : ........*. Rev 9A!l 3.1-11 ...... : ... ; ..***.. ; ......... : .. : ....... : ..**.... .-.................. ....... -; ................................ Rev 113 *. .... .. .-: ..... *.: ...... ': ............................. : ........ : ....................... ........ : . .-.... ; ....... Rev 49 ** 3.1-15 ..........* *.: ............... :*: .*..**.*.. * .*............*.**.**. : .*.*.....*... * .* *.,: ............*....*........... Rev 2 3.1-16 *... : ..........*.. :* .....*...*....... : ...............*........... ;: .......*....* ; ............. * ......... : .... Rev 79 *3.1-17 ...... _ .. , .......... : .... : ...... ....* ; ......... : .*.. 63 . 3.1-18 .... : *..... , .* ..... : *...... .-... ; .*....... ;.:* ... ; ...........*..............*........... ; *.............. Rev 63 .. 3:'1'"19 .: .*..... .".' ... , ... , .. :.;.; *....*. _ .... .............. , *. ; .*...***..*. ; *.....................**... , ..... ; ........ Rev 86.
• 3.1-20 ...**.....*... : .. : ................................... ; ....................*.... : .................. ; ........ : ... *Rev 79 3.1-21 _ *..** : .......**.... ; *.. , .... '.: ............. .": . .' .* : .............. : .. ,.;;: ......... :: ............................. .'Rev 63 3.1.:.23* ........... :, ..... ,: *. * .. :* ... : .*.*. ; ............................. : ............................ , ......*......... Rev 49 .' , 3.1-25 * *..*...*. :; .... , .. .' ......*.............*....*..*......... :;.; ...*.............. : ... : .....*.......... ,: ...... Rev 57 PBAPS UNIT2 i
• Revision No.139
• PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.1 REACTIVITY CONTROL SYSTEMS (continued) page(s) 3.1-26 ................................................................................... ....................... Rev 86 3.1-27 ........................................................................................................... Rev 57 3.1-28 ................................................... ; ....................................................... Rev 72 3.1-29 ........................................................................................................... Rev 49 3.1-31 ............................ ; ............................................................................... Rev 2 ......... ................... * ............................................................................... Rev 2 3.1-33 .......................................................................................................... Rev 86 3.1-34 ............................................................................. ............................. Rev 75 3.1-35 ......................................................................................................... Rev 114 3.1-35a ...................................................... ; .................................................. Rev 63 3.1-36 ........................................................................................................... Rev 63 3.1-37 ............................................ : ............................................................... Rev 86 . 3.1-38 ....... ................................................................................................... Rev 61 3.1-39 ......................................................................................................... Rev 114 3.1-40 .; ....................................................................................................... Rev 114 3.1-41 ............................................... ."; ......................................................... Rev 114 3.1-42 ........................................................................................................... Rev 114 3.1-.43 ........ , ................................................................................................ Rev 114 3.1-44 ........................... , ... _ ............................................................................ Rev 114 3.1-45 ., .................................................... , ................................................... Rev 114 3.1-46 .................................................... ; .................................................... Rev 114 3.1-47 ............. : ............................ , .......... , ................................................... Rev 130 3.1-48 .................... -...................................................... ; ................................. Rev 75 3*.1-49 ........................................................... ........... ; .................................... Rev 57 3.1-50 ............................ ................... -... ........................ , ......... , .................... Rev 57
• 3.1-51 ....................................................... * ................................. ;; .................. Rev 86 3.1-52 ............ -................................. , .. _ ........................................................... Rev 86 B 3.2 POWER DISTRIBUTION LIMITS page(s) 3.2-1 ....................... , ...................................................................................... Rev 49 3.2-2 ********'.****'.************** .. **********************,****** .. ******* .......... , ............................... Rev 49 3.2-3 ........ *:.:: ........ .-............................. .......................................... : ........... * .. Rev 114 3.2-4 .......................... ." ................................................................................. Rev 114
• 3.2-5 .*..**. ; **..... , **. , *.* .*.... ;:.;; **.. .-. .-.... ;; ** :*: *. .***.* ** ...... : *. .'.-; ..*..*** , ....... :* ......... ,. *.*.*. Rev 49 3.2-7 ......... : ........ :: ........................ , ........ -.................................. ..................... Rev 114 3.2-8 .' **.*.***.**.** ; .*.**...*.**.** ......... **.*****.* *.* ; .*** ; ..** : .................................... Rev 114 3.2-9 : .*. , ..***. _ .. H**************;* ... .............. .. '.'"'"""""." .......................... _ ................... ;, Rev .1.14 3.2-1 O ....... , ... , ... _:: ... : ............ , .......... , ............... ; ** _ ........................................ ; ..... Rev _114
• 3.2-11 ........... _,, .. -.; ................. * .. ....... ,.: ...... ; .................. '. ............ '. .. ............ _ ** -Rev.101 3.2-12 ......... ;; ........................ , .... ; .......... , ...... , ............... ; ..... ; ......................... *Rev114* .3.2-12a* ...... _ ... : ............. * .... .. , .......................................... ; ... : ........................ Rev 114 3.2-13 ... : ................ , ............................................................... ..... :.-..... * ........ Rev 114 . -. PBAPS UNIT-2 ii Revision No. 139 I. I PBAPS UNIT 2 -LICENSE NO. DPR-44 ' ' TECHNICAL SPECIFICATIONS BASES. PAGE REVISION LISTING 83.3 INSTRUMENTATION page(s) 3.3-1 .......................................................................... ; .** : .................. :: ........ Rev 134 . 3.3-5 6 (inclusive) ................. ; ............. ; .......................... _ ****** ,.,-.* ; ................ Rev 24 3.3-7 .................................................................... ;: ............ : .. -...................... Rev 124 3.3-8 ...................................... : **** ;,.* ................................... ...... , .................. Rev 114 3.3-9 ................... , .................... _ .... : ............... ,.: ........................... ; ......... , **** ;. Rev 114 3.3-10 ........................................................................................... * ................ Rev 36 3.3-11 ....................................................................................... : ................... Rev 36 3.3-12 .......... ; ....................... : ............... -.; ........................................................ Rev 50 3.3-12a .: ................. * ................. ; ......................... : ........... ; ** :.* ................ : .. * ..... Rev 123 *3.3-12b .................... : ....................... : ........... , ................................. ; .......... * ....
• Rev*123 *3.3-12c ................................................. ; .......................... ; .......................... Rev 123*
• 3 *. 3-17 **** : ................ , ....... _ ** : ............................................................................ _Rev 87 3.3-18 .: ......... ; ................... ; ......... : ................................................................ Rev 114 3.3-19 ...... : .......................................... : ....................................... ; ................ Rev 114 3.3-20 *.*** , ........... ;: ** ; ............................. : ******** ; ................................ ; ...... ...... _Rev 134 . 3.3-21 ....................................... :,; ..................... * ................ ; .......................... Rev 134 3.3-23 .; ........ ; ................................................................................................. Rev 36 * . 3.3-24 ....... .**** _ ...... ; ...... : ............................................ , .................................... Rev 50 3.3-25 ......... : ................. ; ........................ ; ............................................ ; .......... Rev 50 3.3-26 .: ............ * ..................................... ....................................................... Rev 36 3.3-27 .:; ....... *: ........... ; ......... ; ........ ; .*.. :.: ............ -................... ; ................. ; ....... *.Rev 123 ........ :.: ....... ; ........................... ; ........... : ........ ................................... Rev 123 ................... : ................................. : ......... : .............. ....... ;; ........ '. .... Rev 124 3.3-28 .......... ... _ ............. : .*.* : .......... : ........ : ............. _ ......................................... Rev 123 * ** 3.3-29 ......... ; ............................... ;*: ..................... ; .............. ;: ........................ Rev 114 *3:3-30 *** ....................... ................... ; ......................... ; ***** _; ........ _ .... , ............ Rev 114 *, 3.3-31 * .............. ;;;, .... : ...... : ........ ; ........................................................ : ......... Rev 114 . *3.3-32 ............... : ........ ; ** ; ..... * ...... _ ........ '. ** ; ........................ : .... , .* , .... ; .......... :,;* ..... Rev 114 3_3.;33 ............. ; ................................ * ...................... , ..................... ; ......... ; .... Rev 114 * . *-.3.3-34 .;._ ............. ;; .. : .......... _ ............ ' ...... : ... , ............................. '.: ........ : .......... ; ... Rev, 125 . * .. 3.3-35 .... :-............................................ * ...... * ... .-; .............................................. Rev 123 * * .. 3.3-35a ;: ** *: ........ :.-.............. .**.*** ; .... : ....... : ............ ; ........... _ ***. _._. ....... _ ................ Rev 123 3.3-35b * .; ..... ; ....... ; ***.* : ....... _ ..... ; .................. : ..................................... _ .......... : ... Rev -123 3*.3-36
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PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.3 INSTRUMENTATION (continued) page(s) 3.3-62 *.*.***..*.*.*....*.*.*....**...***.**.***....*.*.**** ***...*.*.**.*.**.**..**** : **.*..*.*****....**.**. Rev 114 3.3-63 *.*..**......*.*.*...**.*.*.*...*............**.*.*.*.*...*.....*.***.**..***..***.****..*.********..*.**** Rev 86 3.3-64 .**.**.**.**.*.*.***.*.*.**...*.*..*..*.........*.**.**...*...*.***...*...**....*.*.*..***.**.*****.**...*. Rev 86 3.3-67 *.***...*.**.*.*.*.....*.**.**........*...*..*..*.**.**...*.....*..**.**..***....*....*.**....*..*.**..***.*. Rev 7 3.3-68 ..***....***...*.*..*..*.**.**.*...****..*...**.****.**.***..*.** ; ***......*.**.**.*.....*.**.*.*....**..*..* Rev 3 3.3-69 .*.***.*.******.*...*.*....*.**..*.*.....**.*.***.**.**...*...*....****...***.....*.**...*.*.****...*..*... Rev 57 3.3-70 ****...*.**.*...*.*******..***...***.**.***.*..**.*****...*...*....**.*.*.***.****..*.*..*.*.**.****..**.*. Rev 55 3.3-71 ***....*.*..*.*.*****.*..*.*.*.*.*.**.*.*.*..*..*.**.**...*..*..*.***.**..***. ; **.*.**....***.*.*...***.**. Rev 52 3.3-72 .*..*.**....*.*.***.*.****.*.*.*.*.*..*..**.*..**.***.**.*.*****.**.*.**.****..*..*.*..***.**.*.*...*.*..*.** Rev 3 3.3-73 *..****..*****...*.******..*****.**.*..*.******.************...*.*....*...**..***.*****.****.****.**...* : .**. Rev 3 3.3-74 *.******..*..*****.*.**.*.**..*...***..*...**.******.**.*.**********.*.*.****.*.....***.*.**.*....**..**..* Rev 86 3.3-75 *.**.**...*.**.*.*.*.****.*...*...........*.***.*.*********..***....***.*.**..*.*.****..**.*.*.**.**..**... Rev 86 *....**....*.*.*******..*.*.*.*...*.*.**.***.*..*.*****..*....*......*...***.**.*..*....*.**...*..**.*... Rev 132 PBAPS UNIT2 3.3-77 ......................................................................................................... *Rev 132

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• Revision No. 139

"'. PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.6 . CONTAINMENT SYSTEMS (continued) page(s) : . *: -*  :.,** --*;. ., -.. ' :.-,,. PBAPS UN,IT 2 3.6-23 ***..** : ............ : ****.* .-* ............................................................................. Rev 114 3.6-23a ....................................................................................................... Rev 114 3.6-24 ; ... ; ......................... ............ * ................................................................ Rev 91 *

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PBAPS UNIT 2 -LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.6 CONTAINMENT SYSTEMS (continued) page(s) 3.6-76 ..........*...*.....*...****.....**.*..*..****....*..**.*..*...*..************.*********.*.*****.******.. Rev 120 3.6-77 *...*...*.*..**.........*.*.****.......*....*****.*..*.........**...*.**.....*.*...*.*.*.***.***......*.*.. Rev 97 3.6-78 ....****..*..*...****.......**.......*.*..*.*...*..*.**....*.*......*.**..**.*..*.. * ....*.***.**.....*...*.* Rev 75 3.6-79 ....*.*.......*....*..**..*....*.......*.............**.....*........*.**.*.....*.**..**.*..*..*..*.*...*.. Rev 75 3.6-81 ...**.*......*...*...*......*..*.......*... ; *...*..*.**....*.....*....******....*...**.**......*....*.*.**. Rev 57 3.6-82 ...*..*......*.....*........*...............*...*.....*.*..*...*....*.***..*....*..**..*............*.....* Rev 75 3.6-83 .*.*..*..*.....*.*...................*.**.*.*.*.*******.*.....*..****.**.......**........*.*...*....*..*... 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• 3.10-33 ......................................................................................................... Rev 63 3.10-35 ................................................................... : ..................................... Rev 86 3.10-36 ......................................................................................................... Rev 86 All remaining pages are Rev 0 dated 1/18/96. PBAPS UNIT 2 xii Revision No. 139 1 * ,* . " . '.. ;* -. .* .TABLE OF -CONTENTS B 2.0 SAFETY LIMITS (SLs) ......................................... B 2.0-1 B 2.1.1 B 2.1.2 Reactor Core SLs .................................... B 2. 0-1 Reactor Coo 1 ant System (RCS) Pressure SL ........... B 2. 0-7 B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY* ........ B 3.0-1 SURVEILLANCE REQUIREMENT (SR) ................. B 3.0-10 B 3 .1 B 3.1.1 B 3.1.2 B 3.1.'3 B 3.1.4 B 3.1.5 B 3.1.6 B 3.1.7 B 3.1.8
• B B 3_.2.1. B 3.2.2 *. B 3.2.3 B 3.3 *. B 3.3.1.1 B-3.3;1.2 B 3 .. 3o2;1 B 3;3.2 .. 2 . . B 3.3.3,1' B 3.3.3.2 B 3.3.4 ... 1.* B 3.3.4.2 B 3.3._5.1 B B-3.3.6.1 B. 3. 3. 6<.2 B3.3.7:1 B 3.3;8.*1
• B REACTIVITY CONTROL SYSTEMS . : ................... *. . . . . . . . . B 3. 1 -1 SHUTDOWN MARGIN (SOM) .. ............................ B 3.1-1 Reactivity Anomalies ................................. B 3 .1-8 Control Rod OPERABILITY .............................. B 3.1-13 Control Rod Scram Times ............................. B 3.1-22 Control Rod Scram Accumulators ...................... B 3 .1-29 Rod Pattern Control ....*............................ B 3.1-34 Standby L1 quid Control (SLC) System .... : ............ B 3 .1-39 Scram Discharge Volume (SDV) Vent and Drain Valves .. B 3. 1-48 POWER DISTRIBUTION LIMITS .............. , ................ B 3. 2-1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) ....... , ............................. ; .* .... B 3. 2-1 MINIMUM CRITICAL POWER RATIO (MCPR) ............. , ... B 3. LINEAR HEAT 'GENERATION. RATE ( LHGR)* ..... _. ........ : ; . B 3. 2-11 INSTRUMENTATION ..... ; ... : ...... *: .... : ... ; ......... ..... B 3.3-1. Reactor Protection (RPS) 1nstrumentation ., . , ..... B 3.3-1 * -Wide Range Neut ran Monitor (WRNM) Instrumentation ... , . . . B 3 .. 3-36 Control Rod* Block Instrumentation . ; ......... :.: .... , ..... B 3.3-45
• Feedwater a'nd M<:d n_ Turbine High .Water . Leve 1 Trip . . *. Instrumerrt:ation ... ....... * ....... , .. , ..... :; ...... B 3.3.-58 -Post Accident Monitori'ng (PAM) Instrumentation, ...... , .. B 3.3-65' Remote Shutdown _System ....... : ....................*...... B 3. 3-76 Anticipated Recircul.tion Pump Trip (ATWS-RPT) Instrumentati_on : ........*. : .. B 3. 3-83 End of Gycl e Reci rcul atlon Pump Tri P *. : .. 1 ** * * * *(EOC,-RPT) lnstr_umentation . * ...
• B.*3.3-9la thru B 3.3-9.1j : Emergency Core Cooling. Syi;'tem: (ECCS) * * * * * * ' * . * * *-... Instrumentation ........ .. ::.: ... : ....... * *. _ .....*... B3.3-92 Reactor Core -!Sol ati on Cooling (RCIC) System * * . . _**.. . . Instrumentation.'. .. .-' ... ;:: .. : .. * ............... > .... _.* .. *pfi.mary Conta*inmerit 1.solation InsfruinentationC: .. ..*. : ... . Secondary. Coritainmehf: Isolation Instrumentation ... '. .. *.;. . Mai ri' Cdntrol Room Emergency Venti 1 atfoq. (MCREV) : --... * . B 3. 3".'-130 . B 3.3:.1.41 . B 3.3-1.!39 * . *. . System Ins.ti-u!llentation ......... * ...... ........... B 3.3-180< Loss of Power'(LOP)°Instrumentation ............ , ...*..... 83.3-187. Reactor . Protection System '(RPS) Electric. Power . ..*. . . _. : __ . ,*' .. : ... : . * .. * .. \ .... '..' '. .. ...... , ..... : , ...
• B 3.3-199 * .. * . * ... (Continued) * ' .. .. . .. . . '.*.-** PBAPS UN IT<z* . . i *Revision No.* 25 *,_ .. -* .... *,

TABLE OF CONTENTS (continued) B 3.4 B 3.4.1 B 3.4.2 B 3.4.3 B 3.4.4 B 3.4.5 B 3.4.6 B 3.4.7 B 3.4.8 B 3.4.9* B 3.4.10 B 3.5 B 3.5.1 B 3.5.2 B 3.5.3 B 3.6 B 3. 6 .'1.1 B 3.6.1.2 B 3.6,1.3 B 3.6.1.4 B 3.6.1.5 B 3.6.1.6 B 3.6.2.1 B 3.6.2;2 B 3.6.2.3 B 3.6.2 .4_ B 3.6.2.5 B 3.6.3.1 B 3.6.3.2 B 3.6.4.1 B 3.6.4.2 B 3.6.4.3 B 3.7 B 3.7.1 B 3.7.2 B 3.7.3 B 3.7.4 B 3.7.5 PBAPS UN IT 2 REACTOR COOLANT SYSTEM (RCS) ........ ................... B 3.4-1 Recirculation Loops Operating ....................... B 3.4-1 Jet Pumps .....................*........... , ......... B 3.4-11 Safety Relief Valves CSRVs) and Safety Valves (SVs). B 3.4-15 RCS Operational LEAKAGE ............................. B 3.4-19 RCS Leakage Detection Instrumentation ............... B 3.4-24 RCS Specific Activity ............................... B 3.4-29 Residual Heat Removal ( RHR) Shutdown Cooling System-Hot Shutdown ............................. B 3.4-33 Residual Heat .Removal <.RHR) Shutdown Cooling System-Cold Shutdown, ........................... B 3.4-38 RCS Pressure and Temperature CP/T) Limits ........... B 3.4-43 Reactor Steam Dome Pressure : ........................ B 3. 4-52 EMERGENCY CORE COOLING SYSTEMS CECCS) AND REACTOR CORE ISOLATION COOLING CRCIC) SYSTEM ......................... B 3.5-1 ECCS-Operating ........ ; ............................ B 3.5-1 EC.CS-Shutdown ...................................... B 3.5-18 RCIC System ......................................... B 3.5-24 CONTAINMENT SYSTEMS .................................... . Primary Containment .................................... . Primary Containment Air Lcick ............ ; .............. . Primary Containment Isolation Valves (PCIVs) ........... . Drywel l Air Temperature .... .' ........................... . Reactor Building-to-Suppression Chamber Vacuum Breakers* ........................... * ............. . Suppression Chamber-to-Drywell Vacuum Breakers ......... . Suppression Pool Average Temperature ................. .. Pool Water Level ..................... ; ..... . Residual Heat Removal CRHR) *suppression Pool B 3.6-1 B 3.6-1 B 3.6-6 B 3.6-14 B 3.6-31 B 3.6-34 B 3.6-42 B 3.6-48 B 3.6-53 Cooling._ ....... _ .......................... * ........ B 3.6-56 Residual Heat Removal CRHR) Suppression Pool Spray ...... B 3.6-60 Residual Heat Removal CRHR) Drywell Spray ............... B 3.6-63a I Deleted ... .. *: ......................... .................. B 3.6-64 Primary Oxygen Concentration ................ B 3.6-70 Secondary Containment ............................... : ... B 3. 6-73 Secondary Containment Isolation Valves (SCIVs) .......... B 3.6-78 Standby Gas Treatment (SGT) System ...................... B 3.6-85 PLANT SYSTEMS ...................... : . ** .................. B 3. 7-1 High Pressure Service Water CHPSW) System ........... B 3.7-1 Emergency Service Water CESW) System and Normal Heat Sfnk ................................ * ........

• B 3.7-6 Emergency Heat Sink .........*....................... B 3.7-11 Main Control Room Emergency Ventilation CMCREV) System ..................................... B*3.7-15 Main Condenser ..*..................... : ..... B 3.7-22 continued . ii . Revision No. 106 1':. . ,. I. TABLE OF CONTENTS (continued) B 3.7 B 3:7.6 B 3. 7. 7. B 3.8 . B 3.8.1 B 3.8.2 B 3.8.3 B 3.8.4 B 3.8.5 B 3.8.6 'B 3.8. 7 B 3.8.8 B 3.9 B 3,9 .. 1 . B 3.9.2 B 3.9.3. B 3.9.4 . B 3.9.5. B* 3.9:6* B 3.9.7 *.* . B 3.9.8 B 3.'10. B 3,10.1 B3.10.2* B 3.10.3. B 3.1o.4* B 3.10:.5 B 3.10.6 B 3.10.7 B 3.10.8 *_, .. PBAPS' UNIT 2 PLANT SYSTEMS (continued) . Main Turbine Bypass System .................. : ....... B 3.7-25 Spent Fuel Storage Pool Water Level ............. :. : . B 3.7-29
• ELECTRICAL POWER SYSTEMS ................................ B AC Sources-Operating ............................... B 3.8-1 AC Sources-Shutdown ................................ B 3.8-40 Diesel Fuel Oil, Lube Oil, and Air ......... B 3.8-48 DC Sources-Operating ............................... B 3. 8-58 DC Sources-Shutdown ................................ B 3. 8-72 Battery Cell Parameters ......... ......*............ B j,8-77 Distr.ibution Systems-Operating ...................... B 3.8,.83 Distribution Systems-Shutdown , ... , ................. B 3,8-94 . REFUELING OPERATIONS ......................... ; .......... B 3 .. 9-1 Refueling Equipment Interlocks ...... , ............... B Refuel Position One-Rod-Out Interlock ... , .......... :. B 3.9-.5 Control Rod Position ..... ; ............................ s* 3.9-8 Control Rod Position Indication ..................... B 3 .. 9-10 Control Rod OPERABILITY-Refueling .................. B 3.9-:14 Reactor Pressure Vessel ( RPV) Water Leve 1 ........... B 3. 9-17.
• Residual Heat Removal (RHR)-High Water Level ....... B 3.9-20 Residual Heat Removal. (RHR) ....:.Low Water Le.vel . ; ...... B 3.9-24' SPECIAL OPERATIONS ...... ; ............................... B 3.10-1 In service Leak and Hydrostatic Testi rig Operation .... B Reactor Mode Switch Interlock Testing ............... B. 3 .10'.'5 . *Single Control Rod Withdrawa*l -Hot Shutdown ......... B 3.10-10 *Single Control Rod Withdrawal -Cold Shutdown .... : ... B 3.10-14 Single Control Rod Drive (tRD) * * * . . Removal-Refoeling ...... : .................. ; ...... B 3:10-19
• Mul-ti pl e Control Rod Withdrawal-Refueling ...... * .. * ... B. 3 .10-24 Control Rod Testing.:_Opei-atirig *............ : ..... , .. B _3.10-27 SHUTDOWN MARGIN (SOM) ............... B 3.10-31. .. ".** . * ... ,** .* ....... **. ; ; ; .. *Revisior:i No. o . .... . ...

Recirculation Loops Operating B 3.4.1 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.1 Recirculation Loops Operating BASES BACKGROUND PBAPS. UNIT 2 The Reactor Coolant Recirculation System is designed to provide a forced coolant flow through the core to remove heat from the fuel. The forced coolant flow removes more heat from the fuel than would be possible with just natural circulation. The forced flow, therefore, allows operation at significantly higher power than would otherwise be possible. The recirculation system also controls reactivity over a wide span of reactor power by varying the recirculation flow rate to control the void content of the. moderator. The Reactor Coolant Recirculation System consists of two recirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps. Each external loop contains one variable speed motor driven recirculation pump, an adjustable speed drive (ASD) to control pump speed and associated piping, jet pumps, valves, and instrumentation. The recirculation loops are part of the reactor coolant pressure boundary and are located inside the drywell structure. The jet pumps are reactor vessel internals. The recirculated coolant consists of saturated water from the steam separators and dryers that has been subcooled by incoming feedwater. This water passes down the annulus between the reactor vessel wall and the core shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges high pressure flow into an external manifold, from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remaining portion of the coolant mixture in the annulus becomes the suction flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the driving flow. The drive flow and suction flow are mixed in the jet pump throat section. The total flow then passes through the jet pump diffuser section into the area below the core Clower plenum), gaining sufficient head in the process to drive the required flow upward through the core. The subcooled water enters the bottom of the fuel channels and contacts the fuel cladding, where heat is transferred to the coolant. As it rises, the coolant ed B 3.4-1 Revision No. 137 11-. ii II*** 11 II II. . . . ' . BASES BACKGROUND (continued) *,:* Recirculation Lo.ops Operating B 3.4.1 begins to boil, creating within the fuel that continue until the cool ant ex:i ts core: Beca,use of reduced moderation, the steam voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. recirculation flow control allows operators to increase recirculation flow and sweep some *of the voids from the fuel channel, overcoming the *negative reactivity void effect.* Thus, the reason for having variable reci rcul ati on fl ow is to compensate for reactivity effects of boiling.over a wide range of power generation 65 to 100% of RTP) without having to move cpntrol rods and disturb desirable flux patterns. loop is manually started from the control rodm. .The ASD providei of iridividual l loop drive flows. The flow in each loop is manually controlled.

• APPLICABLE .* . The. operat*i on of. the Reactor Cool ant Reci rcul ati on System is . SAFETV'AN/\LYSES an initial condition assumed in the design basis loss of. *coolant .accident (LQCA) (Ref. 1). During.a LOCA caused by a* recirculation loop pipe break, .the intact loop* is assumed to .*
• prov*ide c_o_olant -fl ow .dur:ing the first few seconds of the * ..
• accident:.* The it}itiiJl core flow decrease is rapid because . *, -the. reci rcul.ati on pump in the l;>roken 1 oo.p ceases to pump.* .*. reactor.coolant to thevessel almost.immediately. The pump in the loop coasts. down relatively slowly. This pump coastdo.wn governs the core flow response for the next * * *several sec*onds uilti l the Jet pump suction is uncovered .. . The analys'es assume thaf both loops are operating at the same flow*priortothe accident .. analysis was reviewed for the* case with a fl;ow mismatch betweenthe-* two .with>the pipe. break assiiined to'be in the loop with the'. higher fl o\'/; * .. WM le the fl ow coastdown and cor.e *** **.*. response 'are potentially niote severe in this assumed . ( s irice the ; ntact loop sta*rts* at** a l ower'*flow rate and the is the; same .as 1 f hothloops WE!re operating at
• r a lower. fl ow rate>, a* s*mal l mismatch has. been determined to * \ -be based on. engineering judgement: The . *.** -. <.,.retircula'fionsystem.is also-assumed to have sufficient *flow.* '. coast:do.wn '.characteristics to mai.ritai n fu.eJ thermal niargi'ns *. *.* during a):Jno_rmal*:operational transients, which are analyzed in.Cha.pter l4.9f the . . -. . . -: '. c continued> "*;, ;*-,:' *. -. .-... * *_._ . B :L 4-2 Rei,tisioh No. 137 BASES APP LI CAB LE SAFETY ANALYSES (continued) PBAPS UN IT 2 Loops Operating B 3.4.l Plant specific LOCA and average power range monitor/rod block monitor Technical Specification/maximum extended load line limit analyses have been performed assuming only one operating recirculation loop. These analyses demonstrate th at , i n the even t of a L 0 C A c a u s e d by a p i p e b re a k i n t he operating recirculation loop, the Core Cooling System response will provide adequate core cooling (Refs. 2, 3, 4, 7 and 8). The Maximum Extended Load Line Limit Analysis Plus (MELLLA+) operating domain has not been analyzed for single recirculation loop operation. Therefore, single loop operation is prohibited in the MELLLA+ operating domain (Ref. 9). The transient analyses of Chapter 14 of the UFSAR have also been perf6rmed for single recirculation loop operation (Ref. 5) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal transients analyzed provided the MCPR are modified. During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRMl insirument set0oints is also required to account for the .different relationships between recirtulation flow and reactor core flow. The MCP.R limits and APLHGR limits dependent multipliers, MAPFACP; ahd flow-dependent APLHGR multipliers, MAPFACt) for single lobp operation are specified in the COLR. The APRM Simulated Jhermal High Value is in LCO 3.3.1.1, Protection System (RPS) Instrumentatibn." continued B 3.4-3 Rev i s i on N ci . 12 3 BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UN IT 2 Recirculation Loops Operating B 3.4.1 Recirculation loops operating satisfies Criterion 2 of the NRC Policy Statement. Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the continued B 3.4-4 *Revision No; 50 BASES LCO (continued) APPLICABILITY PBAPS UNIT 2 Recirculation Loops Operating B 3.4.l assumptions of the LOCA analysis are satisfied. Alternatively, with only one recirculation lobp in operation, modifications to the required APLHGR limits (power-and flow-dependent APLHGR multipliers, MAPFACP and MAPFACf, respectively of LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits CLCO 3.2.2, "MINIMUM CRITICAL POWER.RATIO CMCPR)") and APRM Simulated Thermal Power-High Allowable Value (LCO 3.3.1.1) must be applied to allow continued operation consistent with the assumptions of Reference 5. Single loop operation is . prohibited in the MELLLA+ operating domain per Reference 9. LCO is modified by a Note which allows up to 12 hours before having to put in effect the required modifications to required limits after a change in the reactor operating conditions from two recirculation loops operating to single recirculation lo6p operation. I( the required limits are not in tompliance with the applicable requirements at the . end of this period, the associated equipment must be declared inoperable or the limits "not satisfied," and the ACTIONS required by nonconformance with the applicable specifications implemented. This time is provided.due to the need to stabilize operation with one recirculation loop, including the steps necessary to limit flow in the operating loop, and the complexity and detail required to fully implement and confirm the required limit modifications. *
• In MODES 1 and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur. In MODES 3, 4, and 5, the consequences of an accident are reduced and the coastdown characteristics of the recirculation loops are not important. (continued) B 3.4-5 Revision No. 123 BASES PBAPS UN IT 2 -Recirculation Loops Operating B 3.4.1 THIS PAGE LEFT BLANK INTENTIONALLY (The contents of this page have been deleted) B 3.4-6 Revision No. 50 I I ! BASES (continued) Recirculation Loops Operating B 3.4.1 ACTIONS A.1 PBAPS UN IT 2 With the requirements of the LCD not met, the recirculation loops must be restored to operation with matched flows within 24 hours. A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than required limits. The loop with the lower flow must be considered not in*operation. Should a LDCA occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LDCA analyses. Therefcire, only a limited time is allowed to restore the inoperable loop to operating status. Alternatively, if the single loop requirements of the LCD are applied to operating limits and RPS setpoints, operation with only one recirculation loop would satisfy the requirements of the LCD and the initial conditions of the accident Note that single loop operation is prohibited in the MELLLA+ domain per Reference 9. The 24 hour Completion.Time .is based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action, and on frequent core monitoring by operators allbwing abrupt changes in core flow conditions to be quitklY detected. This Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the required limits. However, in cases where large flo0 mismatches occur .* low flnw or reverse flow can occur in the low flow loop jet pumps, causing vibratton of the jet pumps. If zero or reverse* flow is detected, the condition.** should* be alleviated by changing pump speeds to re-establish forward flow or by trfpping the pump. continued B 3.4-7 Revision No. 123 BASES Recirculation Loops Operating B 3.4.l ACTIONS .!L...l (continued) PBAPS UN IT 2. The MELLLA+ operating domain is not analyzed for single recirculation loop operation, Therefore, single loop operation is prohibited in the MELLLA+ operating domain (Ref. 9). Action shall be taken to immediately exit the MELLLA+ domain in order to return to operation at an analyzed condition. However, it is expected that plant design limitations will preclude operation in the MELLLA+ domain with a single recirculation loop. With no recirculation loops in operation or the Required Action and associated Completion Time of Condition A or B not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours. In this condition, the recirculation loops not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from power conditions in an orderly manner and without challenging plant systems. (continued) s* 3.4-B Revision No. 123 BASES (continued) SURVEILLANCE REQUIREMENTS UN IT 2 SR 3.4.1.1 Recirculation Loops Operating B 3.4.1 This SR ensures the loops are within the allowable limits for mismatch. At low core flow (i.e., < 71.75 X 106 lbm/hr), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < 71.75 X 106 lbm/hr. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop. The mismatch is measured in terms of core flow. (Rated core flow is 102.5 X 106 lbm/hr. The first limit is based on 10% of rated core flow when operating at< 70% of rated core flow. The second limit is based on 5% of rated core flow when operating 70% of rated core flow.) If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered not in operation and _operatibn in the MELLLA+ domain is prohibited per Reference 9. The SR is not required when both loops are not in operation since the mismatch are meaningless -during single loop or natural circulation operation. The Surveillance must be performed within the specified Frequency after both loops are in operation. The Surveillance Frequency is_ controlled under the Surveillance Frequency Control Program: (continued) B 3.4-9 Revision No. 123 BASES (continued) REFERENCES PBAPS UN IT 2 1. UFSAR, Section 14.6.3. Recirculation Loops Operating B 3.4.1 2. NEDC-32163P, "PBAPS Units 2 and 3 SAFER/GESTR-LOCA Accident Analysis," January 1993. 3. NEDC-32162P, "Maximum Extended Load Line Limit and ARTS Improvement Program Analyses for Peach Bottom Atomic Power Station Unit 2 and 3," Revision 1, February 1993. 4. NEDC-32428P, "Peach Bottom Atomic Power Station Unit 2 Cycle 11 ARTS Thermal Limits Analyses," December 1994. 5. NED0-24229-1, "PBAPS Units 2 and 3 Single-Loop Operation," May 1980. 6. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 7. G-080-VC-400, "Peach Bottom Atomic Power Station Units 2 & 3 GNF2 ECCS-LOCA Evaluation," GE Hitachi Nuclear Energy, 0000-0100-8531-Rl, March 2011. 8. Bottom Atomic Power Station LOCA Evaluation for GE14," General Electric Company, GENE-Jll-03716-09-02P, July 2000. 9. NEDC-33006P-A, "Maximum Extended Load Line Limit Analysis Plus Licensing Topical Report," Revision 3, June 2009. B 3.4-10 Revision No. 123 BASES BACKGROUND Jet Pumps B 3.4.2 The Reactor Coolant Recirculation System is described in the Background section of the Bases for LCO 3.4.1, "Recirculation Loops Operating," which discusses the operating characteristics of the system and how these characteristics affect the Design Basis Accident (DBA) analyses. The jet pumps are reactor vessel internals and in conjunction with the Reactor Coolant Recirculation System are designed to provide forced circulation through the core to remove heat from the fuel. The jet pumps are located in the annular region between the core shroud and the vessel inner wall. Because the jet pump suction elevation is at two-thirds core height, the vessel can be reflooded and coolant level maintained at two-thirds core height even with the complete break of the recirculation loop pipe that is located below the jet pump suction elevation. Each reactor coolant recirculation loop *contains ten jet pumps. Recirculated coolant passes down the.annulus between the reactor vessel wall and the core shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges high pressure-flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remaining _portion of _the coolant mixture in the annulus becomes the suction flow for the jet .pumps. This flow enters the jet pump at suction -inlets and is accelerated by the drive flow. The drive _flow and suction -flow are mixed in the jet pump throat section. The total flow then passes .through the jet pump diffuser section into the area below the core (lower pJenum), gaining sufficient head in the process to drive the required -fl ow upward thrc;;ugh the -core.
• APPLICABLE Jet pump OPERABILiTY is an implicit assumption in the design SAFETY ANALYSES basis loss of coolant accident (LOCA) analysis evaluated in -Reference -1. -(continued) PBAPS UNIT *2 B 3.4-11 Revision No. o

.. BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABILITY ACTIONS* P13APS UNIT 2 Jet Pumps B 3.4.2 The capability of reflooding the core to two-thirds core height is dependent upon the structural integrity of the jet pumps. If the structural system, including the beam holding a jet pump in place, fails, jet pump displacement and performance.degradation could occur, resulting in an increased flow area through the jet pump and a lower core flooding elevation. This could adversely affect the water level in the core during the reflood phase of a LOCA as well as the assumed blowdown flow during a LOCA. Jet pumps satisfy Criterion 2 of the NRC Policy Statement. The structural failure of any of the jet pumps could cause significant degradation in the ability of the jet pumps to allow reflooding to two-thirds core height during a LOCA. OPERABILITY of all jet pumps is required to ensure that operation of the Reactor Coolant Recirculation System will be consistent with the assumptions used in the licensing basis analysis (Ref. 1). In MODES 1 and 2, the jet pumps are required to be OPERABLE since there is a large amount of energy in the reactor core and since the limiting DBAs are assumed to occur in these MODES. This is consistent with the requirements for operation of the Reactor Coolant Recirculation System (LCO 3.4.1). In MODES 3, 4, and 5, the Reactor Coolant Recirculation System is not required to be in operation, and when not in operation, sufficient flow is not available to evaluate jet pump OPERABILITY. An inoperable jet pump can increase the blowdown area and reduce the capability of reflooding during a design basis LOCA. If one or more of the jet pumps are inoperable, the plant must be brought to a MODE in which the LCD does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours. The Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. (continued) B Revision No. O

• Jet Pumps B 3.4.2 BASES (continued} SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.4.2.1 This SR is designed to detect significant degradation in jet pump performance that precedes jet pump failure (Ref. 2). This SR is required to be performed only when the loop has forced recirculation flow since surveillance checks*and measurements can only be performed during jet pump operation. The jet pump failure of concern is a complete mixer displacement due to jet pump beam failure. Jet pump plugging is also of concern since it adds flow resistance to the recirculation loop. Significant degradation is indicated if the specified criteria confirm unacceptable deviations from established patterns or relationships. The allowable deviations from the established patterns have been developed based on the variations experienced at plants
• during normal operation and with jet pump assembly failures (Refs. 2 and 3). Each recirculation loop must satisfy one of the performance criteria pro_vided. Since refueling
• activities (fuel assembly replacement or shuffle, as well as any modifications to fuel support orifice size or core plate bypass flow) can affect the relationship between core flow, jet pump flow, and recirculation loop flow, these relationships may need to be re-established each cycle. Similarly, initial entry into extended single loop operation may also require establishment of these relationships.
• During the initial weeks of operation under such conditions,. while baselining new "established patterns," engineering judgement of the daily surveillance results is used to detect significant abnormalities which could indicate a jet pump failure. The recirculation pumpspeed operating character.istics (pump . flow and loop flow versus pump speed) are determined by the flow resistance from the loop suction through the jet pump nozzles. A change in the relationship indicates a plug, flow restriction, loss in pump hydraulic performance, leakage, or new flow path between the recirculation pump discharge and jet pump nozzle .. For this criterion, the pump flow and loop flow versus pump speed relationship must* be verified. *
• Individual jet pumps in a recirculation loop normally do not have the same fl ow. The unequa 1 fl ow is due to the drive flow manifold, which does not distribute flow equally to all risers. The flow (or jet pump diffuser to lower plenum differential pressure) pattern or relationship of one jet {continued) B 3.4-13
• Revision No. O BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS. UN IT 2 SR 3.4.2.l (continued) Jet Pumps B 3.4.2 pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow for a jet pump that has experienced beam cracks. The deviations from normal are considered indicative of a potential problem in the recirculation drive flow or jet pump system (Ref. 2). Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by two Notes. Note 1 allows this Surveillance not to be performed until 4 hours after the associated recirculation loop is in operatiDn, since these checks tan only be performed during jet pump operation. The 4 hours is an acceptable time to establish conditions appropriate for data collection and evaluation. Note 2 allows this SR not to be until 24 hours after THERMAL POWER exceeds 23% of RTP. During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data. The 24 hours is an acceptable time to establish conditions appropriate to perform this SR. . 1. UFSAR, Section 14.6.3. 2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1980. 3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984. B 3.4-14 Revision No. 114 SRVs and SVs B 3.4.3 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.3 Safety Relief Valves (SRVs) and Safety Valves (SVs) BASES BACKGROUND PBAPS UN IT 2 The ASME Code requires the reactor pressure vessel be protected from overpressure during upset conditions by self-actuated safety valves. As part of the nuclear pressure relief system, the size and number of SRVs and SVs are selected such that peak pressure in the nuclear system will not exceed the ASME Code limits for the reactor coolant pressure boundary CRCPB). The SRVs and SVs are located on the main steam lines between the reactor vessel and the first isolation valve within the drywell. The SRVs can actuate by either of two modes: the safety mode or the depressurization mode. In the safety mode, the. pilot disc opens when. steam pressure at the valve inlet expands the bellows to the extent that the hydraulic seating force on the pilot disc is reduced to zero. Opening of the pilot stage all-0ws a pressure differential to develop across the second stage disc which opens the second stage disc, thus venting the chamber over the main valve piston. This causes a pressure differential across the main valve. piston which opens the main The SVs are spring loaded*vaJves that actuate when steam pressure at the inlet overcomes the spring fbrce holding the valve This satisfies the Code requirement. Each of the 11 SRVs steam through a discharge line to a point below the minimum water level in the suppression .po9*1. The three SVs discharge steam directly to the drywell. In the depres.surization niode, the SRV is opened by a which opens stage disc. The main valve theri orens is described above for the safety mode: the depressurization provides controlled --depres.suri zati ori of the reactor cool ant pressure boundary. All 11 of the SHVs function* in the safetY mode and have the in the mode via . manual actuat1on from the contrbl room .. Five of SRVs are allocated to the Automatic Depressurization System CADS). The ADS requirements are in LCO 3.5.1, "ECCS:-Operati ng. "_ (continued) B 3.4-15 Revision No; 114 SRVs and SVs B 3.4.3 BASES (continued) APPLICABLE SAFETY ANALYSES LCD PBAPS UN IT 2 The overpressure protection system must accommodate the most severe pressurization transient. Evaluations have determined that the most severe transient is the closure of all main steam isolation valves CMSIVs), followed by reactor scram on high neutron flux Ci .e., failure of the direct scram associated with MSIV position) (Ref. 1). For the purpose of the analyses, 13 SRVs and SVs are assumed to operate in the safety mode. The analysis results demonstrate that the design SRV and SV capacity is capable of maintaining reactor pressure below the ASME Code limit of 110% of vessel design pressure (110% x 1250 psig = 137& psig). This LCD helps to ensure that the acceptance limit of 1375 psig is met during the Design Basis Event. From an overpressure standpoint, the design basis events are bounded by the MSIV closure with flux scram event described above .. Reference 2 discusses additional events that are expected to actuate the SRVs and SVs. Although not a design basis event, the ATWS analysis demonstrates that peak vessel bottom pressure less than the ASME Service Level C limit of 1,500 psig. SRVs .and SVs satisfy Criterion 3 of the NRC Policy Statement. The s6fety function of any combination of 13 SRVs and SVs
• are requtred to be OPERABLE tb satisfy the assumptions of *the safety analysis (Refs. 1 and 2). Regarding the SRVs, the requirements of this LCO_are applicable only to their capability to mechanically open to relieve pressure when the lift setpoint is exceeded (safety mode). The SRV and SV setpoints are established to ensure that the ASME Code.limit on peak reactor pressure is satisfied. The ASME Code specif{catibY:is*require the lowest safety valve setpoint to be at or below vessel design* pressure (1250 psig) and the highest safety valve to so that the total accumulated pressDre does not exceed 110% of the des.ign iressure for overpressurization con.ditions. The evaluations in UFSAR are based on these but also inclDde the additional uncertainties of + 3% of .the nomifial .setpoint to provide an added degree of conservatism. Operation with fewer valves OPERABLE than specified, or with* set points outside the ASME limits, could. result in a more
• responsecto than predicted, possibly resulting in the ASME Code limit on reactor pressure being exceeded. (continued) B 3.4-16 Revision No. 114 BASES (continued) APPLICABILITY ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN Il 2 SRVs and S.Vs B 3.4.3 In MODES 1, 2, and 3, all required SRVs and SVs must be OPERABLE, since considerable energy may be in the reactor core and the limiting design basis transients are assumed to occur in these MODES. The SRVs and SVs may be required to provide pressure relief to discharge energy from the core until such time that the Residual Heat Removal (RHR) System is capable of dissipating the core heat. In MODE 4, decay heat is low enough for the RHR System to provide adequate cooling, and reactor pressure is low enough that the overpressure limit is unlikely to be approached by assumed operational transients or* accidents. In MODE 5; the reactor vessel head is unbolted or removed and the reactor is at atmospheric pressure. The SRV and SV function is not needed during these conditions. A.1 and A.2 With less than the m1n1mum number of required SRVs or SVs OPERABLE, a transient may result in the violation of the ASME Code limit on reactor pressure. If the safety function* of one or more required SRVs or SVs is inoperable, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours and to MODE 4 within 36 hours. The allb0ed Completion Times are reasonable, on operating experience, to reach required plant conditions from full. power conditions in arr orderly manner and without challenging plant systems. SR 3.4.3.l This Surveillance requires that the required SRVs and SVs will open at the pressures assumed in the of References 1 and 2. The demonstration of the SRV and SV safety lift settings must be during shutdown, since this is a bench test, to be done in accordance with the Inservice Testing The lift pressure** shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures and be verified with installed simulating the in-plant The SRV and SV setpoint is +/- 3% for OPERABILJTY. Prior to new or refurbished valves into the valve openings setpoints must be to be within i 1% of their nominal
• continued* B 3.4-17 Revision No. 110 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UNIT 2 SRVs and SVs B 3.4.3 SR 3.4.3.2 The pneumatic actuator of each SRV valve is stroked to verify that the second stage pilot disc rod is mechanically displaced when the actuator strokes. Second stage pilot rod movement is determined by the measurement of actuator rod travel. The total amount of movement of the second stage pilot rod from the valve closed position to the open position shall meet criteria established by the SRV supplier. If the valve fails to actuate due only to the failure of the solenoid, but is capable of opening on overpressure, the safety function of the SRV is considered OPERABLE. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 2. UFSAR, Chapter 14. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR .Plants, December 2002. B 3.4-18. Revision No. 114 RCS Operational LEAKAGE B 3.4.4 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.4 RCS Operational LEAKAGE BASES BACKGROUND ..: PBAPS UNIT 2 The RCS includes systems and components that contain or transport the coolant to or from the reactor core. The pressure containing components of the RCS and the portions of connecting systems out to and including the isolation valves define the reactor coolant pressure boundary (RCPB). The joints of the RCPB components are welded or bolted. During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. Limits on RCS operational LEAKAGE are required to ensure appropriate action is taken before the integrity of the RCPB is impaired. This LCO specifies the types and limits of LEAKAGE. This protects the RCS pressure boundary described in 10 CFR 50.2, 10 CFR 50.55a(c), and the UFSAR (Refs. 1, 2, and 3).
• The safety significance of RCS LEAKAGE from the RCPB varies widely depending on the source, rate, and duration. Therefore, detection of LEAKAGE 'in the primary containment is necessary. Methods for quickly separating the identified LEAKAGE from the unidentified LEAKAGE are necessary to provide the operators quantitative information to permit them to take corrective action should a leak*occur that is detrimental to the safety of the facility or the public. A limited amount of leakage inside primary containment is expected* from auxiliary. systems that.cannot be made 100%. leaktight. Leakage from these systems should be detected and isolated from the primary containment atmosphere, if possible, so as not to ma*sk RCS operational LEAKAGE . detection * . *This LCD deals with protection of the.RCPB'from* degradation
• arid the core fr9m inadequate cooling, in addition to preventing the. accident analyses release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of accident. * * * (continued) B 3.4-19 Revision 0 BASES (continued) RCS Operational LEAKAGE B 3.4.4
• APPLICABLE The allowable RCS operational LEAKAGE limits are based on SAFETY ANALYSES the predicted and experimentally observed behavior of pipe cracks. The normally expected background LEAKAGE due to equipment design and the detection capability of the instrumentation for determining system LEAKAGE were also considered. The evidence from experiments suggests that, for LEAKAGE even greater than the specified unidentified LEAKAGE limits, the probability is small that the imperfection or crack associated with such LEAKAGE.would grow rapidly. LCO PBAPS UNIT 2 The unidentified LEAKAGE flow limit allows time for corrective action before the RCPB could be significantly compromised. The 5 gpm limit is a small fraction of the calculated flow from a critical crack in the primary system piping. Crack behavior from experimental programs (Refs. 4 and 5) shows that leakage rates of hundreds of gallons per minute wi 11 precede* crack i nstabi 1 i ty. The low limit on increase in unidentified LEAKAGE assumes a failure mechanism of intergranular stress corrosion cracking (IGSCC) in service sensitive type 304 and type 316 austenitic stainless steel that produces tight cracks. This flow increase limit is capable of providing an early warning of such deterioration. No applicable safety analysis assumes the total LEAKAGE limit. The total LEAKAGE limit considers RCS inventory makeup capability and drywell floor sump capacity. RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement. RCS operational -LEAKAGE :shall be 1 imited to: a. Pressure Boundary LEAKAGE No pressure boundary 1EAKAGE is allowed; si.nce it is
• indicative of' material degradation. LEAKAGE of this type is unacceptable as the leak itself could cause. further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE. past seals and _ . gaskets is not pressure boundary LEAKAGE. (continued) B 3.4-20 Revision No. O BASES LCO {continued) APPLICABILITY
• PBAPS UN IT 2 b. Unidentified LEAKAGE
• RCS Operational LEAKAGE B 3.4.4 The 5 gpm of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and drywell sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB. c. Total LEAKAGE The total LEAKAGE limit is based on a reasonable minimum detectable amount. The limit also accounts for LEAKAGE from known sources (identified LEAKAGE). Violation of this LCO indicates an unexpected amount of LEAKAGE and, therefore, could indicate new or additional degradation in an RCPB.component or system. d. Unidentified LEAKAGE Increase An unidentified LEAKAGE increase of > 2 gpm within the previous 24 hour period indicates a potential flaw in the RCPB and must be quickly evaluated to determine the source and extent of the LEAKAGE. The increase is measured relative to thesteady state value; temporary
• changes in LEAKAGE rate as a result of transient conditions (e.g., startup) are not considered. As such, the 2 gpm increase limit is only applicable in MODE I when operating pressures and temperatures are established. Violation of this LCO could result in continued degradation of the RCPB. *
• In MODES. I, 2, and 3, the RCS operational LEAKAGE LCO applies, because. the potential for RCPB LEAKAGE is greatest when the reactor is pressurized. In MODES 4 and 5, RCS operational LEAKAGE limits are not required since the reactor is not pressurized and stresses in the RCPB materials and potential for LEAKAGE are reduced .. (continued) 8 3.4-:-21 Revision No. 0 BASES (continued) ACTIONS PBAPS UNIT -2 A. I RCS Operational LEAKAGE B 3.4.4 With RCS unidentified or total LEAKAGE greater than the limits, actions must be taken to reduce the leak. Because the LEAKAGE limits are conservatively below the LEAKAGE that would constitute a critical crack size, 4 hours is allowed to reduce the LEAKAGE rates before the reactor must be shut down. If an unidentified LEAKAGE has been identified and quantified, it may be reclassified and considered as identified LEAKAGE; however, the total LEAKAGE limit would remain unchanged. B.l and B.2 An unidentified LEAKAGE increase of > 2 gpm within a 24 hour period is an indication of a potential flaw in the RCPB and must be quickly evaluated. Although the increase does not necessarily violate the absolute unidentified LEAKAGE limit, certain susceptible components must be determined not to be the source of the LEAKAGE increase within the required Completion Time. For an unidentified LEAKAGE increase greater than required limits, an alternative to reducing LEAKAGE increase to within limits (i.e., reducing the leakage rate such that the current rate is less than the "2 gpm increase in the previous 24 hours* limit; either by isolating the source or other possible methods) is to evaluate service sensitive type 304 and type 316 austenitic stainless steel piping that is subject to high stress or that contains relatively stagnant or interrilittent flow fluids and determine it is not the source of the increased LEAKAGE. This type piping is very susceptible to IGSCC. The 4 hour Completion Time is reasonable to properly reduce the LEAKAGE increase or verify the source before the reactor must be shut down without unduly jeopardizing plant safety. C.l and C.2 If any Required Action and associated Completion Time of Condition A or B is not met or if pressure boundary LEAKAGE exists, the plant must be brought to a MODE in which the-LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours and to MODE 4 within (continued) B 3.4-22 Revision No. O BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 C.l and C.2 (continued) RCS Operational LEAKAGE B 3.4.4 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant safety systems. SR 3.4.4.1 The RCS LEAKAGE is monitored by a variety of instruments designed to provide alarms when LEAKAGE is indicated and to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.5, "RCS Leakage Detection Instrumentation." Sump level and flow rate are typically monitored to determine actual LEAKAGE rates; however, any method may be used to quantify LEAKAGE within the guidelines of Reference 6. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1.. 10 CFR 50.2. 2. 10 CFR 50.55a(c). 3. UFSAR, Section 4.10.4. 4. GEAP-5620; "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws," April 1968 .. 5. NU REG-75/067, "Investigation and Ev al uati.on of. Cratking in Austenitic .Stainless Piping of Boiling Water Reactors.," October 1975. 6: Regulatory Guide 1.45, May 1973. 7*. Ger'feric Letter *ss-oi', "NRC Position on IGSCC in BWR *Aus t e nit i c St a i n l es s Ste el P i p i n g , " J a n u a r y 19 8 8 .
• B 3.4-23 Revision No. 86 RCS Leakage Detection Instrumentation B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM CRCS) B 3.4.5 RCS Leakage Detection Instrumentation BASES BACKGROUND PBAPS UNIT_ 2 UFSAR Safety Design Basis (Ref. 1) requires means for detecting and, to the extent practical, identifying the location of the source of RCS LEAKAGE. Regulatory Guide 1.45, Revision 0, (Ref. 2) describes acceptable methods for selecting leakage detection systems. Limits on LEAKAGE from the reactor coolant pressure boundary CRCPB) are required so that appropriate action can be taken before the integrity of the RCPB is impaired (Ref. 2). Leakage detection systems the RCS are provided to alert the operators when leakage rates above normal background levels are and.also to supply quantitative measurement of leakage rates. In addition to meeting the OPERABILITY requirements, the monitors are typically set to provide the most sensitive without causing an excessive number of spurious alarms. The Bases for LCD 3.4.4, "RCS Operational LEAKAGE," discuss the limits on RCS LEAKAGE rates. Systems for separating the LEAKAGE of an identified source from an unidentified source are necessary to provide prompt and quantitative information to the to permit them to take immediate corrective action. LEAKAGE from the RCPB inside the drywell is detected by at least one of two indepehdently monitored variables, such as sump level changes and drywell gaseous radioactivity levels. The primary means of quantifying LEAKAGE in the drywell is the drywell floor drain sump monitoring system. drywell floor drain sump monitoring system the LEAKAGE collected in the floor drain sump. This LEAKAGE of from ccintrol rod drives,* valve flanges or packings, floor.drains, the' Reactor Building Closed Cooling Water System, and drywell air coolihg unit condensate and any LtAKAGE not collected *in the drywell_ equipment.drain sump. An to the drywell floor dfain sump monitoring system is the drywell equipment drain sump monitoring *system, but only if the drywell floor drain sump is overflciwing. The drywell drain not only all leakage not collected in the drywell flocir drain . sump, -but al so any overflow from the drywell floor drain Therefore, if the drywell floor drain sump is continued B 3.4-24 Revision No. 93 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES LCD PBAPs' UN IT 2 RCS Leakage Detection Instrumentation B 3.4.5 overflowing t6 the drywell equipment drain sump, the drywell equipment drain sump monitoring system can be used to quantify LEAKAGE. In this 'condition, all LEAKAGE measured by the drywell equipment drain sump monitoring system is assumed to be unidentified LEAKAGE.
• The floor drain sump level indicators have switches that start and stop the sump pumps when required. If the sump fills to the high high level setpoint, an alarm .sounds in the control room, indicating a LEAKAGE rate into the sump in excess of 50 gpm. A flow transmitter in the discharge line of the drywell floor drain sump pumps provides flow indication in the c.ontrol room. The* pumps can al so be started from the cont ro 1 room. The primary containment air monitoring system continuously monitors the containment atmosphere for airborne gaseous radioactivity. A sudden significant increase of radioactivity; which.may b.e attributed toRCPB steam or water LEAKAGE, is annunciated in the control room. I A threat of signifitant to RCPB exists if the barrier contains a crack that is large enough to propagate raptdly. LEAKAGE rate limits are low enough to detect the LEAKAGE emitted from a single crack in the RCPB (Refs. 3 and 4). The allowed LEAKAGE rates are well below the rates predictea for critical crack sizes (Ref, 6). Therefore, these actions provide response before a break in the RCPB can occur.
• RCS leakage detection instrumentation satisfies Criteri6n 1 of the NRC Policy Statement. This LCD requires instruments of diverse monitoring principles to be OPERABLE to provide that. small amounts of unidentified LEAKAGE are detetted in time to allow actions to the plant in a safe condition, when RCS LEAKAGE indicates possible RCPB degradation. The LCD requires two instruments to be OPERABLE .. The drywell sump monitoring system is required to quantify the unidentified LEAKAGE from the RCS. Thus, for the system fo be considered OPERABLE, the system .must be capable of continued B 3; 4-25 Revision No. 93*

BASES LCO (continued) *APPLICABILITY PBAPS UN IT 2 RCS Leakage Detection Instrumentation B 3.4.5 measuring reactor coolant leakage. This may be accomplished by use of the associated drywell sump flow integrator, flow recorder, or the pump curves and drywell sump pump out time. The system consists of a) the drywell floor drain sump*. monitoring system, orb) the drywell equipment drain sump monitoring system, but only when the drywell floor drain sump is overflowing. The identification of an increase in unidentified LEAKAGE will be delayed by the time required for the unidentified LEAKAGE to travel to the drywell sump and it may take longer than one hour to detect a 1 gpm increase in unidentified LEAKAGE, depending on the origin and magnitude of the LEAKAGE. This sensitivity is acceptable for containment sump monitor OPERABILITY. The reactor coolant contains radioactivity that, when released tb the primary containment, can be detected by the gaseous primary containment atmospheric radioactivity monitbr. Only one of the two detectors is required to be OPERABLE. A radioactivity detection system is included for monitoring gaseous activities because of its sensitivities and rapid resP.onses to RCS LEAKAGE, but it has recognized limitations. Reactor coolant radioactivity levels will be low during initial reactor startup and for a few weeks thereafter, until activated corrosion products have been formed and fission products appear from fuel element cladding contamination or cladding defects. If there are few fuel element cladding defects and low levels of activation it may not be possible for the gaseous *primary containment atmospheric radioattivity monitor.to detect *a 1 gpm increase within 1 hour during normal operation; However, the gaseous primary containment _atmospheric radioactivity monitor is OPERABLE when it is capable of. detecting a 1 gpm increase in unidentified LEAKAGE within 1 hour _given an RCS activity equivalent to that assumed in the calculations for the monitors (Reference 6). The LCD is satisfied when monitors diverse measurement are available. Thus, drywell sump monitoring system, in combination with a gaseous primary containment atmospherfc radioactivity monitor provides an acceptable minimum.

• In MODES 1, 2, 3, leakage detection systems are requjred to be OPERABLE to support LCD 3.4.4. This Applicability is consistent with that for LCO 3.4.4. (continued) B 3.4-26 Revision 93 BASES (continued) RCS Leakage Detection Instrumentation B 3.4.5 ACTIONS A.1. A.2. and A.3 PBAPS UN IT 2 With the drywell sump monitoring system inoperable, the only means of detecting LEAKAGE is the primary containment atmospheric gaseous radiation monitor. The primary containment atmospheric gaseous radiation monitor typically cannot detect a 1 gpm leak within one hour when RCS activity is low. In addition, this conf'iguration does not provide the requir.ed diverse means of leakage detection. Indirect methods of monitoring RCS leakage must be implemented. Grab samples of the primary containment atmosphere must be taken and analyzed and monitoring of RCS leakage by administrative means must be performed every 12 hours to provide alternate periodic . information. Administrative means. of monitoring RCS leakage include monitoring and trending parameters that may indicate an increase in RCS leakage. There are diverse alternative mechanisms from which appropriate indicators may be selected based on plant conditioni. It is not necessary to utilize all of these methods, but a method or methods should be selected considering the current plant conditions and historical or expected sources of unidentified leakage. The administrative methods are drywell pressure and temperature, Reactor Recirculation System pump seal pressure and temperature and motor cooler temperature indications, and Safety Relief Valves tailpipe temperature. These indications, cbupled with the atmospheric grab samples, are sufficient to alert the operating staff to an unexpected increase in unidentified LEAKAGE. The 12 hour interval is sufficient to detect increasing RCS leakage. The Required Action provides 7 days to restore another RCS leakage monitor to OPERABLE status to regain the intended leakage detection diversity. The 7 day Completion Time ensures that the plant will not be operated in a degraded configuration for a lengthy time period. B.1 and B.2 With the gasebus primary containment atmospheric monitoring channel inoperable, grab samples of the primary containment atmosphere must be taken and analyzed for gaseous radioactivity to provide periodic leakage information. Provided a sample is obtained and analyzed once every 12 hours, the plant may be operated for up to 30 days to allow restoration of the required monitor. continued B 3.4-26a Revision No. 93 I*. BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 RCS Leakage Detection Instrumentation B 3.4.5 B.l and B.2 (continued) The 12 hour interval provides periodic information that is adequate to detect LEAKAGE. The 30 day Completion Time for restoration recognizes that at least one other form of leakage detection is available. C.1 and C.2 If any Required Action and associated Completion Time of Condition A or B cannot be met, the plant must be brought to a MODE in the LCD does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to perform the actions in an orderly manner and without challenging plant systems. With all required monitors inoperable, no required automatic means of monitoring LEAKAGE are available, and immediate plant shutdown in accordance with LCD 3.0.3 is required. SR 3.4.5.l This SR for the performance of a CHANNEL CHECK of the required primary containment atmospheric monitoring system. The check gives reasonable confidence that channel is operating properly. * .. T.he Surveillance. Frequency is. controlled under the Surveillance Frequency.Control Program.
• continued B 3.4-27 :Revision No. 86
• BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UN IT 2 RCS Leakage Detection Instrumentation B 3.4.5 SR 3.4.5.2 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection instrumentation. The test ensures that the monitors can perform their function in the desired manner. The test also verifies the alarm setpoint and relative accuracy of the instrument string. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.4.5.3 This SR: is for the performance of a CHANNEL CALIBRATION of required leakage detectiori instrumentation channels. The calibration verifies the accuracy of the instrument string .. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 4.10.2. 2. Regulatory Guide 1.45, Revision 0, "Reactor Coolant Pressure BoOndary Leakage Detection Systems," May 1973. 3. GEAP-5620, "Failure Behavior in ASTM A106B Pipes Cont a i n i n g Ax i a l Th r o u g h -W a 11 Fl aw s , " A p r il 19 6 8
• 4. NUREG-75/067, "Investigation and Evaluation Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactors," October 1975. 5. UFSAR, Section 4.10.4. . 6. UFSAR, Section 4.10.3.2. B 3.4-28 No. 93. I I I I I l .* .... RCS Specific Activity B 3.4.6 B 3.4 REACTOR COOLANT SYSTEM (RCS) .B 3.4.6 RCS Specific Activity BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 * .. ., During circulation, the reactor coolant acquires radioactive materials due to release of fission products from fuel leaks into the reactor coolant and activation of corrosion products in the reactor coolant. These radioactive materials in the reactor coolalilt can* plate out in the RCS, ' -' and, at times, an accumulation will break away to spike the normal level of radioactivity. The release of coolant during a Design Basis Accident (OBA) could send. radioactive _materials into the environment. Limits on the maximum allowable 1 evel of radi cacti vi ty in the reactor coolant are to ensure that in the event of a release of any radioactive material to.the erivironment during a OBA, radiation are maintained within the limits of 10 CFR 50.67 (Ref. 1). LCD contains the iodine specific activity limits. The iodine activities per gram of reactor coolant are expressed in terms of a DOSE EQUIVALENT I-131. The _ al,lowable level is intended to limit the maximum 2 hour .radiation dose an individual at the site boundary to within the 10 CFR 50.67 limit as modified in Regulatory Table a. . Analytical involvitig radioactive
• __ in the primary coolant are in UFSAR _ (Ref. The specific activity in the (the source term) is an i ni ti al c,onditi on .for evaluation of the consequences of-an accident due io a steam line break (MSLB) outside No fuei. is postulated in the.MSLB accident, and the release of radioactive material to the environment: is assumed to end when.the main steam isolation valves (MSIVs) close completely. This MSLB release forms the determining offsite. doses (Ref. 2). The limits on the specific activity of tile primary coolant ensure that 2 hour TEDE d6ses at -. the .. site boundary, result fog from an MSLB outside * *
• contai.nment ol!ri ng steady state operation,: wi 11 not exceed the dose 10 tFR 50.61 as modified in *. Regulatory_ Guide 1.:183,Table 6. . -_.,.*.** . '.' . .* .. **-* . (continued)-. .
• r ' *
• B 3.4-29 Revision No. *_ 75 : ...

BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABILITY ACTIONS PBAPS UNIT 2 RCS Specific Activity B 3.4.6 The limits on specific activity are values from a*parametric evaluation of typical site locations. These limits are conservative because the evaluation considered more restrictive parameters than for a specific site, such as the location of the site boundary and the meteorological conditions of the site. RCS specific activity satisfies Criterion 2 of the NRC Policy Statement. The specific iodine activity is limited to s 0.2 µCi/gm DOSE EQUIVALENT I-131. This limit ensures the source term assumed in the safety analysis for the MSLB is not exceeded, so an*y rel ease of radioactivity to the environment during an MSLB is within the 10 CFR 50.67 limits as modified in Regulatory Guide 1.183, Table 6. In MODE 1. and MODES 2 and 3 with any main steam line not limits on the primary coolant radioactivity are applicable since there is an escape path for release of radioactive material from the primary coolant to the environment in the event of an MSLB outside of primary *containment. In MODES 2 and 3 with the main steam lines isolated, such limits do not apply since an estape path does not exist. In MODES 4 and 5, no limits are required since the reactor is not pressurized and the potential for leakage is reduced. A.1 and A.2* When the reactor coolant specific activity exceeds the LCO DOSE EQUIVALENT I-131 limit, but is s 4.0 µCi/gm, samples must be analyzed for DOSE I-131 at least once every 4 hours. In addition, the specific activity must be restored to the LCO limit within 48 hours. The Completion Time of once every 4 hours is based on the time needed to take and analyze a sample. The 48 hour Completion Time to restore the activity level provides a reasonable time for temporary coolant activity increases (iodine spikes) to be cleaned up with the normal processing systems. (continued) B 3 .4-30 Revision No. 75 BASES ACTIONS PBAPS UNIT 2 A.1 and A.2 (continued) RCS Specific Activity B 3.4.6 A Note permits the use of the prov1s1ons of LCO 3.0.4.c. This allowance permits entry into the applicable MODE(S) while relying on the ACTIONS. This allowance is acceptable due to the significant conservatism incorporated into the specific activity limit, the low probability of an event which is limiting due to exceeding this limit, and the ability to restore transient specific activity excursions while the plant remains at, or proceeds to, power operation. 8.1, 8.2.1, B.2.2.1j and 8.2.2.2 If the DOSE EQUIVALENT I-131 cannot be restored to 0.2 µCi/gm within 48 hours, or if at any time it is> 4.0 µCi/gm, it must be determined at least once every 4 hours and all the main steam lines must be isolated within 12 hours. Isolat-ing the main steam lines precludes the possibility of releasing radioactive material to the environment in an amount that is more than the requirements of 10 CFR,50.67 as modified in Regulatory Guide 1.183, Table 6, during a postulated MSLB_accident.

• Alternatively, the plant can be in MODE 3 within 12 hours and in MODE 4 within :36 hours. This option is provided for those instances when isolation of main steam lines is not desired (e.g., due to the decay heat loads). In MODE 4, the requirements of the LCO are no longer *
• The Completion Time of once every 4 hours is the time needed to* take and analyze c;i sample. The 12 hour Completion Time is reaso-nabl e' based on operating experience', to isolate the main steam lines an orderly manner Bnd without challenging plant systems. Also, the allowed Completion Ti mes for Required Ac_ti ans B. 2. 2. 1 and B. 2. 2. 2 for placing the in MODES 3 and 4 reasonable, based on operating to achieve the required plant c6nditions full power .condi ti on-s in an orderly manner and without challenging plani systems. (continued) _ B 3.4-31 Revision No. 75 BASES (continued) SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 SR 3.4.6.l RCS Specific Activity B 3.4.6 This Surveillance is performed to ensure iodine remains within limit during normal operation. The Surveillance Frequency is controlled under the Surveil-lance Frequency Control Program. *
• This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MObES is much 1 ess. 1. 10 CFR 50.67 .. 2. UFSAR, Section 14.6.5. B 3.4-32 Revision No. 86 RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.7 Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown BASES BACKGROUND APPLICABLE SAFETY ANALYSES LCO PBAPS tJNIT 2 Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to reduce the temperature of the reactor*coolant to s 212°F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for keeping the reactor in the Hot Shutdown condition. The RHR System has two loops with each loop consisting of two motor driven pumps, two heat exchangers, and associated piping and valves. There are two RHR shutdown cooling subsystems per RHR System loop. Both loops have a common suction from the same recirculation loop. The four redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to reactor via the associated recirculation loop. The RHR heat exchangers transfer heat to the High Pressure Service Water (HPSW) System. Any one of the four RHR shutdown cooling subsystems can provide the required decay heat removal function. Decay heat removal by operation of the RHR System in the shutdown cooling mode.is not required for mitigation of any event or accident evaluated in the safety analyses. Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR Shutdown Cooling System meets Criterion 4.of the NRC Policy Statement. Two RHR shutdown cooling subsystems are required to be OPERABLE, and when no recirculation pump is in operation, one shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, one heat exchanger, a HPSW pump capable of providing cooling to the heat exchanger, and the associatedpiping and valves. The two subsystems have a common suction source and are allowed to have common discharge piping. Sinc.e piping is a passive component that (continued) B 3.4-33
• Revision No. 0 BASES LCO (continued) APPLICABILITY PBAPS UN IT 2 RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 is assumed not to fail, it is allowed to be common to both subsystems. Each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. In MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. Management of gas voids is important to RHR Shutdown Cooling System 0 PERA B I LI TY . Note 1 permits both required RHR shutd6wn cooling subsystems and recirculation pumps to be shut down for a period of 2 hours in an 8 hour period. Note 2 allows one required RHR shutdown cooling subsystem to be inoperable for up to 2 hours for performance of Surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy. In MODE 3 with steam dome pressure below the RHR shutdown cooling isolation pressure (i.e., the actual pressure at which the RHR shutdown cooling isolation pressure setpoint clears) the RHR Shutdown Cooling System must be OPERABLE and shall be operated in the shutdown cooling mode to remove decay heat to reduce or maintain coolant temperature. Otherwise, a recirculation pump is required to be in operation. In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the RHR shutdown cooling isolation pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping: Decay heat removal at reactor pressures greater than or equal to the RHR shutdown cooling isolation pressure is typically accomplished by condensing the' steam in the main condenser. continued B 3.4-34 Revision No. 126 BASES APPLICABILITY (continued) ACTIONS PBAPS UN IT 2 RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems CECCS) (LCD 3.5.1, "ECCS-Operating") do not allow placing the RHR shutdown cooling subsystem into operation. The requirements for decay heat removal in MODES 4 and 5 are discussed in LCD 3.4.8, "Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown"; LCO 3.9.7, "Residual Heat Removal CRHR)-High Water Level"; and LCD 3.9.8, "Residual Heat Removal CRHR)-Low Water Level." A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Times, specifies bnce a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Requiyed Actions of Condition continue to apply for-each additional failure, with Completion Times based on initial entry into the Conditton. the Actions for shutdown appropriata compensatory measures for separate inoperable shutdown cooling
• As'such, a Note has been allows Coridition for eacih inoperable RHR shutdowh cool .. A.1. A.3 .With one shutdown cooling subsystem inoperable for except as permitted by LCD Note 2, the subsystem must be restored to OPERABLE status delai. Ih ihis tond4ticin, the remaining subsystem can provide the necessary decay heat removal. The continued -B 3.4-35 Revision 52 BASES ACTIONS PBAPS UNIT 2 RHR Shutdown Cooling Shutdown B 3.4.7 A.1. A.2. and A.3 (continued) overall reliability is reduced, however, because a single failure in the OPERABLE subsystem could result in reduced RHR shutdown cooling capability. Therefore, an alternate method of decay heat removal must be provided. With both required RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability. This* re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. The required cooling capacity of the alternate method should be ensured by verifying (by calculation or demonstration) its capability to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Condensate/Main Steam Systems and the Reactor Water Cleanup System. However, due to the potentially reduced retiability of the alternate methods of decay heat removal, it is also required tri reduce the reactor coolant temperature to the point where MODE 4 is entered. *
• R.1. B.2i and 8.3 With no RHR shutdotln cooling subsystem and no recirculation pump in.operation, except as permitted by LCO Note 1,. reactor coolant circulation by the RHR shutdown cooling subsystem Qr recirculation pump must be restored without
• ay. *. . . . . Until RHR or recirc.ulation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature. The 1 hour Completion Time is based on the coolant circulation function. and is modified such that .the 1 .hour is* applicable ** separately for each occurrence irivolving a<loss of coolant (continued} B Revision No. O BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAP.S UNIT 2 RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 B.l. B.2. and B.3 (continued) circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours thereafter. This will provide assurance of continued temperature monitoring capability. During the period when the reactor coolant is being circulated bj an alternate method (other ihan by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the method. The once per hour Cbmpletion Time is deemed appropriate.
• SR 3.4.7.1 This Surveillance verifies that one required RHR shutdown cooling or recirculation pump is in operation and circulating reactor coolant. The required flow rate is by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency C6ntrol Program. *This Surveillante is modified by a Note allowing sufficient time t6 align the RHR for shutdown cool operation* after clearing the pressure setpoint that isolates the or for placing a recirculation pump in The Nrite takes exception to the requirements of the Surveillance being met (i.e., forced coolant circulation is . not' required for this initial 2 hour period), which also allows entry into the Applicability of this Specification in accordance with SR 3.0.4 since the Surveillance will not be "not met" at the time of entry into the Applicability. SR 3.4.7.2 RHR Shutdown Cooling (SOC) System p1p1ng and components have the potential to develop voids and pockets of entrained Preventing and managing gas intrusion and accumµ1ation is for proper operation of the required RHR shutdown cooling subsystems and. may al so prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor. vessel. continued .* B Revision No. 126 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 RHR Shutdown Cooling System-Hot Shutdown. B 3.4.7 SR 3.4.7.2 (continued) Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and
• instrumentation drawings, isometric drawings, plan and elevation drawings, calculations, and operational procedures. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. For the RHR SDC piping on the discharge side of the RHR pump, acceptance criteria are .establ.ished for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the location (or the volume of gas at one or more susceptible locations exceeds an acceptance criteria for gas volume* in the RHR SOC piping on the discharge side of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas Ci .e., the system is sufficiently filled with the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria .limits. Sihce the RHR SOC piping on the discharge side of the pump is the same as the Low Pressure Coolant Injection pjping,
• performances of surveillances for ECCS TS may satisfy the requirements of this surveillance. For the RHR SOC piping on the suction side of the RHR the surveillance is met by virtue of the performance of operating procedures that ensure that the RHR SOC suction piping is filled and vented. The performance of these actions ensures that the surveillance is met. RHR SOC System locations on the discharge side of the RHR pump susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared. to the acceptance criteria for. the location. Susce*ptible locations iii the same system fl ow path which are subject to. the same gas * (continued B 3.4-37a Revision No. 127 ..

BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 SR 3.4.7.2 (continued) intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure OPERABILITY during the Surveillance interval. The SR may be met for one RHR SOC subsystem by virtue of

• having a subsystem in service in accordance with operating procedures. This SR is modified by two Notes. Note 1 that states the SR is not required to be performed until 12 hours after steam dome pressure is less than the RHR Shutdown Cooling System Isolation reactor pressure allowable value in TS Table In a rapid shutdown, there may be insufficient time to verify all susceptible locations prior to entering the Applicability. Note 2 to the Surveillance recognizes that the scope of the is limited to the RHR system components. The HPSW system components have been determined to not be required to be in the scope of this surveillance due to operating experience and the design of the system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation. None. B 3.4-37b Revision No. 126 RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.8 Residual Heat Removal (RHR) Sh*utdown Cooling System-Cold Shutdown BASES BACKGROUND APPLICABLE SAFETY.ANALYSES LCD PBAPS UNIT 2 Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to maintain the temperature of the reactor coolant :S 212°F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for keeping the reactor in the Cold Shutdown condition. The RHR System has two loops with each loop consisting of two motor driven pumps, two heat exchangers; and associated piping and valves. There are two RHR shutdown cooling subsystems per RHR System loop. Both loops have a common suction from the same recirculation loop. The four redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal. Each pump the reactor coolant, after circulation through the respective heat exchanger, to the reactor via the associated recirculation loop. The RHR heat exchangers transfer heat to the High Pressure Service Water (HPSW) System. Any one of the four RHR shutdown cooling subsystems can provide the requested decay heat removal function. Decay heat removal by operation*of the RHR.System in the shutdown cooling mode is not required for mitigation of any event or accident evaluated in the safety analyses. Decay heat removal is, however, an important safety function that must be. accomplished or core damage could res.ulL The RHR Shutdown Cooling System meets Criterion 4 of the NRC Policy Statement. * * . . Two RHR shutdown coollng subsystems are required to be*
• OPERABLE, .and when no recirculation pump is in operation, one RHR shutdown cooling subsystem m.ust be. in operation. An OPERABLE*RHR shutdown cooling.subsystem.consists of one OPERABLE RHR pump, one heat exchanger, a HPSW pump capable of providing cooling to the heat exchanger, and the associated piping and valves. The tw.o subsystems have a common suction source and are allowed to have conunon discharge Since piping is a passive component that is assumed not to fail, it is allowed to be common to both (continued) B 3.4-38 Revision No. 0 BASES LCO (continued) APPLICABILITY PBAPS UN IT 2 RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 subsystems. In MODE 4, the RHR cross tie valve (M0-2-10-020) may be opened (per LCO 3.5.2) to allow pumps in one loop to discharge through the opposite recirculation loop to make a complete subsystem. In addition, the HPSW cross-tie valve may be opened to allow an HPSW pump in one loop to provide cooling to a heat exchanger in the opposite loop to make a complete subsystem. Additionally, each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) ih the shutdown cooling mode for removal of decay In MODE 4, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required. However, to ensure adequate core flow to all.ow for accurate reactor coolant temperature monitoring, nearly continuous operation is required. Manage.ment of gas voids is important to RHR Shutdown Cooling System OPERABILITY. Note 1 permits both required RHR shutdown cooling subsystems to be shut down for a period of 2 hours in an 8 hour period. Note 2 allows one required RHR shutdown cooling subsystem to be inoperable for up to 2 hours for performance of Surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be Tow enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy. In MODE the RHR Shutdown Cooling System must be OPERABLE and shall be operated in the shutdown cooling mode to remove decay heat to maintain coolant below 212°F. Otherwise, a recirculation pump is required to be in* operation. In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the RHR shutdown cooling isolation pressure, this LCO is *not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping. Decay heat removal at reactor pressures above the RHR shutdown cooling isoJation pressure is typically accomplished by condensing the steam in the main conderiser. continued B 3.4-39 No. 126 BASES APPLICABILITY (continued) ACTIONS PBAPS UNIT 2 RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems (ECCS) (LCD 3.5.1, "ECCS-Operating") do not allow placing the RHR shutdown cooling subsystem into operation. The requirements for decay heat removal in MODE 3 below the RHR shutdown cooling isolation pressure and in MODE 5 are discussed in LCO 3.4.7, "Residual Heat Removal (RHR) Cooling System-Hot Shutdown"; LCO 3.9.7, "Residual Heat Removal (RHR)-High Water Level"; and LCO 3.9.8, "Residual Heat Removal (RHR)-Low Water Level." A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions. of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows
• separate Condition entry for each inoperable RHR shutdown cooling subsystem. With one of the two required RHR shutdown cooling subsystems inoperable, except as permitted by.LCD Note 2, the remaining subsystem is capable of providing the required decay heat removal. However, the overall reliability is reduced. Therefore, *an alternate method of decay heat removal must be provided. With both required RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability. This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO.
• The 1 hour . Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat (continued) ..
• B.3.4-40 Revision No. b BASES ACTIONS PBAPS UNIT 2 A.I (continued) RHR Shutdown Cooling Shutdown B 3.4.8 removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours thereafter. This will provide assurance of continued heat removal capability. The required cooling capacity of the alternate method should be ensured by verifying (by calculation or demonstration) its capability to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. _Alternate methods that can be used include (but are not limited to) the Condensate/Main Steam Systems (feed and bleed) and the Reactor Water Cleanup System. B.l and B.2 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as permitted by LCO Note I, and until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the circulation for monitoring coolant The I hour Completion Time is based on the coolant circulation function and is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours thereafter. This will provide assurance of continued temperature monitoring capability. During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed (continued) B 3.4-41 Revision No. 0 RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.4.8.1 This Surveillance verifies that one required RHR shutdown cooling subsystem or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.4.8.2 RHR Shutdown Cooling (SOC) System p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the required RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel. Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is on a review of system design including piping and instrumentation drawings, isometric drawings, plant and elevation drawings, calculations and operational procedures. The design review is supplemented by system walk downs to the system high points and to tonfirm the location and orientation of components that can become sources of gas or could otherwise cause gas to be trapped or difficult tQ remove during system maintenance or lbcations depend on plant and system configuration, such as stand-by versus operating* conditions. The RHR .Shutdown Cooli tig .system is OPERABLE* when it is
• suffi cienfl y filled with water. For the RHR SOC piping on the discharge side of RHR pump, acceptance criteria are established for the yol ume of accumulated gas at susceptible.locations,* rraccumulated*gas is discovered that exceed.s the. acceptance* criteria for the. susceptible *location,* (or. the volume.of accumulated gas at one or more 'susceptible' l ocati ohs exceeds an :acceptance criteria for gas volume irr the RHR SOC piping on the side of a . pump), the Surveillance is not met. If the accumulated gas i s el i mi n at ed o r b r o u g ht w i.t h i n t h e a c c e pt a n c e c r it e r i a limits during performance. bf the Survei 11 ance; the SR is met and sjstem OPERABILITY is under the
• Corrective Action Program. 1f it is determined by subsequent that the RHR Shutdowri Cooiing System is.not rendered inoperable by the:accumulated gas.Ci.e.*, the system is sufficiently fi 11 ed with water), the Surveillance (continued) B 3.4-42 .*. Revision No. 127 BASES SURVEILLANCE REQUIREMENTS REFEREN.C.ES PBAPS UNH 2
• RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 SR 3.4.8.2 (continued) may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits. Since the RHR SOC piping on the discharge side of the pump is the same as the Low Pressure Coolant Injection piping;, performances of surveillances for ECCS TS may satisfy the requirements of this surveillance. For the RHR SOC piping on the suction side of the RHR pump, the surveillance is met by virtue of the performance of operating procedures that ensure that the RHR SOC suction piping is adequately filled and vented. The performance of these manual actions ensures that the surveillance is met. RHR SOC System locations on the discharge side of the RHR pump susceptible to gas accumulation are moriitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location: Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a .representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring)*may be used to monitor the susceptible location Monitoring is not required for susceptible locations where the maximum potential accumulated gas void. volume has been evaluated and determined to not challenge System OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the should be sufficient to assure system OPERABILITY during.the Surveillance interval. *
• The SR can be met by virtue 6f having an RHR SDC subsystem in* accordance with operating procedures. The SR is modi fled by The Note that the scope of the surveillance-is limited to the RHR system components. The HPSW .system components have been det.ermi.ned to not be requ'ir.ed to be in the* scope of this surveillance due to operating experience ana the design of . the system.: * ** The Surveillance* Frequency is controlled under. the Surveillance Frequency Control Program. The Surveillance may by location to gas accumulation.
• None. B 3 .4-42a Revision No. 126 RCS PIT Limits B 3.4.9 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.9 RCS Pressure and Temperature (P/T) Limits BASES BACKGROUND PBAPS UN IT 2 All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cool down) power transients, and reactor trips. This LCO limits the pressure temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation. The PRESSURE AND TEMPERATURE LIMITS REPORT CPTLR) (Ref. 10) contains P/T limit curves for heatup, cooldown, and inservice leakage and hydrostatic testing, and also limits the maximum rate of change of reactor coolant temperature. The crititality curve provides limits for both heatup and criticality. Each P/T limit curve defines an acceptable region for normal operation. The usual use of the curves is operational guidance during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and co-mpared to the applicable curve to determine that operation is the allowable region. The LCO establishes operating limits that provide a margin to brittle of the vessel and piping of the reactor coolant boundary CRCPB). The vessel is component most subject to failure. Therefore,-the LCO limits apply to the vessel. 10 CFR 50, Appendix G (Ref. 1), requi re.s the es ta bl ishment of P/T limits for material _fracture toughness requirements. of the RCPB .materials. Reference 1 requires an adequate margin to b'rittl e failure during normal operation, abnormal 6perational transients, and system hydrostatic tests. It ma_ndates the use oftheASME Code,. SectiOn III, Appendix G (Ref. 2). The actual shift in the RTNor of the vessel material will be established periodically by removing and evaluating the irradiated reactor vessel material specimens, in accordance with the UFSAR (Ref. 3) and Appendix H Of 10 CFR 50 . (Ref.. 4). **The operating P /T limit curves wi 11 be adjusted_, as necessary, based on the_eyaluation findings and the .recommendations of Reference.5. continued B 3.4-43 Revision 102 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UN IT 2 RCS P/T Limits B 3.4.9 The P/T limit curves are composite curves established by superimposing limits derived from stress analyses of those portions of the reactor vessel and head that are the most restrictive. At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span of the P/T limit curves, different locations are more restrictive, and, thus, the curves are composites Df the most restrictive regions. The heatup curve represents a different set of restrictions than the cooldown curve because the directions of the thermal gradients through the vessel wall are reversed. The thermal gradient reversal alters the location of the tensile stress between the outer and inner walls. The criticality limits incl.ude the Reference 1 requirement that they be at least 40°F above the heatup curve or the cooldown curve and not lower than 60°F above the adjusted reference temperature of the reactor vessel material in the region that is controlling (reactor vessel flange region). The consequence of violating the LCO limits is that the RCS has been operated under conditions that can result in brittle failure of the. reactor pressure vessel, possibly leading to a nonisolable leak or loss of coolant accident. In the event these limits are exceeded. an evaluation must be performed to determine the effect on the structural integrity of the RCPB components. ASME Code, Section XI, Appendix E (Ref. 6), provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits. The P/T limits are not derived from Design Basis Accident (OBA) analyses. They are prescribed during normal operation to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the reactor pressure vessel, a condition that is unanalyzed. Since the P/T limits are not derived from any OBA, there are no acceptance limits related to the P/T limits. Rather, the P/T limits are acceptance limits themselves since they preclude operation in an unanalyzed condition. continued B 3.4-44 Revision No. 102 BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UN IT 2 RCS PIT Limits B 3.4.9 RCS PIT limits satisfy Criterion 2 of the NRC Policy Statement. The elements of this LCO are: a. RCS pressure and temperature are within the limits specified in the PTLR and heatup or cooldown rates are within the limits specified in the PTLR;
• b. The temperature difference between the reactor vessel bottom head coolant and the reactor pressure vessel CRPV) coolant is within the limits specified in the PTlR during recirculation pump startup; c. The temperature difference between the reactor coolant in the respective re.ci rcul ati on loop and. in the reactor is within the limits specified in the PTLR during pump startup; d. RCS pressure and temperature are within the criticality limits specified in the PTLR, prior to achieving criticality; and e. The reactor vessel and the flange are within the limits specified in the PTLR when tensioning the re_actor vessei head bolting . studs. These *limits define allowable operating regions and permit a large n.umber of operating cycles while also providing a wide margin to failure. * . The of change of temperature limits controls the thermal gradient .through* the vessel wall and is used as input for calculating the heatup, cooldown; and leakage and testing P/T limit curves. Thus) the LCO for the ra'te*or. change*of temperature restrfrts stresses :*caused by thermal gradients and* al so ensures the validity of the P/T limit turves. continued 83.4-45. Revision No .. 102 BASES LCO (continued) APPLICABILITY ACTIONS PBAPSUNIT 2 RCS PIT Limits B 3.4.9 Violation of the limits places the reactor vessel outside of the bounds of the stress analyses and can increase stresses in other RCS components. The consequences depend on several factors, as follows: a. The severity of the departure from the allowable operating pressure temperature regime or the severity of the rate of change of temperature; b. The length of time the limits were violated (longer violations allow the temperature gradient in the thick vessel walls to become more pronounced); and c. The existences, sizes, and orientations of flaws in the vessel material. The potential for violating a P/T limit exists at all times. For example, P/T limit violations could result from ambient temperature conditions that result in the reactor vessel metal temperature being less than the minimum allowed tempefature for boltup. *.Therefore, this LCO is applicable even when fuel is not loaded in the core. A.l and A.2 Operation the P/T limits in the PTLR while in MODES 1, 2, and 3 must be so that the RCPB is returned to a condition that has been verified by stress analyses . . The 30 minute Completion Time reflects the vrgency of restoring the to within the analyzed range. M6st violations will not be severe, and the activity can be accomplished *in this time in a controlled manner . . Besides. restoring within an evaluation is required to determine if RCS opera ti on can continue. The must the remains and be if cbntinued operation is desired. Several methods may be used, including with transients in the stress analyses, new or inspection of the . * --* ! '.... -.-: * * * ':
• ASME Code, .Section XI, Appendix E (Ref. 6), may be used to support the evaluation .. However, its use is restricted. to evaluation of t_he vessel be'ltl i ne. continued B 3.4-46. Rei.ti si on 102 BASES ACTIONS PBAPS UNIT 2 A.l and A.2 (continued) RCS P/T Limits B 3.4.9 The 72 hour Completion Time is reasonable to accomplish the evaluation of a mild violation. More severe violations may *require special, event specific stress analyses or inspections. A favorable evaluation must be completed if continued operation is desired. Condition A is modified by a Note requiring Required Action A.2 be completed whenever the Ctindition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits. Restoration alone per Required Action A.l is insufficient because higher than analyzed stresses may have occurred and may have affected the RCPB integrity. -B.l and B.2 If a Required Action and associated Completion Time of *Condition A are not met, the plant must be placed.in a lower MODE either the RCS remained in an unacceptable P/T region for an extended period of increased stress, or a sufficiently severe event caused entry into an unacceptable region. Either possibility indicates a need for more careful cif event, best accomplished with the RCS at reduced and temperature. With the reduced pressure and temperature the possibility of propagation of undetected flaws is decreased. and are reduced by placing the plant in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. The allowed Times are reasonatile, on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. C.l and C.2 Operation outside the P/T limits in the PTLR in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses. The Required Action be init1ated without delay and continued until the limits are restored. continued B 3.4-47 Revision No. 102 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 C.l and C.2 (continued) RCS P/T Limits B 3.4.9 Besides restoring the P/T limit parameters to within limits, an evaluation is required to determine if RCS operation is allowed. This evaluation must verify that the RCPB integrity is acceptable and must be completed before approaching criticality or heating up to> 212°F. Several methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components. ASME Code, Section XI, Appendix E (Ref. 6), may be used to support the evaluation; however, its use is restricted to evaluation of the beltline. SR 3.4.9.1 Verif1cation that operation is within the PTLR limits is required when RCS pressure and temperature conditions are undergoing planned changes. Plant procedures specify the pressure and temperature monitoring points to be used during the performance of this Surveillance. The Surveillance Frequehcy is controlled under the Frequency Control Program. Surveillance for heatup, cooldown, or inservice and* hydrostatic testing may be discontinued when the criteria given in the relevant plant procedure for ending the activity are satisfied. This SR has been modified with a Note that requires this Surveillance to be only during system heatup and cooldown operations and inser0ice leakage .and hydrostatic testing. SR 3.4.9.2 A separate limit in the PTLR is. used when the reactor is I approaching Consequently, the RCS pressure and temperature must be verified within appropriate before withdrawing control rods that will make the reactor .critical. B 3.4-48 Revision No.*102 BASES SURVEILLANCE REQUIREMENTS PBAPS UN.IT 2. SR 3.4.9.2 (continued) RCS P/T Limits B 3.4.9 the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal. SR 3.4.9.3 and SR 3.4.9.4 Differential temperatures within the applicable limits in the PTLR ensure that thermal stresses resulting from the startup of an idle pump will not exceed design allowances. Iri addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation loop (Ref. 9) are satisfied. Performing the Surveillance within 15 minutes before starting the idle recirculation pump provides adequate assurance that the limits will not be.exceeded between the time of the Surveillance and the time of the idle pump. start. An Bcceptable means of demonstrating compliance with the temperature differential requirement SR 3.4.9.4 is to compare of the operating recirculation loop and the idle loop. *
• SR 3.4.9.3 and SR have been modified by a Note that requires the Surveillance t6 be met onlj in MODES 1, 2, 3, and 4. MODE 5, the overall stress on limiting components is lower. :Therefore, limits are not required. The Note also states the required to be met a recirculation _pump startup, this is when the stresses occur. SR 3 .4 . 9 . 5 . SR . 3 . 4 . 9 . 6 . a*n d SR 3 . 4 . 9 . 7 :** Limits *in the PTLR .on the reactor vessel flange and head flanga are generally bounded by the other P/T limits during system heatup and cooldown. However, operations MODE 4 from MOO[ 5 and in MODE 4 with RCS or to specified require assurance that these meet the LCO limits. . .. . continued ... Revision No. 102 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2. ' RCS PIT Limits B 3.4.9 SR 3.4.9.5. SR 3:4.9.6. and SR 3.4.9.7 (continued) The flange temperatures must be verified to be above the limits in PTLR before and while tensioning the vessel head bolting studs to ensure that once the head is tensioned the limits are satisfied. When in MODE 4 with RCS temperatures 80°F, checks of the flange temperatures are required because of the reduced margin to the limits. When in MODE 4 with RCS temperature s l00°F, monitoring of the flange temperature is required to ensure the temperature is within the limits specified in the PTLR. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.4.9.5 is modified by a Note that requires the Surveillance to be performed only when tensioning the reactor vessel head bol ti.ng studs. SR 3. 4. 9. 6 is modified by a Note that requires the Surveillance to be initiated after RCS temperatures 80°F in MODE 4. SR 3.4.9.7 is mod1fied by a Note that requires the Surveillance to be after RCS temperatures l00°F in MODE 4. The Notes contained in these SRs are necessary to specify when the reactor flange and head flange temperatures are required to be verified to be within .the .limits specified, 1. 10 CFR 50, Appendix G. 2*. ASME, Boil er and. Pressure Vessel Code,* Section I I I, Appendix G. 3. DFSAR, Section and Appendix K. 4. 10 CFR, 50' -.Appendjx H. 5. f.99, Revision 2, May continued B 3.4-50 Revi.sion No. 102 BASES REFERENCES (continued) PBAPS UN IT 2 RCS PIT Limits B 3.4.9 6. ASME, Boil er and Pressure Vessel Code, Section XI, Appendix E. 7. DELETED 8. DELETED 9. UFSAR, Section 14.5.6.2. 10. PRESSURE AND TEMPERATURE LIMITS REPORT. B Revision No .. 102 Reactor Steam Dome Pressure B 3.4.10 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.10 Reactor Steam Dome Pressure BASES BACKGROUND APPLICABLE SAFETY ANALYSES LCD APPLICABILITY PBAPS UN IT 2 The reactor steam dome pressure is an assumed value in the determination of compliance with reactor pressure vessel overpressure protection criteria and is also an assumed initial condition of design basis accidents and transients. The reactor steam dome pressure of s 1053 psig is an initial condition of the vessel overpressure protection analysis of Reference 1. This analysis assumes an initial maximum reactor steam dome pressure and evaluates the resp9nse of the pressure relief system; primarily the safety/relief valves, during the limiting pressurization transient. The determination of compliance with the overpressure criteria is dependent on the initial reactor steam dome pressure; therefore, the limit on this pressure ensures that the of the overpressure protection analysis are conserved. Reference 2 along Reference 1 assumes an initial reactor steam dome for the analysis of design basis accidents and transients used to determine the limits for fuel cladding integrity (see Bases for LCO 3.2.2, .MINIMUM CRITICAL POWER RATIO CMCPR)") and 1% . . cladding plastic strain (see Bases for LCD 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)"). ' Reactor steam dome pressure satisfies the requirements of 2 of the NRC Policy Statement. The specified reactor dome preisure lfmit of s 1053 ensures the plant is operated within the assumptions of the reactor overpressure protection analysis. Operation above the limit may result in a transient mo re s e v e re th a n a ri a l y zed . * * *
• In MODES 1 and 2, _the reactor steam dome pressure.is re qui red to. be less th an or equal to the limit. In these ** MODES, reactor may be generating sigriificant steam and the events-which may challenge the overpressure limits are possible. ' .-. continued . B Revision No. _49 BASES APPLICABILITY (continued) ACTIONS SU RV EI LLANC E
• REQUIREMENTS REFERENCES PBAPS UNIT 2 Reactor Steam Dome Pressure B 3.4.10 In MODES 3, 4, and 5, the limit is not applicable because the reactor is shut down. In these MODES, the reactor pressure is well below the required limit, and no anticipated events will challenge the overpressure limits. With the reactor steam dome pressure greater than the limit, prompt action should be taken to reduce pressure to below the limit and return the reactor to operation within the bounds of the analyses. The 15 minute Completion Time is reasonable considering the importance of maintaining the within limits. This Completion Time also ensures that the probability of an accident occurring while pressure is greater than the limit is minimized. If the reactor steam dome pressure cannot be restored to within the *limit within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. SR 3.4.10.1 Verification that reactor steam dome pressure is 1053 psig ensures that the initial conditions of the reactor overpressure protection analysis and design basis accidents are met. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NEDC-33566P, "Safety Analysis Report for Exel on Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 2. UfSAR, Chapter 14. B 3.4-53 Revision No. 114

.-ECCS-Operating B 3.5.1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION . COOLING (RCIC) SYSTEM B 3.5.1 ECCS-Operating BASES BACKGROUND ',.,* ..., PBAPS UNIT 2 The ECCS are designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The ECCS network consists of the High Pressure Coolant Injection (HPCI) System, the Core Spray (CS) System, the low*pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System, and the Automatic Depressurization System (ADS). The suppression pool provides the required source of water for the ECCS. Although no credit is taken in the safety analyses for the condensate storage tank (CST), it is capable of providing a source of water for the HPCI and CS systems. On receipt of an initiation signal, ECCS pumps automatically start; simultaneously, the system aligns and the pumps inject water, taken either from the CST or suppression pool, into the Reactor Coolant System (RCS) as RCS pressure is overcome by the discharge pressure of the ECCS pumps. Although the system is initiated, ADS action is delayed, allowing the operator to interrupt the timed sequence if the system is not needed. The HPCI pump discharge pressure

• almost immediately exceeds that of the RCS, and the pump injects.coolant into the vessel to cool the core. If the break is small, the HPCI System will maintain coolant inventory as well as 'vessel level while 'the RCS is still *If HPCr it is backed up by ADS in* combination with LPCI and CS. In this event, the ADS timed sequence would be allowed* to time out and open the selected safety/relief valves (S/RVs) depressurizing the RCS, thus
• allowing the LPCI arid CS *to. overcome RCS pressure and inject coolant inlo th .. e vessel. If the break is large*, RCS * ** pressure initially drops rapidly and the LPCI and CS cool the core. *
• Water frcim the break returns to the suppression pool where it is used again and again. Water in the suppression pool
• is .circulated through an RHR System heat exchanger cooled by the High Pressure .Service Water System.
• Depending on the location and size of the break, of the ECCS may be .-Ccontinuedl B. 3.5-1 Revision o I BASES BACKGROUND (continued) 'PBAPS UNIT 2 ECCS-Operating B 3.5.1 ineffective; however,the overall design is effective in cooling the core regardless of the size or location of the piping break. All ECCS subsystems are designed to ensure that no single active component flilure will prevent automatic initiation and successful operation of the minimum required ECCS equipment. The CS System (Ref. 1) is composed of two independent subsystems. Each subsystem consists of twQ 50% capacity motor driven pumps, a spray sparger above the core'* and piping and valves to transfer water from the suppression pool to the sparger. The CS System is designed to provide cooling to the reactor core when reactor pressure is low. Upon receipt of an initiation signal, the CS pumps in both subsystems are automatically started (if offsite power is available, A and C pumps in approximately 13 seconds, and B and D pumps in approximately 23 seconds, and if offsite power is not available, all pumps 6 seconds after AC power is available). When the. RPV pressure drops suffi.ciently, CS System flow to the RPV begins. A full flow test line is provided to route water from and to the suppression pool to allow testing of the CS System without spraying water in the RPV.
• LPCI is an independent operating mode of the RHR System. There are two LPCI subsystems (Ref. 2), each consisting of two motor driven pumps and piping and valves.to transfer water from the suppression pool to the RPV via the corresponding recirculation loop. The two LPCI pumps and associated motor operated valves in each LPCI subsystem are powered from separate 4 kVemergency buses.* Both pumps in a LPc1*subsystem inject water into the reactor vessel through a connnon inboard injection valve and depend on the closure of the recirculation pump discharge valve following a LPCI injection signal. Therefore, each LPCI subsystems' common inboard injection valve and recirculation pump discharge valve is powered from one of the two 4 kV emergency buses associated with that subsystem (normal source) and has the capability for automatic transfer to the second 4 kV emergency bus associated with that LPCI subsystem. The ability to provide power to the inboard injection valve and the recirculation pump discharge valve from either 4 kV emergency bus associated with the LPCI subsystem ensures that the single failure of a* diesel generator (DG) will not result in the failure of both LPCI in one subsystem. (continued) Revision No.* o BASES BACKGROUND (continued) PBAPS .UN IT 2 ECCS-Operati ng B 3.5.1 The two LPCI subsystems can be interconnected via the LPCI cross tie valve; however, the cross tie valve is maintained closed with its power removed to prevent loss of both LPCI subsystems during a LOCA. The LPCI subsystems are designed to provide core cooling at low RPV pressure. Upon receipt of an initiation signal, all four LPCI pumps are automatically started (if offs{te power is available, A and B pumps in approximately 2 seconds and C and 0 pumps in approximately 8 seconds, and, if offsite power is not available, all pumps immediately after AC power is available). Since one DG supplies power to an RHR pump in both units, the RHR pump breakers are interlocked between units to prevent operation of an RHR pump from both units on one DG and potentially overloading the affected DG. RHR System valves in the LPCI flow path are
• positioned to ensure the proper flow path for water .from the suppression pool to inject into the recirculation loops. When the RPV pressure drops sufficiently, the LPCI flow to the RPV, via the corresponding begins. The water then enters the reactor through the jet pumps. Full flow test lines are the four LPCI pumps to route water to the suppression pool, to allow testing of the LPCI pumps without injecting water into the RPV. These test lines also provide suppression pool cooling capability, as described in LCD 3.6.2.3, "RHR Suppression Pool Cooling." The HPCI System (Ref. 3) consists of a steam driven turbine. pump unit, and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the tore via the feedwater line, where the coolant is distributed within the RPV th0ough the feedwater sparger. Suction piping for the system is provided fr6m the CST and. the-suppression pool. Pump suction for HPCI is aligned to the CST source to minimize injection of suppression pool water into the RPV. However, if the CST water supply is low, or if the suppression pool level is high, an automatic transfer to the suppression pool water source ensures a water supply for Continaous of the HPCI System. The steam supply to the HPCI turbine is piped from a main steam line upstream of the associated inboard main steam isolation valve. The HPCI System is designed to cooling a wide of reactor pressures (150 psig to 1170 psig). Upon receipt_ of an initiation signal, the HPCI turbine stop valve arid turbine control valve open and the
• to a specified speed. As the HPCI flow continued B 3.5-3 Revision 110 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UN IT 2 ECCS-Operating . B 3. 5 .1 increases, the turbine governor valve is automatically adjusted to maintain design flow. Exhaust steam from the HPCI turbine is discharged to the suppression pool. A full flow test line is provided to route water back to the CST to allow testing of the HPCI System during normal operation without injecting water into the RPV. The ECCS pumps are provided with m1n1mum flow bypass lines, which discharge to the suppression pool. The valves in these lines automatically open to prevent pump damage due to overheating when other discharge line valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, all ECCS pump discharge lines are filled with water. The LPCI and CS System discharge lines are kept full of water using a "keep fi 11" system. The HPCI System is normally aligned to the CST. The height of water in the CST is sufficient to maintain the piping full of water up to the first isolation valve. The relative height of the feedwater line connection for HPCI is such that the water in the feedwater lines keeps the remaining portion of the HPCI discharge line full of water. Therefore, HPCI does not require a "keep fi 11" system. The Nuclear System Pressure Relief System consists of 3 safety valves CSVs) and 11 safety/relief valves CS/RVs). The ADS (Ref. 4) consists of 5 of the 11 S/RVs.
• It is designed to provide depressurization of the RCS during a small break LOCA if HPCI *fails or is unable to maintain required water level in the RPV. ADS operation reduces the RPV pressure to within the operating pressure range of the low pressure ECCS subsystems (CS and LPCI), so that these subsystems can provide coolant inventory makeup. Each of the S/RVs used for automatic depressurization is equipped with one nitrogen accumulator and associated inlet check valves .. The accumulator provides the pneumatic power to actuate the valves. The ECCS performance is evaluated for the entire spectrum of break sizes for a postulated LOCA. The accidents for which ECCS operation is required are presented in Reference 5. The required analyses and assumptions are defined in Reference 6. The results of these analyses are described in References 7, 14, and 15. continued B 3.5-.4 Revision No. 125 BASES APPLICABLE SAFETY ANALYSES (continued) LCD . ':.*** PBAPS UN IT 2 \ ECCS-Operating B 3.5.1 This LCD helps to ensure that the following acceptance criteria for the ECCS, established by 10 CFR 50.46 (Ref. 8), will be met following a LOCA, assuming the worst case single active component failure in the EC\S: a. Maximum fuel element cladding temperature is s 2200°F; b. Maximum cladding oxidation is s 0.17 times the total cladding thickness before oxidation; c. Maximum hydrogen generation from a zirconium water reaction is s 0.01 times the hypothetical amount that would be generated if all of the* metal in the cladding surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react; d. The core is maintained in a coolable geometry; and e. Adequate long term cooling capability is maintained. The limittng single failures are discussed in References 7, 14, and Jhe OPERABLE ECCS subsystems provide the capability to adetjuately cool the core and prevent excessive fuel damage. The ECCS satisfy Criterion 3 of the NRC Policy Statement. Each ECCS'injection/spray and .five ADS valves are to be OPERABLE. The ECCS injection/spray subsystems are defined as the two CS subsystems; the two LPCI subsystems, and one HPCI System; The low pr.es sure ECCS i nj_ecti on/spray subsysfems are defined as the two CS subsystems arid the two LPCI subsystems.
• Management of gas *. voids is important to* ECCS i nj e.cti on/spray subsystem OPERABILITY: . .* -With ihan number of ECCS subsystems . OPERABLE, the poteDti al exists that.during a l irhi ting design basis LOCA concurrent with the worst case single failure; the limits tn could be All ECCS subsystems must therefore be OPERABLE to satisfy the single criterion required bY Reference 8. ' . A lPCI subsystem is inoperable during alignment
• and operation. for decay heat removal when below the actual
• RHR shutdown cooling i_sol ati on pressure in MODE 3; si nee transferring from the shutdown* cooling mode to the .LPCI mode could result in pump cavitation ,and voiding in the suction.* continued B 3.5-5 Revision No. 126 BASES LCD (continued) APPLICABILITY ACTIONS PBAPS UN IT 2 ECCS-Operating B 3.5.1 p1p1ng, resulting in the potential to damage the RHR including water hammer. This is necessary since the RHR System is required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. At these low pressures and decay heat levels, a reduced complement of ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling when necessary. One LPCI subsystem shall be declared inoperable when M0-34A(B) and M0-39A(B) are simultaneously open in the same subsystem (one or both subsystems) with no Emergency Diesel Generators (EDGs) declared inoperable to ensure compliance to References 7, 14, and 15 single failure analyses (Ref. 11). If the M0-34A and M0-39A are simultaneously open, the subsystem of LPCI shall be declared inoperable unless the E-2, or E-4 EDG is declared inoperable, If the M0-34B and M0-39B are simultaneously open, 'B' subsystem of LPCI shall be declared inoperable unless the E-1, E-2, or E-3. EDG is declared inoperable. All ECCS subsystems are required to be OPERABLE during MODES 1, 2, and 3, when there is considerable energy in the reactor core and core cooling would be required to prevent fuel in the event of a break in the primary system piping. In MODES 2 and 3, when reactor steam dome pressure is s 150 psig, HPCI is not required to be OPERABLE because the low pressure ECCS subsystems can sufficient flow belo0* this pressure. In MODES 2 and 3, when reactor steam dome pressure is s 100 psig, ADS is not required to be OPERABLE because the low pressure ECCS subsystems can sufficient flow below this pressure. ECCS requirements for MODES 4 and 5 are specified in LCD 3.5.2, "ECCS-Shutdown." A Note prcihibits the application of LCO 3.0.4.b to an inoperable. HPCI subsystem.
• There is an increased risk with a MODE or other:specified.condition in the Applicability with an inoperable HPCI subsystem and the. provisions of LCO 3.0-.4<b, which allow-entry into a M_ODE o.r' other .specified condition in the Applicability with the *
• LCD not met after performance of a risk assessment. address"ing "inoperable systems and components, should not be applied in this circumstance.
• continued B 3.5-6 Revision No. 112

.BASES ECCS-Operati ng B 3.5.1 ACTIONS A.1 (continued) PBAPS UN IT 2 If any one low pressure ECCS injection/spray subsystem is *inoperable, or if one LPCI pump in each subsystem is inoperable, all inoperable subsystems must be restored to OPERABLE status within 7 days (e.g., if one LPCI pump in each subsystem is inoperable, both must be restored within 7 days). In this Condition, the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced, a single failure in one of the remaining OPERABLE subsystems, concurrent with a LOCA, may result in the ECCS not being able to perform its intended safety furiction. The 7 day Completion Time is based on a reliability study (Ref. 9) that evaluated *the impact on ECCS availability, assuming various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times Ci .e., Completion Ti mes) . continued B 3.5-6a Revision No. 96' I BASES ECCS-Operat i ng B 3.5.1 ACTIONS B.1 (continued) PBAPS UNIT 2 If the inoperable low pressure ECCS subsystem cannot be *restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 12) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. C.l and C.2 If the HPCI System is inoperable and the RCIC System is immediately verified to be OPERABLE, the HPCI System must be restored to OPERABLE status within 14 days. In this Condition, adequate core cooling is ensured by the OPERABILITY of the redundant and diverse low pressure ECCS injection/spray subsystems in conjunction with ADS. Also, the RCIC System will automatically provide makeup water at reactor operating pressures. verification of RCIC DPERABlLITY is therefore required when HPCI is This may be performed as an administrative check by examining logs or other to determine if RCIC is out of service for maintenance or other reasons. It does not mean to perform the Surveillances needed to the OPERABILITY of the RCIC System. If the OPERABILITY of the RCIC System cannot be verified immediately, however, Condition G must be immediately entered. If a single active fails concurrent with a design basis LOCA, there is a potential, depending on the specific failure, that the minimum required ECCS equipment will not be available. A 14 day Completion Time is based on a reliability study cited in Reference 9 and has been found to be acceptable through operating experience. D.1 and D.2 If any one low pressure ECCS injection/spray subsystem is inoperable in addition to an inoperable HPCI System, the inoperable low pressure ECCS injection/spray subsystem or the HPCI System must be restored to OPERABLE statDs within 72 hours. In this Condition, adequate core cooling is continued B 3.5-7 Revision No. 89 BASES ACTIONS PBAPS UNIT 2 D.l and D.2 (continued) ECCS-Operating B 3.5.1 ensured by the OPERABILITY of the ADS and the remaining low pressure ECCS subsystems. However, the overall ECCS reliability is significantly reduced because a single failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function. Since both a high pressure system CHPCI) and a low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours is required to restore the HPCI System the low pressure ECCS injection/spray subsystem to OPERABLE This Completion Time is based on a reliability study cited in Reference 9 and has been found to be acceptable through operating experience. Ll The LCG requires five .ADS valves to be OPERABLE in order to provide the .ADS function (Refs. 7, 14, and 15). A single fail*ure in the ADS valves results in a reduction* in depressurization capability.* The 14 day Completion Time is based on a reliability study cited in Reference *g and has *been found to be acceptable through operating experience. F.1 and F.2 If any oae low pressure ECCS injection/spray subsystem is* inoperable in addition to one inoperable ADS valve, adequate co.re cooling is ensured by the.OPERABILITY of HPCI and the ECCS ihjectibn/Spray subsystem. overall ECCS reliability is reduced because a *single active comporient concurrent with a design basis LOCA coulc!_result .in the minimum required ECCS

• equipment not.being available. Si nee both a high pressure system (ADS) and. a low pressure subsystem are -inoperable, ;a * **more restrictive Completion Time of 72 hours -is required to restore either ttie *1 ow pressure E'.CCS subsystem or the ADS valve to OPERABLE status. This Completion Time is based on a reliability study cited in* Reference 9 and has been found. to be:atteptable experience.** (continued) B*3.5-8 Revision 101 BASES . ECCS-Operati ng B 3.5.1 ACTIONS G.1 (continued) SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 If any Required Action and associated Completion Time of Condition C, D, E or F is not met, the plant must be brought to a MODE in which the overall plant risk is To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower thari the risk in MODE 4 (Ref. 12) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into .MODE 4 may be made as it is also an acceptable risk state. The allowed Completion Time is reasonable, based on operating experience, to reach* the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. H.l and H.2 If two. or* more ADS valvei are inoperable, there is a reduction in the depressurization The plant must be brought *to a condit{on in which the LCO does not apply. To this status, the plant must be brought to at least MODE 3 within 12 hours.and reactor steam dome reduced to s 100 psig within 36 hours. Tha allowed. Cbmpletion Times are reasonable, based on operating experiente; to 0each the required plant conditions from full power conditi6ns in an orderly manner and without challenging*plant When multiple ECCS *sub.systems> a re* i noperabl_e (for reasons other-than the second of as i*n Condition I, the plant 1s i.n a_ condition outside of the acc-identanalyses, Therefore, LCO 3.0.3 must be entered *.immediately: . * * . SR 3'. 5 .1.1 The ECCS injection/spray sl)bsystem fl ow path p1 p1 ng and *have the potential to develop and . pockets .. Preventing gas *
• intrusion and accumulation is necessary for -*proper operation-of the ECCS injection/spray subsys_tems and m13y (continued) B Revision No. 126 * *
• BASES SURVEILLANCE REQUIREMENTS PBAP$ UN IT 2 SR 3.5.1.1 (continued) ECCS-Operating B 3.5.1 also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel. Selection of ECCS subsystem locations to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenante or restoration. Susceptible locations depend ori plant and system confi.guration, such as stand-by versus operating conditions. The ECCS injection/spray subsystem is OPERABLE when it is suffi ci entl y fi 11 ed with water. Acceptance criteria a re established for the volume of accumulited gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location Cor the volume of accumulated gas at one or more *susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not If the accumulated gas is. or brought within the acceptance limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated under.the Corrective Action Program. If it is determined by subsequent evaluation that the ECCS injection/spray subsystems are not rendered inoperable by the accumulated gas Ci .e., the system sufficiently filled with water), the Surveillance *may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits. ECCS injection/spray subsystem locations susceptible to gas accumulation are monitored and, if gas is found, gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representati.ve subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g .* parameters, remote monitoring) may be used (continued) B 3.5-10 No: 127 .. '

BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2. SR 3.5.1.1 (continued) ECCS-Operating B 3.5.1 to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance i nterva 1

• The Surveillance Frequency is controlled under the surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation. SR 3.5.1.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to . locking, sealing, or securing. A valve that receives an initi*ation signal allowed to in a. nonaccident position . provided the valve will automatically reposition in the
• proper stroke time. This SR does not require any testing br valve manipulation; rather; it involves verification that those.valves capable of potentially being* mispositiOned are in the correct position .. This SR does not to valves cannot be inadverteritly misaligned, as check valves. For the HPCI System, this SR includes the steam flow path for:the turbine the controller position. For the RHR verify RHR heat. exchanger inlet flow control valve is positioned to at least the minimum flow rate required by SR The Surveillance Frequency is controlled under the Surveillance Control Program. The Surveillance is modified by a Note which exempts system flow paths opened under administrative control.* The .* admi n.i strati_ve control should be procedural i zed and 1 ncl ude _ an who rapidlY close the system flow path if directed.* continued B 3.5-lOa *Revision Nb. 126 I BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 2 SR 3.5.1.3 ECCS-Operating B 3.5.1 Verification that ADS nitrogen supply header pressure is 85 psig ensures adequate air pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at.70% of design pressure (Ref. 10). The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure 85 psig is provided by the ADS instrument air supply. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.1.4 Verification that the LPCI cross tie valve is closed and I power to its operator is disconnected ensures that each LPCI subsystem remains independent and a failure of the flow path in one subsystem will not affect the flow path of the other LPCI subsystem. Acceptable methods of removing power to the operator include de-energizing breaker control power or racking out or removing the breaker. If the LPCI cross tie valve is open or power has not been removed from the valve operator, both LPCI subsystems must be considered inoperable. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.5-11 Revision No. 86 *
• 11. BASES SURVEILLANCE REQUIREMENTS (continued).* -._*: . , *_. --.: . :. :--. -: PBAPS YNIT 2 .. ,-: SR 3. 5.L5 ECCS-Operati ng B 3.5.1 Cycling the recirculatibn pump discharge valves through one complete cycle of full travel demonstrates that the* valves are mechanically OPERABLE <ind will close when required. Upon initiation of an automatic LPCI subsystem injection signal, these valves are required to be closed to ensure full LPCI subsystem flow injection in the reactor via the recirculation jet pumps. De-energizing the valve in the closed position will also ensure the proper flow path for -the LP.CI subsystem; Acceptable methods of de-energizing the valve. include de-energizing breaker control power, racking out the or removing the If the valve is inoperable and in the open position, the associated lPCi must be declared inoperable. The of this SR is in accordance with fhe Inservice Testing.Program. ' . .. . -Sit' 3.5.l.6. Veri fi satiofi of the automatic transfer the normal * -* .. and the alternate power* source (4 kV. emergency bus) for each *
• LPCI: subsystem inboard .injection *and each
• reci rcl!l ati on pump discharge va:l ve
• demonstrate.s that AC electrical power will be ,available to operate these valves following loss of power .to one of tlie 4 k\/ emergency buses. The-ability to provide power to the inboard injection va)ve andthe reci'rculation pump discharge valve from either 4 kV emergency bus associated wi,th the LPCI subsystem ensures that-the.-single of an DG will not resul.t in: the *:*.' *** .. *.-. _ ... *; ... ,., . -_ . .,__ . *. ; .. (continued)* ' . : ; ., **: -. ' _*.,_ .' *.' .. *:: . ---.,**--** .. , .. *.. * .. ., .*. 131 B 3.5-12 r.<: * * . ' . .

BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.5.1.6 (continued) ECCS-Operating B 3.5.1 failure of both LPCI pumps in one subsystem. Therefore, failure of the automatic transfer capability will result in the.inoperability of the affected LPCI subsystem. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.1.7. SR 3.5.1.8. and SR 3.5.1.9 The performance requirements of the low pressure ECCS pumps are determined through application of the 10 CFR 50, Appendix K criteria (Ref. 6). This periodic Surveillance is performed to verify that the ECCS pumps will develop the flow rates required by respective analyses. The low pressure ECCS pump flow rates ensure adequate core cooling is provided to satisfy the acceptance criteria of Reference 8. The pump flow rates are verified against a system head equivalent to the RPV pressure expected during a LOCA. The total system pump outlet pressure is adequate to overcome the elevation pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV present during a LOCA. These values may be established by testing or analysis or during preoperational testing. Core spray pump flow surveillance requirements ensure that the flow rates of Reference 7 are met. Long cote spray flow requirements (Ref. 13) are assured by the existence 6f high pump run out flow

• capability. SR 3.5.1.7 also accounts for any piping leakage in the system. avoid damaging CS System during testing, throttling is not normally' performed to obtain a system head corresponding to a reactor pressure of 105 psig. As such, SR 3.5:1 .. 7 is modified by a Note to allow use of pump curves to determine equivalent values for flow rate and test pressure for the CS pumps in order to the Surveillance Requirement. The Note allows baseline testing at a system head corresponding to a reactor pressure 105 psig to be used to determine an equivalent flow value at the normal test pressure, This baseline testing is performed after any modification or repair that could affect system flow characteristics. -The flow tests for the HPCI System are performed at two different pressure ranges such that system capability to provide rated flow*is tested at both the higher and lower operating ranges of the system. Additionally, adequate steam flow must be through the main turbine of turb{ne bypass valves to continue to control -reactor cont{nued B 3.5-13 Revision No. 99 BASES SU RV EI LLANCE REQUIREMENTS PBAPS UNIT_ 2 ECCS-Operating B 3.5.1 SR 3.5.1.7. SR 3.5.1.8. and SR 3.5.1.9 pressure when the HPCI System diverts steam flow. Reactor steam pressure must be s 1053 and 915 psig to perform SR 3.5.1.8 and greater than or equal to the Hydraulic Control (EHC) System minimum pressure set with the _ EHC System controlling pressure (EHC System begins controlling pressure at a nominal 150 psig) ands 175 psig to perform SR 3.5.1.9. Adequate steam flow is represented by at least 2 turbine valves open. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Reactor startup is allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that HPCI is inoperable. Therefore, SR 3.S.1.8 and SR 3.5.1.9 are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.1.10 The ECCS subsystems ire required t6 automatically to perform their design functi ans. This Survei-11 ance veri f1 es that, with a required system initiati6n signal (actual or _ the-automatit initiatioH of HPCI, CS, LPCI will cause the systems 6r subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, pump startup and: actuation of all automatic valves to their required -positions. -This SR that either the HPCI System -continued B 3.5-14 Revision -No. 130 _ : I I BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 ECCS-Operat i ng B 3.5.1 SR 3.5.1.10 (continued) will automatically.restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip or, if the initial RPV low water level (Level 2) signal was not manually reset, then the HPCI System will restart when the RPV high water level (Level 8) trip automatically clears, and that the suction is automatically from the CST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCD 3.3.5.1 overlaps this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance. SR 3.5.1.11 The ADS designated S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to that the mechanical portions of the ADS function Ci .e., solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. SR 3.5.1.12 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCD 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.5-15 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS . ':.' PBAPS UN IT 2 SR 3.5.1.11 (continued) ECCS:-Qperating B 3.5.1 This SR is modified by a Note that excludes valve actuation. This prevents an RPV pressure blowdown. SR 3.5.1.12 The pneumatic of each ADS valve is stroked to verify that the second stage pilot disc rod is mechanically displaced when the actuator strokes. Second stage pilot rod movement .is determined by the measurement of actuator rod travel. The total amount of movement of the second stage pilot rod from the valve closed position to the open positibn shall meet established by the S/RV SRs 3.3.5.1.5 and 3.5.1.11 overlap this Surveillance to provide testing of the SRV depressurization mode function. The Surveillance Frequency is controlled under the Frequency Control Program. (continued) :. -* B 3.5-16 Revision No.

ECCS-Operating B 3.5.1 BASES (continued) REFERENCES ' -PBAPS UNIT 2 1. UFSAR, Section 6.4.3. 2. UFSAR, Section 6.4.4. 3. UFSAR, Section 6:4.1. 4. UFSAR, Sections 4.4.5 and 6.4.2. 5. UFSAR, Section 14.6. 6. 10 CFR 50, K. NEDC:32163P, "Peach Bottom Atomic Power Station Units 2 and 3 SAFER/GESTR-LOCA Loss of Coolant Accident Analysis," January 1993. 8'. 10 CFR 50.46. 9. Memorandum from R.l. Baer CNRC) to Stello, Jr. CNRC), "Recommended Interim.Revisions to LCOs for ECCS 1, 10. UFSAR, Section ll. Issue Report 189167, Operability of RHR while in Test Modes/Torus Cooling. 12. . NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Pl ants, Decemb.er 2002. -13. GE Position Summary -_Lt:ing-Term Post-LOCA Adequate Core Cooling *Requirements RevisionO, _--. Novemb_er 2000). * --* -. -.* ' . . -.*_ . : .. : 14: G-080-VC-400, "Peil_ch Sottom Atomic Power Station Units .2 3 GNF2 ECCS-LOCA EvaTuation," G[ Hitachi Nuclear 15. G_-080-vc-2?2, ;;-Peach Bottom Atomic-Power Station ECCS--LOCk Evaluation for GE14," General Electric Company, GENE-J11-03716-09-02P, July 2000. B 5 -17 Revision No; 101 -

• !'. ECCS-Shutdown
• B 3. 5. 2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 ECCS-Shutdown BASES BACKGROUND A description of the Core Spray (CS) System and the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System is provided in the Bases for LCO 3.5.1, "ECCS-Operating. "*
• APPLICABLE The ECCS performance is evaluated for the entire spectrum SAFETY ANALYSES of break sizes for a postulated loss of coolant accident LCO PBAPS UNIT.2 . (LOCA). The long term cooling analysis following a design basis LOCA (Ref. 1) demonstrates that only one low pressure ECCS injection/spray subsystem is required, post LOCA, to .maintain adequate reactor vessel water level in the event of ihadvertent vessel draindown. It is reasonable to assume, on engineering judgement, that While in MODES* 4 and 5 one low pressure ECCS injection/spray subsystem cBn vessel water .. To provide redundancy, a minimum of two low pressure ECCS injection/ spray subsystems Bre required to be OPERABLE in MODES 4 and 5. The iow pressure ECCS subsystems satisfy Criterion 3 of the* NRC Policy Statement. Two low pressure ECC-S injection/spray subsystems are. required to be OPERABLE. A low pressure ECCS inje'ction/ subsystem consists a CS 6r a LPCI subsystem. Each CS consists of two motor driven pumps, piping, and valves to water fjom the suppression pool or condensate storage tank (CST) t6 the reactor pressure vessel ( RPV). Each LPCI sub*system consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV; Only a. s:i ngl'e LPCI pump is required per because cif the lirger injection capacity in relation to a CS subsystem. In . MODES 4 and 5, the LPCI £ross tie valve is not required to be closed. The necessary portions of the Service.* Water System are*a1so required to provide appropriate* cooling to each required ECCS as necessary *1* (Reference TRM3.Jl). Management of gas voids is important ***.*
• to ECCS inject.ion/spray subsystem
• continued
• B 3.5-18 Revision No. 133 BASES.
• LCD (continued) PBAPS UNIT 2 ECCS-Shutdown B 3.5.2 As noted, one LPCI subsystem may be considered OPERABLE during alignment and operatfon for decay heat removal if capable of being manually realigned (remote or local) to the LPCI mode and is not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Because of low pressure and low temperature conditions in MODES 4 and 5, sufficient time will be available to manually align and i.nitiate LPCI subsystem operation to provide core cooling prior to postulated fuel uncovery. discussion applies when the LPCI cross tie valve CM0-20) is closed: One LPCI subsystem shall not be considered one of the required ECCS injection/spray subsystems when M0-34ACB) and M0-39ACB) are simultaneously open in the same subsystem with no Emergency Diesel Generators CEDGs) declared inoperable. As discussed below, an exception to this may be taken if an EOG is declared inoperable. If the M0-34A and M0-39A are simultaneously open, the 'A' subsystem of LPCI shall not be considered as one of the required ECCS injection/spray subsystems unless the E-1, E-2, or E-4 EOG is declared inoperable. If the M0-34B and M0-39B are simultaneously open, the 'B' subsystem of LPCI shall not be considered as one of the required ECCS injection/spray subsystems unless the E-1, E-2, or E-3 EOG is declared inoperable. The following discussion applies when the LPCI cross tie valve CM0-20) is open: The LPCI cross tie valve CM0-20) cannot be credited for closing during an event to isolate both LPCI subsystems. A pipe break within Primary Containment is assumed when the Reactor Coolant System (RCS) is pressurized. Conversely, a pipe break within Primary Containment is not assumed when the RCS is depressurized. Mode 4 with RCS pressurized: When the Unit is in Mode 4 with reactor steam dome pressure indicating that the RCS is pressurized, then both subsystems of LPCI are inoperable. C cont i nue_dJ B 3.5-19 Revision No. 96 BASES LCO (continued) ... -' PBAPS uN rf 2 ECCS-Shutdown B 3.5.2 Mode 4 with RCS depressurized or Mode 5: -:* M0-34A(B) and M0-39A(B) Closed: When the Unit is in Mode 4 with reactor steam dome pressure indicating that the RCS is depressurized or in Mode 5 AND there are no flow paths that could divert LPCI flow going to the reactor vessel Ci .e., M0-34/39 closed), then both subsystems of LPCI can be considered operable as the required ECCS injection/spray subsystems. M0-34A(B) and M0-39A(B) Open: When M0-20; M0-34A, and M0-39A are simultcineously open, the 'A' subsystem -of Core Spray and both subsystems of LPCI cannot be considered as separate ECCS injection/spray subsystems because a single failure (failure of the E-3 EOG) exists that causes the 'A' subsystem of 'Core Spray and both subsystems of LPCI to be unable to perform their design functions. As a result, the 'A' subsystem of Core Spray and both subsystems of LPCI can only be considered as one of the two required ECCS injection/spray subsystems when aligned in this configuraiion. -*-* --When M0-34A, and are simultaneously open with either the E-1, E-2, or t-4 EDG then the 'A' and 'B' subsystems of LPC I may* be credited as being operable, separate subsystems; since_ a failt.1re of the I-3 EDG is not P.ostul ated; * -. . . . -W h en M-0 -2 O , MO -3 4 B , a n d Mb 3 9 B a re si multane-ousl y open; the 'B' .subsystem of Core -Spray and both-subiystem$ of LPCI cannot_be co*ns i dered as separate ECCS i nJect ion/spray subsystems Cfai1ure of E EOG) exists that causes the 'B' _subsystem of. and both subsystems of LPCI to be to per1orm their design functions. As a _the 'B' of Spray and both subsystems of LPCI can only be considered as one of the two required ECCS injection/spray _ subsystems when aligned in s continued B 3.5-l9a Revision No. 96 BASES LCD -(continued) APPLICABILITY ACTIONS ,*'* ,-* -PBAPS UN IT 2 ECCS-Shutdown B 3.5.2 When M0-20, M0-34B, and M0-39B are simultaneously open with either the E-1, E-2, or E-3 EOG declared inoperable, then the 'A' and 'B' subsystems of LPCI may be credited as being operable, separate subsystems, since a failure of the E-4 EOG is not postulated. OPERABILITY of the low pressure ECCS injection/spray subsystems is required in MODES 4 and 5 to ensure adequate coolant inventory and sufficient heat removal capability for the irradiated fuel in the core in case of an inadvertent draindown of the vessel. Requirements for ECCS OPERABILITY during MODES 1, 2, and 3 are discussed in the Applicability section of the Bases for LCD 3.5.1. ECCS subsystems are not required to be OPERABLE during MODE 5 with_the spent fuel storage pool gates remrived, the water level maintained at 458 inches above reactor pressure vessel instrument zero _ (20 ft 11 inches above the RPV flange), and no operations with a potential for draining the reactor vessel (OPDRVs) in progress. provides sufficient coolant inventory to allow &perator to the inventory loss prior to .fuel uncovery in case of an inadvertent draindown. The Automatic Depressuriiation System not required to be OPERABLE during MODES 4 and 5 because the RPV pressure is 100. psig, and the CS System and the LPCI subsystems can provide core cooling without ariy of the primary system.
• The High Pressure Coolant Injection System is not required to be OPERABLE during MODES 4 5 since the low ECCS injection/spray subsystems can provide sufficient flow to the vessel. A.1 and -B.1 If any one required low 0*pressure ECCS i njectfon/spray .subsystem is an inoperable subsystem must be res t o red to 0 P ERA B L E s t a t u s i n 4 h bu r s . -I n t h i s Co n d it i on , .the OPERABLE subsystem cah provide sufficient vessel flooding-c:apabjl ity to recover from an inadvertent vessel draindown. However, overall.system reliabi-lity is reduced because a iingle in_the remaining OPERABLE continued-B.3.5-l9b-RevisionNo. 9i_

BASES ACTIONS UNIT 2 . A.1 and B.1 ECCS-Shutdown B 3.5.2 subsystem concurrent with a vessel draindown could result in the ECCS not being able to perform its intended function. The 4 hour Completion Time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considered the remaining available subsystem and the low probability of a vessel draindown event. With the inoperable subsystem not restored to OPERABLE status in the required Completion Time, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended. C.1. C.2. D.1. D.2; and D.3 With both of the required ECCS injection/spray subsystems inoperable, all coolant inventory makeup capability may be unavailable. Therefore, actions must immediately be initiated to suspend OPDRVs to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended. One ECCS injection/spray subsystem must also be . restored to OPERABLE status within 4 hours. If at least one low pressure ECCS injection/spray subsystem is not restored to OPERABLE status within the 4 hour Completion Time,. additional actions are required to minimize any potential fission product release to the environment. This includes ensuring secondary containment is OPERABLE; one standby gas . treatment subsystem fo-r Unit 2 is OPERABLE; and secondary containment isolation capability (i.e., one iSolation valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability) in each associated secondary containment penetration flow path not isolated that is assumed to be isolated to mitigate radioactivity releases. OPERABILITY may be verified by an administrative check, or by examining logs or other information, to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances* needed to demonstrate the OPERABILITY of the components. (continued) B Revision 0 . BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 C.l, C.2. 0.1, 0.2. and 0.3 (continued) ECCS-Shutdown B 3.5.2 If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, ,the Surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE. The 4 hour Completion Time to restore at least one low pressure ECCS inJection/spray subsystem to OPERABLE status ensures that prompt action will be taken to provide the required cooling capacity or to initiate actions tQ place the plant in a condition that minimizes any potential fission product release to the environment. SR 3.5.2.1 and SR 3.5.2.2 The minimum water level of 11.0 feet required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (Nt>SH) for the CS System and LPCI subsystem pumps, recirculation volume, and vortex prevention. With the suppression pool water level less than the required limit, all ECCS injection/spray subsystems are inoperable unless they are aligned to an OPERABLE CST.

• When suppression pool level is < 11.0 feet, the CS System is considered OPERABLE only if it can take suction from the CST, and the CST water level is sufficient to provide the required NPSH for the CS pump. Therefore, a verification that either the suppression pool water level is 11.0 feet or that CS is aligned to take suction from the CST and the CST contains 17 .3 feet of water, equivalent to *. > 90,976 gallons of .water, ensures thatthe CS System can . supply at least 50,000 gallons of makeup water to the RPV. The unavailable volume of the CST for CS is at the 40,976* .gallon level. However, as noted, only one required CS subsystem may take credit for the CST,option during OPDRVs. During OPDRVs, the volume in the CST may not provide ,
• adequate makeup if the RPV were completely drained. Therefore, only one CS subsystem is allowed to use the CST. This ensures the other required ECCS subsystem has adequate
• makeup volume. * (continued)** B3.5-21 Revision No. O

',. I BASES SURVEILLANCE REQUIREMENTS* *.* . .-PBAPS UN IT 2 SR 3.5.2.1 and SR 3.5.2.2 (continued) ECCS-Shutdown B 3.5.2 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.2.3. SR 3.5.2.5. and SR 3.5.2.6 The Bases provided for SR 3.5.1.1, SR 3.5.1.7, and SR 3.5.1.10 are applicable to SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6, respectively. SR 3.5.2.4 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS This SR does not apply to valves that are locked, sealed,. or otherwise secured in. position, s.ince these were verified to be in the correct position prior to locking, sealing, 6r securing. A that recei.ves an initiation signal is allowed to be in a nonaccident pos1tion provided the valve will automaticqlly reposition. in the proper stroke time. This SR does not require any testing or valve manipulation; rather, .it involves verification that those valves capable of

• being mispositioned are in.the correct position. This SR does not apply to valves that be . inadvertently such as check For the RHR System, verify each RH.R heat exchanger_ inlet -fl ow control valve is posHi.oned td a chi.eve af l.east the minimum fl ow rate req'uired *by SR 3:. 5 .1. 7. The' Surveillance Frequency is controll.ed under the Surveillance Frequen_cy Control Program. The -Surveil 1 ance *is modi fjed by a Note* which exempts system . paths control. The .adrn,i ni st ve. contro t shoui d be procedura 1 i zed and include . stati onfng an .i ndi vi dual who can .'.rapidly close the system vent fl ow path if directed. * -(continued) B 3.5-22 Revision No. 126 BASES REFERENCES PBAPS UNIT 2 ECCS-Shutdown B 3.5.2 1. NED0-20566A, "General Electric Company Analytical Model for Loss-of-Coolant Accident Analysis in Accordance with 10 CFR 50 Appendix K," September 1986. '*, B 3, 5-23. Revision Np. 57 RCIC System B 3.5.3 B 3.5 EMERGENCY CORE COOLING SYSTEMS CECCS) AND REACTOR CORE ISOLATION COOLING CRCIC) SYSTEM. B 3.5.3 RCIC System BASES . BACKGROUN.D PBAPS UN IT 2 The RCIC System is not part of the ECCS; however, the RCIC System is included with the ECCS section because of their similar The RCIC System is designed to operate either automatically or manually following reactor pressure vessel CRPV) isolation accompanied by a loss of coolant flow frbm the feedwater system to provide adequate core cooling and control of the RPV water 1 evel. Under these conditions, the . High Pressure Coolant Injection CHPCI) and RCIC systems perform similar functions. The RCIC System design requirements ensure that the criteria of Reference 1 are satisfied. *
• The RCIC System (Ref. 2) consists of a steam driven turbine pump unit, and valves to provide steam to the turbine, as piping and valves to.transfer water from the suction source to the core via the system line, where the coolant is distributed within the RPV through the sparger. Suction piping is provided from the tank (CST) and the suppression pool. Pump suction is normally aligned to the CST to mihimjze of suppression pool water into the RPV. However, if the CST water supply is l-0w, an automatic. transfer to the suppression pool water source ensures .a water supply for c.ontinuous operation of the RCIC System. Trie supply to the turbine from a main steam line upstream of the associated inboard main steam line isolation valve. RCIC System is designed to provide core cooling for a wide range of pressures (150 psig to 1170 psig). *.Upon receipt of an initiation signal; the RCIC turbine accelerates to a specified speed. As the RCIC flow increases, the turbine governor valve is automatically adjusted to maintain design flow. Exhaust steam from the RCIC turbine is discharged to the suppression pool. A flow line is provided to route water back to the CST to testing of the RCIC System during normal operation .without injecting water into the RPV.
• continued .B3.5-24.* Re vision No .. 110 I BASES BACKGROUND (continued) APPLLCABLE
• SAFETY ANALYSES LCO APPLICABILITY PBAPS UNIT .2* RCIC System B 3.5:3 The RCIC pump .is provided with a mini mum fl ow bypass 1 i ne, which discharges to the suppression pool. The valve in this line automatically opens when the discharge line Valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, the RCIC System discharge piping is kept full of water. The RCIC System is normally alighed to the CST. The height of water in the CST is sufficient to maintain the piping full of water up to the first isolation valve. The relative height of the feedwater line connection for RCIC is such that the water in the feedwater lines keeps the remaining portion of the RCIC discharge line full of water. Therefore, RCIC does not require a "keep fill" system. The function of the RCIC System is to respond to transient events by providing makeup coolant to the reactor. The RCIC System is not an Engineered Safeguard System and no credit is in the safety analyses for RCIC System Based on its contribution to the reduction of overall plant. risk, however, the system satisfies.Criterion 4 of the NRC Policy Statement. The OPERABILITY of the RCIC System provides adequate cbre cooling such that actuation of any of.the low pressure ECCS subsystems is not required in the.event of RPV isolation accompanied by a of feedwater flow.* The RCIC has su_fficient capacity for maintaining RPV inventory during* an event.* of gas voids is important to RCIC OPERABILITY. . . ... The RCIC System-is to during MObE and MODES 2 and reactor steam dome > 150 psig, sinc.e RCIC is ,the primary non-ECCS water source for core* cooling when the reactor is* isolated and pressurized. In MODES 2 and 3 with reactor steam dome pressure 15: 150 psi g, and in MODES 4 an0 5, RClC is not required to be OPERABLE since the low pressure ECCS injection/spray subsystems can provide sufficient flciw to the RPV. (continued) Revision No.* 126 BASES (continued) RCIC System B 3.5.3 ACTIONS A Note prohibits the application of LCD 3.0.4.b to an inoperable RCIC system. There is an increased risk associated with entering a MODE or other specified condition i,n the Applicability with an inoperable RCIC system and the provisions of LCD 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCD not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance. PBAPS UNIT. 2 A.l and A.2 If the RCIC System is inoperable during MODE 1, or MODE 2 or 3 with reactor steam dome pressure > 150 psig, and the HPCI:System is immediately verified to be the RCIC System must be restored to OPERABLE status within 14 days. In this Condition, loss of the.RCIC System will not affect the overall plant capability to provide makeup inventory at high reactor pressure since the HPCI System is the only high pressure system assumed to function during a loss of coolant accident (LOCA). OPERABILITY of HPCI is therefore immediately verified when the RCIC System is inoperable. This may be performed as an administrative check, by examining logs or other information, to determine if HPCI is out of service for maintenance or other reasons. It does not mean it *is necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the HPCI System. If the OPERABILITY of the HPCI System cannot be verified immediately, Condition B must be immediately entered. For certain transients and abnormal events with no LOCA, RCIC (as opposed to HPCI) is the preferred source of makeup coolant because of its. relatively small capacity, which allows easier control of the RPV water level. Therefore, a limited time is allowed to restore the i nope r ab l e , RC IC to 0 PERA BL E status . The 14 day Completion Time is based on a reliability study (Ref. 3) that evaluated the impact on ECCS availability, assuming various components and subsystems were taken out of service. The results used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times CAOTs). Because of similar functions of HPCI and RCIC, the AOTs (i.e., Completion Times) determined for HPCI are also applied to RCIC. If the RCIC System cannot be restored to OPERABLE status within the associated Completion Time, or if the HPCI System is simultaneously inoperable, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of continue B 3.5-26 Revision No. 66 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN l.T 2 1L..1 (continued) RCIC System B 3.5.3 the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 be made as it is also an acceptable low-risk state. The allowed Completion Time is based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.5.3.1 The RCIC System flowpath p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RCIC System and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel. Selection of RCIC System locations susceptible to gas accumulation is based on a review of system design information; including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations, Ttie design review is.supplemented by system walk downs to -validate the high points and to -confirm -the J ocatj on and orientation of important components that can become sources* of gas* or could cause gas to be trapped or difficult to remove during system maintenance or restoration. -Susceptible locations de-pend on plant and system configuration, such as . stan_d-by versus operating coriditi oris. -The.RCic'SYstem is-OPERABLE w.hen it.is suff-fciently'filled -with* water. Acceptance cri.teri a a re established for the volume of gas at susceptible locations. If accumulated gas that exceeds criteria for the_ susceptible location C or the vol of. . -accumulated gas at one or more susceptible locations* exceeds -an :*acceptance cri teri_a for gas volume at the sLicti on or -discharge' *of a pu.mp), the Survei Hance is not met. If the accumulated gas is eliminated or brought within the. acceptance limits during of the the SR is met and past system OPERABILITY is evaluated uhder the-Corrective Action If it is .. determined :bY subsequent eval uati-on* that the RCIC System is -not rendered inoperable l;Jy *the accumul at_ed .gas (i.e., the system *i-s sLiffi ci entl y fi 11 ed wi tQ water), -the Survei l lahce may b*e declared met.-Accumulated gas should be eliminated_ *or brougn:t whhin 'the accept_ance criteria limits. * (continued) B 3.5-27 Revision No .. 127 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.5.3.1 (continued) RCIC System* B 3.5.3 RCIC System locations susceptible to gas are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in* the same system fl ow path which a re subject to the same gas intrusion mechanisms may be verified by monitoring representative subset of susceptible locations. may not be practical for .locations that inaccessible due to radiological or environmental conditions, the plant ctinfiguration, or personnel For these .locations alternative methods (e.g., operating parameters, remote monitoring) may be to monitor*the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of. the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptib1e to_gas .accumulation; SR 3.5.3.2 *. Verifying Uie correct alignment for manual, power operated, and valves in the RCIC flow path provides that the proper flow path will exist for RCIC operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or A valve. that receives an initiation signal is allowed to be in a nonacctdent position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves. verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves cannot be misaligned, such as check valves. For the RCit System, this SR also includes the steam flow path for the turbine the flow controller posit1on .... continued B 3. 5-.21a *Revision No. 126 1** *.

BASES SU RV EI LLANCE REQUIREMENTS PBAPS UN IT 2 ------------**--. ---SR 3.5.3.2 (continued) RCIC System B 3.5.3 The Frequency is controlled under the Surveillance Frequency Control Program. ' The Surveillance is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should .be and ihclude stationing an individual who can rapidly close the vent flow path if directed. SR 3.5.3.3 and SR 3.5.3.4 The RCIC pump flow rates ensure that the system can maintain reactor coolant during pressurized conditions with the RPV isolated. The flow tests for the RCIC System are performed at two different pressure ranges such that system capability to provide rated flow is tested both at the higher and lower operating of the system. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Reactor steam pressure must bes 1053 915 psig to perform SR 3.5.3.3 and greater than rir to the Electro-Hydraulic Control .(EHC) System pressure set with the EHC System controlling (the EHC System begins controlling pressure* at a nominal 150 psig) and . s 1 7 5 p s i g t o p e r f o r:m S R 3 . 5 . 3 . 4 . Alt e r n *a t e l y ,. a u x il i ar y steam be used to perform SR 3.5.3.4. Adequate steam flow is represented by at least 2 turbine bypass valves*.* ripen. sufficieht is allowed after and flow are achieved t6* perfofm these SRs . . startup is allowed prior to. performing the low *pressure Surveillante because the reactor is low and *the time allowed to satisfactorily perform the Surveillance is short. Alternately, the low pre*ssure Surveillance test may be performed prior to itartup an* auxiiiary steam supply. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed thit the low pressure Surveillance has been satisfactorily and is no indication

• to believe that RCIC is inoperable. these SRs are by that state the Surveillances are not to until 12 hciurs the reactor steam pressure and fl ow a re adequate .to perform the: test,
• continued B 3,5-28 Revisiori No. 130 ; "'.

BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.5.3.3 and SR 3.5.3.4 (continued) RCIC System B 3.5.3 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.3.5 The RCIC System is required to actuate automatically in order to verify its design function This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of the RCIC System will cause the system to operate as designed, including actuation of the system throughout its operating sequence; that is, automatic pump startup and actuation of all automatic valves to their required positions. This test also ensures the RCIC System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is autbmatically transferred from the CST to the suppression pool on low CST level. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCD 3.3.5.2 overlaps this Surveillance to provide complete testing of the assumed safety The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note that excludes vessel injection the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillarice. (continued) B 3.5-29 Revision No. 86 BASES REFERENCES ' . . PBAPS UNIT 2 1. UFSAR, Section 1.5. RCIC System B 3.5.3 2. UFSAR, Section 4.7. 3. Memorandum from R.L. Baer (NRC) to V. Stello, Jr. CNRC), "Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975. 4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification. to Selected Required End States for BWR Plants, December 2002. -B 3.5-30 Revision No. 66 i .-Primary Containment

• B 3.6.1.1 B 3 .. 6 CONTAINMENT SYSTEMS B 3.6.1.1 Primary Containment BASES BACKGROUND . , -. '* -':*,. . ... . .... . The function of the primary containment is *to isolate and *contain fission products released from the Reactor Primary System following a Design Basis Accident (OBA) and to confine the postulated release of radioactive material. The , primary containinent co.nststs of a steel vessel, *which surrounds the Reactor Primary System and.provides an .essentially leak tight barrier against an: uncontrolled release of radioactive material to the environment. Portionsof the steel vessel are surrounded.by reinforced concrete for shi,elding * . ' -* -. . . ' . * . The i sol fo.r the penetrations in the primary containment boundary are a part of the containment leak To maintain leak tight barrier: a*. *.***. All pehetratioris to be close.d during accident conditions are either: . , . . , L * .. capable* of being 'closed by an OPERABLE automatic Containment Isolation System, or
• by nianual or de:-'acti vated :a(Jtomat ic valves sepured in their. closed positi9ns, except as provjded in *
• LCO 3.6.L3, 11:Primary*Containment Isolation * .* . .Valves (PCIVs) 11 ;. * * . **. b .. *
• The* '_air lotk is except . . as provided in*LCO ):.6.1.2:, "Primary Containment Air ... . tock; * .::::'_*:* * * * * * * * * , c.
• All.equipment clOsed. * : :.****
• ThisS.peC'iffcalion.E;?nsures that the.perforinaric:e _of.-the* .: .: .. ' . -. ' :_. '. , ..... *' . PBAPS. UNIT 2 .. *. .. .-: ..... -, . . primary containment,*. irt: the event of' a meets* the .. ** . assumptions used in the" s:afety analyses of Reference .. 1. * . SR *3 .. 6 El leakage rate reqiJi rements are in conformante .with.-lOCFR 50, Apperid'ixJ, Option 3), as modified . by. exe111p::t ion_s ... * * " ,*, ,..,*:,:, .* ,., ,., ;*.':*;_ '*--.-.--*-*.* **., ' .. *-(continued r , *, ... :. -. '* .. '"'." :. ,. . *; . ,*.* . .*. *' -_ ;*:*. _ ... , Revisfon No. 2 7 .. :, .. .,.-_ .. , . *\-.< -. -... ,. ' .* . . . . .. *** .. ***-' .*

Primary Containment B 3.6.1.1 BASES (continued) APPLICABLE SAFETY ANALYSES * ... ** LCO PBAPSUNit 2 The safety design basis for the primary containment is that it must the pressures and temperatures of the ifmiting OBA without exceeding the design leakage rate. The DBA that p6stulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environmeht is controlled by the rate of primary containment leakage. Analytical methods and assumptions involving the primary containment are presented in Reference 1. The safety analyses assume a nonmechanistic fission product release following a OBA, which forms the basis for determination of offsite doses. The fission product release is, in turn, based on an assumed leakage rate from the primary. OPERABILITY of the primary containment ensures that the leakage rate assumed in safety analyses is not exceeded.* The maximum allowable rate. for the containment (La) is 0.7% by weight of the containment air per 24 hours at the design basis LOCA maximum peak containment pressure (Pa) of 49.1 psig. The value of Pa (49.l psig) is conservative with respect to the current calculated peak pressure of 48.7 psig (Ref. 2). This of 48.7 psig includes operation 90°F Final Feedwater*Temperature Reduction. Primary Criterion 3 of the NRC Policy Statement *. Primary containment OPERABILITY is maintained by limiting leakage to s 1.0 La, except.prior to the first startup after performirig a required primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be In addition, the leakage from drywell to the suppression chamber must be limited to ensure the pressure suppression function is accomplished and the suppression pressure does not exceed design limits. Compliance with this LCD will .ensure a primary

• cohtainment configuration, ihcluding equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analyses. continued *B.3.6-2* No. 114 BASES LCD (continued) APPLICABILITY ACTIONS SU RV EI LLANCE
• REQUIREMENTS . PBAPS UN IT 2 Primary Containment B 3.6.1.1 Individual leakage rates specified for the primary containment air lock are addressed in LCD 3.6.1.2. In MODES 1, 2, and 3, a OBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, primary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment. In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour. The 1 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during . MODES 1, 2, and 3 .. This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal. If primary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE 1n which the bverall plant risk is minimized. To achieve this status, the plant must be* brought to at MODE 3 within 12 hours. Remaining in . . the Applicability of the LCD is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 8) and because the tirrie spent i.n MODE 3 to perform the repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant SR 3.6.1.1.1 Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. Failure to meet air lock leakage testing CSR 3.6.1.2.1), or main steam isolation continued B 3.6-3 Revision No. 66 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.6.1.1.1 (continued) Primary Containment B 3.6.1.1 valve leakage CSR 3.6.1.3.14), does not necessarily result in a of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. At 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program. SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywel l, the steam would be directed through the downcomers into the suppression pool. This SR is a leak. test that confirms that the bypass cirea between the drYwell. and the suppression chamber is less than or equivalent to a one-inch hole (Ref. 4). This that the paths that would bypass the suppression pool are within .. allowable limits. The Surveillance Frequency is controlled under the I Survei 11 ance Frequency Control Program; Two consecutive test . primary cont a i nme n t deg r ad a t i on ; i n . t h i s e v en t , a s t he N o t e
• indicates, a test shall be performed at a. Frequency. of once every 12* months. until two consecutive tests pass. (continued) *.--:* . . * .. "': -, .... -* B 3.6-4 Revision No. 86 REFERENCES PBAPS UNIT 2 1. UFSAR, Section 14. 9. Primary Containment* B 3.6.1.1 2.
• NEDC-33566P, "Safety Analysis Report for Exel on Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0 .. 3. 10 CFR 50, Appendix J, Option B. 4. Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 127 and 130 to Facility Operating License Nos. DPR-44 and DPR-56, dated February 18, 1988. 5 . N EI 9 4 -0 1 , . Rev i s i on 3 a n d 2 -A , ,; I n d us t r y Gu i de 1 i n e for Implementing Performance-Based Option of 10 CFR 50, Appendix J." 6. * "Containment System leakage .*Testing Requirements." 7, Deleted . . . . . 8. NEDC-32988-A,.Revisiori 2, Technical Justification to Support Risk-Informed Modifi ca ti on to Selected Required End States for BWR Plants, December 2002. * -.*:. *. *._ -' * .. *-*.*.:* Revision*N.O. li8 Primary Containment Air Lock B 3.6.1.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.2 Primary Containment Air Lock BASES BACKGROUND . PBAPS UN IT 2 One double door primary containment air lock has been built. into the primary containment to provide personnel access to the drywell and to provide primary containment isolation during the process of personnel entering and exiting the drywell. The air lock is designed to withstand the same loads, temperatures, and peak design internal and external pressures as the primary containment (Ref. 1). As part of the primary containment, the air lock limits the release of radioactive material to the environment during normal unit operation and through a range of transients and accidents up to and.including postulated Design Basis Accidents (DBAs). Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum
• expected pressure following a OBA in primary containment. Each of the doors contains a gasket seal to ensure pressure integrity. To effect a leak tight seal, the air lock design uses pressure seated doors (i.e., an increase in primary . containment internal pressure results in increased sealing force on each door). Each air lock is nominally a*right circular cylinder, 12 ft in diameter, with doors at each end that are interlocked to prevent simultaneous opening. During periods when primary containment is not required to be OPERABLE, the air lock interlock mechanism may be disabled, allowing both doors of
• an air lock to remain open for extended periods when frequent primary containme'nt entry is necessary. Under some conditions as allowed by this LCO, the primary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.
• The primary containment air lock forms part of the primary containment pressure As such, air lock integrity and leak tightness are essential for maintaining primary containment leakage rate to within limits in the event of a OBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in-excess of that assumed in the unit safety analysis. (continued) B Revision No.* 0 Primary *Containment Air Lock B 3.6.1.2 BASES Ccrintinued) APP LI CABLE SAFETY ANALYSES LCD PBAPS UNIT 2 The DBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident .* it is assumed that primary is OPERABLE, such that release of fission products to the environment is controlled by the rate of primary containment leakage. The primary containment is designed with a maximum allowable leakage rate CLal of 0.7% by weight of the containment air per 24 hours at the maximum containment pressure CPa) of 49.1 psig. The value of Pa (49.1 psig) is conservative with respect to the current calculated peak drywell pressure of 48.7 psig (Ref. 3), This value of 48.7 psig includes operation with 90°F Final Feedwater Temperature Reduction. This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air lock. Primafy containment air lock OPERABILITY is also required to minimize the* amount of fission product gases that may escape containment through the air lock and contaminate and the secondary containment. The primary air lock satisfies Criterion 3 of the NRC Policy Statement. As part of primary containment, the air lock's safety *function is related to control of containment leakage following a DBA. *Thus, *the air lock's structural integrfty and leak tightness are essential to the such an everit. The primary containment air lock is to be For ihe air lock.to'be OPERABLE, air lock .. i n t e r 1 o c k me c h a n i s m mu s t b e
• O P ERA B LE , t h e a ir
• 1 o c k mu st be tn compliance with:the Type B test, and both air lock doors must be OPERABLE. *The interlock allows only one 1ock door to be a This . provision ensures that a gross breach of primary containmen.t does exist when primary ii required to .*
• OPERABLE. Closure of a single door in each air lock. is
• sufficient to a leak tight barrier following postulated events. Neveftheless, both doors are kept when the air lock is not being for normal entry and exit from primary containment. B 3.6-7 Revis i on No: 114 BASES (continued} APPLICABILITY ACTIONS PBAPS *uNIT 2 / Primary Containment Air Lock
• B 3.6.1.2 In MODES I, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the primary containment air* lock is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment. The ACTIONS are modified by Note I, which allows entry and exit to perform repairs of the affected air lock component. If the outer door is inoperable, then it may be easily accessed to repair. If the inner door is the one that is inoperable, however, then a short time exists when the containment boundary is not intact (during access through the outer door}. The ability to open the OPERABLE door, even if it means the primary containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the primary containment during the short time in which the OPERABLE door is expected to be open. The OPERABLE door must be immediately closed after each entry and exit. The ACTIONS are modified by a second Note, which ensures appropri.ate remedial measures are taken when necessary. Pursuant to LCO 3.0.6, actions are not required, even if primary containment leakage is exceeding L8*
• Therefore, the Note is added to require ACTIONS for LCD 3.6.1.1, nPrimary
• Containment,n to be taken in this event. A.I. A.2. and A.3 With one primary containment air lock door inoperable, the OPERABLE door must be verified closed (Required Action A.I} in the air lock. This ensures that a leak tight primary containment barrier is maintained by the use of an OPERABLE air lock door. This action must be completed within I hour. The I hour Completion Time is consistent with the ACTIONS of LCD 3.6.1.1, which requires. that primary containment be restored to OPERABLE status within 1 hour. In addition, the air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour Completion Time. The 24 hour Completion Time is considered (continued) B 3.6-8 Revision No. 0 BASES ACTIONS PBAPS UNIT 2 A.I. A.2. and A.3 (continued) Primary Containment Air Lock B 3.6.1.2 reasonable for locking the OPERABLE air lock door, considering that the OPERABLE door is being maintained closed. Required Action A.3 ensures that the air lock with an inoperable door has been isolated by the use of a locked closed OPERABLE air lock door. This ensures that an acceptable primary containment leakage boundary is maintained *. The Completion Time of once per 31 days is based on engineering judgment and is considered adequate in view of the low likelihood of a locked door being mispositi-0ned and other administrative controls. Required Action A.3 is modified by a Note that applies to air lock doors located in high radiation areas or areas with limited access due to and allows these doors to be verified locked closed by use of administrative controls. Allowing veri*fication by administrative controls is considered *acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small.
• The Required Actions have been modified by two Notes .. Note 1 ensures that only the Required*Actions and associated Completion Times of Condition*c are required if both doors in the ai.r lock are inoperable. With both ,doors in the air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.l and C.2 are the appropriate remedial actions. The exception of Note 1 does not affect tracking the Completion Time from the initial entry into *.Condition A; only the requirement to comply with the Required Actions. Note: 2 allows use of the air lock for entry and exit for 7. days Linqer administrative controls. Primary containmen:t entry may be required* to perform * * . Technical SpeC:ificatiotis _(TS) Surveillances and Required as well as other activities _on TS'.'"required . equipmerit<*O_r activities on equipment that support TS-required equipment. This Note is not .intended to precl ude.*performing. other activities (i.e.;,* non-TS-re 1 ated acti'vities) .if the primary containment was entered, using the inoperable air lock, to perform an allowed activity liste.d .above. The administrative controls required consist of the. stationing of a dedicatecj individual to assure .. c 1 osure -of the OPERABLE door during . the entry and
• exit,. ancl assuring 'the OPERABLE door is relocked after. '. '* (continued) B 3.6.-9 Revision No. o BASES ACTIONS PBAPS UNIT 2 A. I. A. 2, and A. 3 ( corittnued) Primary Containment Air Lock B 3.6.1.2 completion of the containment entry and exit. This allowance is acceptable due to the low probability of an event that could pressurize the primary containment during the short time that the OPERABLE door is expected to be open. B.1. B.2. and B.3 With an air lock interlock mechanism inoperable; the Required Actions and associated Completion Times are consistent with those specified in Condition A. The Required Actions have been modified by two Notes. Note I ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock are inoperable. With both doors in the air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.l and C.2 are the appropriate remedial actions. Note 2 allows entry into and exit from the primary containment under the control of a dedicated . individual stationed at the air lock to ensure that only one door is opened at a time the indjvidual performs the functfon of the interlock). Required.Action B.3 is modified by a Note that applies to air lock doors located in high radiation areas or areas with limited access due to inerting and that allows doors to be verified locked closed by use of administrative controls._ Allowing verification by administrative controls is conside.red acceptable, since access to these areas .is . typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small. C.1. C.2. and C.3 If the air lock is inoperable for reasons other than those described in .Condition A or B, Required Action C.l requires action to be immediately initiated to evaluate containment overall leakage rates using current air lock leakage test results. An evaluation iS acceptable since it is overly conservative to immediately declare the primary containment if the overall air lock leakage is not within (continued) B 3.6-10 Revision No. 0 BASES ACTIONS PBAPS UNIT:2 Primary Containment Air Lock . B 3.6.I.2 A.I, A.2. and A.3 (continued) completion of the containment entry and exit. This allowance is acceptable due to the low probability of an event that could pressurize the primary containment during the short time that the OPERABLE door is expected to be open. B.l, 8.2, and B.3 With an air lock interlock mechanism inoperable, the Required Actions and associated Completion Times are with those specified in Conditi6n A. The Required Actions have been modified by two Notes. Note I ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors . in the air lock are inoperable. With both doors in the air
• lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.I and C.2 are the appropriate remedial actions. Note 2 allows entry into and exit from the primary containment under the control of a dedicated individual stationed at lock to that onlj one door is opened at a time (i.e., the individual performs the function of the interlock).
• Required Action 8.3 is modified by a Note that applies to
• air lock doors located i.n high radiation areas or areas with limited access due to inerting and that allows these doors to be verified locked closed by use of administrative controls. _Allowing verification by administrative controls is considered acceptable, since access to areas is
• typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in * .the proper position, is small. If the air lock is inoperable for reasons other than those described in Condition A or B, Required Action C.l requires action to be immediately initiated to evaluate containment overall leakage rates tising current lock leakage test results. *An evaluation is acceptable since it is overly conservative to immediatelydeclare the primary containment inoperable if the overall air lock leakage is not within (continued) ' ' B --Revision No. o -.. -*
  • .'* BASES ACTIONS SURVEILLANCE REQUIREMENTS .* .... -. ,. ; *.* PBAPS UNIT 2 Primary Containment Air Lock B 3.6.1.2 C.1. C.2. and C.3 (continued) limits. *In many instances (e.g., only one seal .per door has failed), primary*containment remains OPERABLE, yet only 1 hour (according to LCO 3.6.1.1} would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In addition, even with the overall air lock leakage not within limits, the overall containment leakage rate can still be within.limits. Required Action C.2 requires that one door in the primary . containment air lock must be verified closed. This action must be completed within the 1 hour Completion Time. This specified time period is consistent .with the ACTIONS .. of LCO 3.6.l.l, which require that primary containment be restored to OPERABLE status within 1 hour . . Additionally, the air lock must be restored to OPERABLE status within 24 hours. The 24 hour Completion Time is
• reasonable for restoring an inoperable air l oc.k to OPERABLE status considering that at least one door is maintained closed in the air lock. D.l and 0.2 . If the inoperable primary containment air lock cannot be* restored to OPERABLE status within the.associated Compretion * *Time, the plant must be brought to a MODE in which the LCO. does not apply. *To achieve this status, the plant must be brought to at MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times_ are .*. on operating reach the, .. required plarit conditions from full power't1mditions in an orderly manner and without challenging plant systems.* . SR 3. 6. 1. 2 . 1 * .... : .. -, :, ... Maintaining primary containm ... nt air locks OPERABLE requires. compliance with the leakage rate test requirements of the Primary. Containment leakage Rate Testing Program. Thh SR . reflects the leakage rate testing requirements with .respect to air lock leakage (Type B leakage tests) The acceptance * * .criteria were established during .initial air lock and primary C:onta inmel'lt OPERABILITY (continued). B 3.6-11 Revision No. 6 I I * ' . I BASES SURVEILLANCE REQUIREMENTS .UNIT 2 .* SR 3.6.1.2.1 (continued) Primary Containment Air Lock B 3.6.1.2 testing. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary Containment Leakage Rate Testing Program. The SR has been modified by two Notes. Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test. This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a* OBA; Note 2 requires the results of air lock leakage tests to be evaluated against the acceptance criteria of the Containment Leakage Testing 5.5.12. This ensures that the air lock leakage is properly accounted for in determining the combined Type B and C primary containment leakage. SR 3.6.1.2.2 The air lotk interlock mechanism is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident primary containment pressure, closure of either door will support tontainment OPERABILITY. the interlock feature supports containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed *and that simultaneous inner and outer door opening will not inadvertently occur. The Surveillance Frequency is control Surveillance Frequency Control Program. (continued) B 3;6-12 Revision No. 86 BASES (continued) REFERENCES I'**' .. .-.. Y:: . --* ... : .. * ...
• t';; -:: .. 1. UFSAR, Section 5.2.3.4.5. Primary Containment Air Lock B 3.6.1.2 2. 10 CFR 50, Appendix J, Option B. 3. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 4. Deleted '.-** *.; .. : :: ... *,* .. ,_ . . --: '* . ---*. . . '*'*:, .. *, -.; * .. _ .. :. *-.-B 3:6-13 .. Revision No. 114*.

PC I Vs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B Primary Containment Isolation Valves (PCIVs) BASES BACKGROUND PBAPS UNIT _2 The function of the*PCIVs, in combination with other accident mitigation systems, is to limit fission product. release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment isolation within 'the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses furaOOA.

• The OPERABILITY requirements for PCIVs help ensure that an adequate primary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. Therefore, the OPERABILITY requirements .. provide assurance that primary containment function assumed in the safety analyses will be maintained. These isolation devices are either passiveor active (automatic). Closed manual valves, de-activated automatic valves secured in their closed position (including check valves with flow t.hrough the valve secured)., blind flanges, and closed systems ate considered passive devices. *check valves and other automatic valves.designed to operator action following an accident, are considered active devices. Two barriers in series are.provided for each penetratfon so that n() single credible failure .or malfunction of an active* component can result in a loss of isolation or leakage that exceeds 1 imits assumed .in the safety analyses. One of these
• barriers may be a system. , , The reactor chamber vacuum breakers and the scram discharge_ volume vent and' drain valves each .serve a dual function, one of which is primary containment isolation *.
• However, since .. t,he other safety functions* of the * -vacuuni breakers* and the *scram discharge volume vent and* drain valves would .. riot be available if the normal PCIV taken, the PCIV OPERABILITY requirements are not applicable to the reactorbuilding-to .. suppression ch_ambe'r vacuum breaker valves and the scram discharge volume ve11t and drain valves. Surveillance Requirements in :the LCO for the reactor buildiflg .. to-suppression chamber
• vacuum breakers and thetCO for the.scram discharge volume .*-*,*.-* . -. -.. . B Revision No.* 0 BASES BACKGROUND (continued) . PBAPS *UN IT 2 PC I Vs B 3.6.1.3 vent and drain valves provide assurance that the isolation capability is available without conflicting with the vacuum relief or scram discharge volume vent and drain functions. The primary containment purge lines are 18 inches in diameter;. exhaust lines are 18 inches .. in diameter. In addition, a 6 inch line from the Containment Atmospheric Control (CAC) System is also provided to purge primary containment. The 6 and 18 inch primary containment purge .valves and the 18 inch primary containment exhaust valves are normally maintained closed in MODES 1, 2, and 3 to ensure the primary containment boundary is maintained. However, containment purging with the 18 inch purge and exhaust valves is permitted for inerting, de-inerting, and pressure control. Included in the scope of the de-inerting *is the need to purge containment to ensure personnel safety during the performance of inspections beneficial to nuclear safety; e.g., inspection of primary coolant integrity during plant startups and shutdowns. Adjustments in primary containment pressure to perform tests such as the to-suppression chamber bypass leakage test are included within the scope of pressure control purging. Purging for humidity and temperature control using the 18 inch valves is excluded. The isolation valves on the 18 inch vent lines have 2 inch bypass lines around them for use during normal* reactor operation when the 18 inch valves cannot be opened. Two ad.ditional redundant Standby Gas Treatment (SGT)
• isolation valves are provided on the vent line upstream of the SGT System filter trains. These isolation valves, together with the PCIVs, will prevent high pressure from reaching the SGT System filter trains in the unlikely event of a loss-of coolant accident (LOCA) during venting. The Safety Grade Instrument Gas (SGIG) System supplies pressurized nitrogen ga_s (from the Containment Atmospheric Dilution (CAD) System liquid nitrogen storage tank) as a safety grade pneumatic source to the CAC System purge and exhaust isolation valve inflatable seals, the reactor building-to-suppression chamber vacuum breaker air operated isolation valves and inflatable seal, and the CAC and CAD Systems vent control air operated valves. The SGIG System thus performs two distinct post-LOCA functions: (1) supports containment.isolation and (2) supports CAD System vent operation. SGIG System requirements are addressed for (continued) B 3.6-15 Revi.sion No.* .. o *.,*.'.

BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 PC I Vs B 3.6.1.3 each of the supported system and components in LCO 3.6.1.3, "Primary Containment Isolation Valves CPCIVs)," and LCO 3. 6 .1. 5, "Reactor Buil ding-to-Suppression Chamber Vacuum Breakers." For the SGIG System, liquid nitrogen from the liquid nitrogen storage tank passes* through the liquid nitrogen vaporizer where it is converted to a gas. The gas then flows into a Unit 2 header* and a Unit 3 header separated by two manual globe valves. From each header, the* gas then branches to each valve operator or valve seal supplied by the SGIG System. Each branch is separated from the header by a manual globe valve and a check valve. To support SGIG System functions, the nitrogen inventory is to a storage tank minimum required level 22 water column, or a technically justified source of equivalent 124,000 scf at 250 psig, and a minimum required SGIG System header pressure of 80 psig. The PCIVs LCO was derived from the assumptions related to minimizing the loss of reactor coolant inventory, and establishing the primary containment boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary containment. Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this LCO. . DBAs that in a release of radioactive material and are mitigated by PCIVs a LOCA and a main steam line break CMSLB). In the analysis for each of these accidents, it is assumed that PCIVs are either closed or close within the required isolation times following event initiation. This ensures that potential paths to the environment through PCIVs (including primary containment purge valves) are minimized. Of the events analyzed in Reference l, the LOCA *is a limiting event due to *radiological consequences. The closure time of the main steam isolation valves CMSIVs) is *the most significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds after signal generation. Likewise, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled. continued 6 3. 6 . Revision No. 91

*' . , BASES APPLICABLE SAFETY ANALYSES (continued) LCO. -;. .. . . . PBAPS UNIT 2 PC I Vs B 3.6.1.3 The DBA analysis assumes* that within 60 seconds of the .accident, isolation of the primary containment is complete and leakage is terminated, except for the maximum allowable leakage rate, La. The primary containment isolation total response time or 60 seconds includes signal delay, diesel generator startup (for loss of offsite power), and PCIV stroke times. The single failure criterion required to be imposed in the conduct of unit safety analyses was considered in the original design of the primary containment purge and exhaust valves. Two valves in series on each purge and exhaust line , provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred. PCIVs satisfy Criterion 3 of *the NRC Policy Statement. PCIVs. form a part of the primary containment boundary .. The. PCIV safety function is related to minimizing the loss of the .reactor coolant inventory and establishing the. primary containment boundary during a OBA. ' . . . . . The power operated, automatic .isolation valves are required *to have isolation times within limits on an automatic: isolation signal. ln addition, for the CAC System

• purge and exhaust isolation valves to be considered OPERABLE, the SGIG System supplying nitr9gen gas to the inflatab1e seals*of the valves must be OPERABLE. While the reactor building-:to-suppression chamber vacuum breakers and the scram discharge volume vent and drain valves isolate
• primary containment penetrations, they are excl.uded from this .spedfication. Controls on thei .. r isolation fuf\ction are adequately addressed in LCO "Scram Discharge Volume (SDV) Vent and Drain Valves," andLtO .. "Reactor Vacuum The valves covered LCO are listed with their .. * .. * .. *** *
• associated stroke times* in Reference 2. The.required stroke* ,t'trne *is *the stroke time listed >in Reference 2 or the . .* .*. Testing Program which ever isJnore ... The normallyclosed PC'!Vs are considered OPERABLE when .. manual .vaJves are closed Qr open . in accordance. with
• approprlate>adminlstrative controls, automatic valves . ' . -:, . . * -:*_ :>-_: are . (c_ontinued) *. B 3.'6-17 ** Revision No. 2 I BASES LCO (continued) APPLICABILITY ACTIONS .. * . ", ,*-**--.. . PBAPS UNIT. 2 .* PC I Vs B 3.6.I.3 de-activated and secured in their closed blind flanges are in pl ace, and closed systems are intact. These passive isolation valves and devices are those listed in Reference 2 and Reference 5. MSIVs must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.19 "Primary Containment," as Type B or C testing. This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor cqolant inventory and establish the primary containment boundary during accidents. In MODES 1, 2, and 3, a OBA could cause a release of radioactive material to primary containment. .Jn MODES 4 and 5,. the probability and consequences of these events are reduced due*to the pressure and temperature limitations of these MODES. Therefore, most PCIVs are not required to be OPERABLE and the primary containment purge and exhaust valves are not required to be normally closed in MODES 4 and 5. Certain valves, however, are required to be OPERABLE to*prevent inadvertent reactor.vessel draindown. These. valves are those whose associated instrumentation is required to be OPERABLE per LCO "Primary Containment Isolation Instrumentation." (This does not *include the valves th.at isolate the associated instru!Dentation.) . The ACTIONS are modified by a Note allowing penetration flow* path(s) except for purge *or exhaust valve flow pa:th(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator at the contr6ls of the is in communication. with the control room.* In this way, the . can* be rapidly isolated when a need for primary . *
• contairtment isolati-0n-is indicated. Due to the size of the primary;coritainmentpurge line penetrationand thefact that those pene.trations*.exhaust.directly *fromthe_containment
• atmosphere: to the environment, the penetration flow path containing these valves *is not a 11 owed to *be operated under * ** * * {continued) ,*. --: . B 3.6-.18 . Revision No. 2

.BASES ACTIONS (continued) . . . . . PBAPS UNIT 2 . PC I Vs B 3.6.1.3 A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path *.. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriateremedial actions are taken, if if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling Systems subsystem is inoperable due to a failed open test return valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded. Pursuant to LCO 3.0.6, these actions would not be required even when the associated LCO is not *met. Therefore, Notes 3 and 4 are added to require the proper actions be taken. A.I and*A.2 With one or more penetration fl ow paths with one PCIV inoperable except for MSIV leakage not within limit, the affected penetration flow paths must be isolated.

• The method of isolation must include the use of at least one isolation barrier that. cannot be adversely affected by a single active Isolation that meet this criterion are a closed and de-activated automatic valve, a c 1 osed manua 1 va 1 ve, a bl i rid flange, and a check va 1 ve with flow through the valve secured. For a penetration isolated in accordance with-Required Action A.1,.the device used to isolate the penetration should be the closest available valve to the primary containment. The Required Action must be completed within the 4 hour Completion Time (8 hours for main steam 1i nes)
• The Completion Ti me of 4 hours is reasonable considering the time required to isolate the penetratiOn and the relative importance of supporting. primary containment OPERABILITY during MODES 1, 2, and 3.
• For main steam lines, an 8 hour Completion Tim.e is allowed. The Completion Time of 8 hours for the main $team lines (continued) B Revision No. O 1 * .. * ***. **-BASES ACTIONS PBAPS UN IT-. 2 A.l and A.2 (continued) PC I Vs* B 3.6.1.3 allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown. For affected penetrations that have been isolated in accordance with Required Action A.l, the affected penetration flow path(s) must be verified to be isolated on a basis. This is necessary to ensure that primary containment penetrations required to be isolated foll.owing an accident, and no longer capable of being automatically isolated, will be in the isolation position should an occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification that
• those devices outside containment and capable of potentially. being mispositioned are in the correct position; The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low. For the devices inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and considered reasonable in view of the inaccessibility of the and other administrative controls ensuring that device misalignment is an unlikely possibility. Condition A is modified by a Note indicating that this. Condition is only applicable to those penetration flow paths with twb PCIVs. For penetration flow paths with one PClV, Cond1tion C provides the appropriate Required Actions. ** Required Action A.2 is modified by two Note 1 applies to isolation lbcated in high radiation areas, and
• allows them to be verifietj bY use of administrative Allowing verification by is considered acceptable, since access to these, areas i.s typically restricted. Note 2 to devices that are locked, sealed,*or otherwise secured in position and allows these devices to be verified closed by of means *. Allowing verification by administrative means is considered acceptable1 since the function of locking, 6r components is to ensure that these devices are not-inadvertently repositioned .. Therefore, the probability :of misalignment_, orice they have been verified to be in the proper position, is low. (continued) B 3.6-20 Revision No. 57 _J BASES PC I Vs B 3.6.1.3 ACTIONS B.l (continued) PBAPS UN rt. 2 With one or more penetration flow paths with two PCIVs inoperable except due to MSIV leakage not within limit, either the inoperable PCIVs must be restored to OPERABLE status or the affected penetration flow path must be isolated within 1 hour. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criferion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 1 hour Completion Time is consistent with the ACTIONS of LCD 3.6.1.1. Conditirin B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two PCIVs. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. C.1 and C.2 With one or more penetration flow paths with one PCIV inoperable,_ the inoperable valve must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. The Completion Time of 4 hours is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The Completion Time of 72 hours for penetrations. with a closed system is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES l, 2, and 3. The closed system must also meet the requirements of Reference 6.
• The Completion Time of 72 hours is also reasonable considering the instrument and the small pipe of penetration (hence, reliability) to act as a penetration isolation boundary and the small pipe diameter of the affected penetrations. For affected penetrations that have been isolated in accordance with Required Action C.l, the affected penetration flow path(s) must be verified to be isolated on (continued) B 3;6-21 Revision No. 57 BASES . ACTIONS . PBAPS UN IT 2 C.l and C.2 (continued) PC I Vs B 3.6.1.3 a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and no capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown, that those valves outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" i*s appropriate because the valves are operated under administrative controls and the probability of their misalignment is low. For the valves inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted whil* in 4, if not performed within.the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the valves and other. administrative controls ensuring that valve misalignment is an unlikely possibility. Conditinn C is modified by a Note indicating that this Condition is only applicable to penetrati6n flow paths with only one PCIV. For penetration flow paths with two PCIVs, Conditions A and B provide-the Required Actions.* Required Action C .2 is .modified by two Notes. Note 1 applies I to valves and blind flanges located in high radiation areas arid allows them to be verified by use of Allowing verification by administritive means is since access to these areas is typically restricted: Note 2 applies to isolation devices that are locked, sealed, or otherwise.secured in position and i'rll ows these devices .to v.eri fi ed closed by' use of means .. Allowing verification by ... admi ni strati ve -s *is .. *c.dri side red* acceptahl e, s i nee the furicti cin oT locking, se(l_l ing, or securing components is to -ensure that these dev.i ces are not inadvertently repositioned . . Therefore; the probability of misalignment of these valves, . onc:e they have been v.erified t9 be in the proper position,. is low. * . . With .any MSIV le.akage*rate not within* limit, the assumptions of .analysis ar.e not .met. Therefore, the leakage must be restored to within.limit within B hours. Restorat1.o'r{ can be-accomplished by i so}ating the penetration* that caused the limit.to be eiceeded by use of one closed and de-activated automatic valve; closed manual valve, or blind flange.* When. a penetration is isolated, the leak.age* (con ti niied) .,-**_ B Ntr. 57 .

BASES ACTIONS PBAPS UN IT 2 lL.l (continued) PC I Vs B 3.6.1.3 rate for the isolated penetration is assumed to be the actual pathway through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the two devices. The 8 hour Completion-Time is reasonable considering the time required to restore the leakage by i$Olating the penetration, the fact that MSIV closure will result in isolation of the main line and a_ potential for plant shutdown, and the relative importance of MSIV leakage to the overall containment function.

• E.1. E.2.1. and E.2.2 The accumulated time that the large containment purge and/or vent valves (6" and 18" vent valves) are open, when reactor pr*essure is greater than 100 psig and the reactor is in MODES 1 or 2, is limited to 90 hours per calendar year. This will limit the total time a flow path exists through certain penetrations. The design (Reference 7) assumes that the containment remairis at atmospheric pressure for the determination of ECCS NPSH. during a .LOCA. Consequently, there exists minimal. impact on plant risk resulting from challenges to ECCS NPSH during a LOCA while purging._ The A-hour Completion Time-to isolate the penetration is. considered a reasonable amount of time to ensure compliance with the design analysis for containment overpressure. If the penetration is not iSolated within the specified 4-hour time period, then the plant must-be brought -to at least MODE j wtthin 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based oh operating experience, to reach the required-plant conditions from full power conditions in an manner and without challenging plant systems. -F.1 and F.2 If any Required Action and associated Completion Time cannot be met in MODE 1, 2, or 3, the plant must be brought to a MODE in which the_LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed -Completion Times are reasonable, based on operating to the required plant conditions from full power conditions an orderly manner and Without plant (continued) Revision No.-114 BASES ACTIONS (continued) PBAPS UN IT 2* G.l and G.2 PC I Vs B 3.6.L3 If any Required Action and associated Completion Time cannot be met for PCIV(s) required to be OPERABLE during MODE 4 or 5, the unit must be placed in a condition in which the LCD does not apply. Action must be immediately initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended and valve(s) are restored to OPERABLE status. If suspending an OPDRV would result in closing the residual heat removal (.RHR) shutdown cooling isolation valves, an alternative Required Action is provided to immediately initiate action to the valve(s) to OPERABLE status. This allows RHR. to remain in service while actions are being taken to restore the valve. (continued) B 3.6-23a Rev.ision No. 114
• 1.

BASES (continued) SURVEILLANCE REQUIREMENTS .PBAPS UNIT 2 SR 3.6.1.3.1 PC I Vs B 3.6.1.3 Verifying that the nitrogen inventory is equivalent to a level in the liquid nitrogen tank 22 inches water column 124,000 scf at 250 psig) will ensure at least 7 days of post-LOCA SGIG System operation. This minimum volume of nitrogen allows sufficient time after an accident to replenish the nitrogen supply in order to maintain the containment isolation function. The inventory is verified to ensure that the system is capable of performing its intended isolation function when required. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.2 This SR ensures that the pressure in the SGIG System header is 80 psig. This ensures that the post-LOCA nitrogen pressure provided to the valve operators and valve seals is adequate for the SGIG System to perform its design function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.3 SR ensures that the primary ctintainment purge and exhaust valves are closed as required or, if open, open for an allowable reason.. If a purge valve is open in violation of this SR, the valve is considered inoperable (Condition A applies). The SR is modified by a Note stating that the SR is not required to be met when the purge and exhaust valves are open for the stated reasons. The Note states that these valves may be opened for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. The 6 inch and 18 inch purge valves and 18 inch exhaust continued B 3.6-24 Revision No. 91 BASES SU RV EI L LANCE REQUIREMENTS .. :. PBAPS UNIT 2 SR 3.6.1.3.3 (continued) PC I Vs B 3.6.1.3 valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. SR 3.6.1.3.4 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed, The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are _in the c-orrect position. Since verification of valve p6sition for PCIVs primary containment is relatively the Frequency was chosen to provide added assurance that-the PCIVs are in the correct This SR does not apply to valves that are sealed, or otherwise *secured in the.closed position, since valves were Verified to be in the correCt* pas it i Oh upon locking, Sf:a ling,. o r s e cur i n g . Three Notes have been-added to this SR. The first Note allows valves and blind -flanges located in high radiation a re as to be v er if i e d by use of ad m _i n i st r_a ti v e -control s . Allowing verification by administrative.controls is -considered accep-tabie s1nce the primary containment is _ inerted and access to is typically 1, 2; and j ALARA reasons. Therefore; the probability of-misalignment of these P.CIVs, once *they have been ve:tined be in the proper position,<is low. .. -second'Note has'.-beeri includ'ed to clarify that PCIVs that_ are bpen under'* contrbls are not-required to meet _ t h e S R d ur i ri g t h e t i me t h a t t _h e PC I V s a re open : A t h i rd _ Note-states that performance of the SR is not required.for test tap_s with a diameter 1 inch. It is the intent that this SR inust sti 11 be .met, but actual performance is not .requtreci .for test taps w*ith_*a diameter::;_ 1 inc_h.

• The Note_*3 allowance'* is consistent with the origin_al plarit licensing cont1nued B 3.6-25 *-Re v i s i on N o . 8 6 BASES SU RV EI.LLANC E REQUIREMENTS (continued) . -.... -.... -PBAPS LJN IT-2: SR 3.6.1.3.5 PC I Vs B 3.6.1.3 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise and is required to be closed during accident coriditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the *primary containment boundary is within design limits. For . PCIVs *inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed .within th_e previous 92. days" is appropriate sinc-e these PCIVs are operated under administrative controls and the probabi1ity of their misa1ignment is low. This SR does not apply to valves.that are locked, sealed, or otherwise secured in* the closed position, since these valves were verified to be in the correct position upon locking, sealing, or securing. Two Notes have been added to this SR. The first Note allows valv.es and blind flanges located in high radiation areas to be verified by use of administrative Allowing verification by administrative controls is considered acceptable the primary containment is inerted and access to these areas is typically restricted during MODES l, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs; once they*have been verified to be iri proper position, is low.* A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet _ the SR; du r i n g the ti me that .the PC IVs a re open . SR -3.6 .. 1.3.6 . ' . . . The traversing incore pr,obe GIP) shear isolatio_n valves are ac.tuated by.-.exp*fosive-charges. -Surveillance of explosive assurance that TIP valves will * . actuate .when. re qui red. .-Other admi ni strati ve contra ls, such as-those that lirhit .the shelf life of the.explosive charges, must be' Jol lowed. The Surveillance frequency is controlled ---*1 under the *surveillance:freqUency Control_ Program._*.* . . SR J,6:L3.7 _ Verifyingthe correct alignment for each manual valve in the -SGIG System.required. flow paths 'provides assurance that the proper flow paths .:exist :for system operatj.ori. _ This SR does*. not apply to valves that are .locked or otherwise secured in
• cont i riued Re vi s_i_on No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2. SR 3.6.1.3.7 (continued) PC I Vs B 3. 6 .. 1. 3 position, since these valves were verified to be in the correct position prior to locking or securing. This SR does not require any testing or valve manipulation; rather, it verification that those valves capable of being* mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.8 Verifying the isolation time of each power operated automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV . full closure isolation time is demonstrated by SR 3.6.1.3.9. The isolation test ensures that the valve will isolate in a time period less than or equal to that assumed in the safety analyses. The isolation time is in accordahce with Reference 2 or the requirements of the Inservice Testing Program which ever is more conservative. The Frequenc; of this SR is in accordance with the requirements of the Inservice Testing Program. SR 3.6.1.3.9 Verifying.that the isolation time of each MSIV ii within the spetified limits is required tQ demonstrate OPERABILITY. The isolation time test ensures that the-MSIV. will isolate in C) time period that does not exceed the time's assumed in . the OBA analyses. This ensu.res that*the calculated radiological consequences of these events .remain within 10 CFR 50.67 as modified in Regulatory Guide 1.183, Table 6. The Frequency of {his SR is in with the requirements of the Inservice Testing *.* .. SR 3.6.1.3.10 .Automatic PCIVs close on a primary containment isolatioh signal to prevent leakage of radioactive m(l.terial from primary containment follciwing a DBA. This SR that *each autdmatic-PCIV will actuate to its isolation position *on a primary contiinment isolation signal. -The LOGIC SYSTEM continued .-B 3.6-27 Revision No: 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.6.1.3.10 (continued) PC I Vs B 3.6.1.3 FUNCTIONAL TEST in LCO 3.3.6.1 overlaps this SR to provide complete testing of the safety function. The Surveillance is c6ntrolled under the Surveillance Frequency Control Program. SR 3.6.1.3.11 This SR requires a demonstration that a representative sample of reactor instrumentation line excess flow check valve (EFCVs) is OPERABLE by verifying that the valve *actuates to the isolation position on a simulated instrument line break signal. The representative sample consists of an approximately number of EFCVs, such that each EFCV is tested at least once every 10 years (Nominal). In addition, the EFCVs in the sample are representative of the various plant. configurations, models, sizes and operating environments. *This any potentially common problem with a specific type of application of EFCV is detected at the earliest possible time. This SR provides assurance that the line EFCVs will perform so that predicted radiological consequences will not be exceeded during a postulated instrument line break event. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.12 The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not pbssible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.6-28 Revision No. 86

! I. BASES SURVEILLANCE REQUIREMENTS (continued) . ' .<. ... .... " PBAPS UNIT -2 SR 3.6.1.3.13 PC I Vs B 3.6.1.3 This SR ensures that in case the non-safety grade instrument air system is unavailable, the SGIG System will perform its function to supply nitrogen gas at the required pressure for valve operators and valve seals supported by the SGIG System. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.14 Total leakage through all four main steam lines must bes 170 scfh, ands 85 scfh for any one steam line, when tested at 25 psig. The analysis in Reference 1 is based on treatment of MSIV leakage as secondary containment bypass leakage, independent of the primary to secondary containment leakage analyzed at La. The Frequency is in accordance with the Primary Contaihment Leakage Rate Testing Program. SR 3.6.1.3.15 Vetifying the opening Qf 6 inch and 18 inch primary containment purge valve and each 18 inch containment 'exhaust valve is restricted by a blocking device to less than orequal to the required maximum opening angle s p e c i f i ea i n . the U FSA R C Ref . 4 ) i s. re q u i r e d to e n s u re t h a t the can cl6se under OBA conditioris within the times in the analysfs of Ref.erence 1. If a LOCA occurs, the purge valves must close to primary leakage within the values assumed in the accident.analysis. A't other times. pressurization concerns. thJs purge exhaust can be fully The-Frequency is controlled under the Surveillance Frequency Control Program. -. . ' continued *. * ... . ** ; . B 3.6-29 Revision No.* 114 I I BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UN IT 2 SR . 3.6.1.3.16 PC I Vs B 3.6.1.3 The inflatable of each 6 inch and 18 inch primary containment purge valve and each 18 inch primary containment exhaust valve must be replaced periodically. This will allow the opportunity for replacement before gross leakage failure occurs. 1. UFSAR, Chapter 14. 2. UFSAR, Table 7.3 .. 1. 3. 10 CFR 50, Appendix J, Option B. 4. UFSAR, Table 7.3.1; Note 17.

• 5 . U FSA R , Ta b l e 5 . 2 . 2 . 6 .. _UFSAR, Table 7:3.1, Note 14. 7. NEDC-33566P, "Safety Analysis Report for Exelon Peach .Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0 .. . . --* --.. . . -. .. ' : *.; .* B 3.6-30 Revisidh N6. 114 *.-. -

, .. Drywell Air Temperature B 3.6.1.4

• B 3. 6 CONTAINMENT SYSTEMS B 3. 6 .1. 4
• Drywe 11 A fr Temperature BASES .BACKGROUND *. APPLICABLE SAFETY ANALYSES *: ' . ";* ... '-*'.' LCO ' .** .. PBAP_S. UNIT 2 .. : \ .* . -* : .. ._,** The drywell contains the reactor vessel and piping, which add. heat to the *airs pace. Drywe 11 coolers remove heat and maintain a suitable environment. The average airspace temperature affects the calculated response to postulated Design Basis Accidents (DBAs). The limitation on the *-:drywell average air temperature was developed as reasonable; based .on operating experience. The limitation on drywell air tempera:ture .is used in the Reference 1 safety analyses. Primary containment performance* is evaluated for a .. * . spectrum of break sizes for postulated loss of .coolant accidents (LOCAs) (Ref. Among the inputs to the design basis analysis is the initial drywell average air . temperature (Ref. 1). Analyses assume an initial average*
• drywell *air temperature* . ThiS .1 imitation ensures that the safety analysis remains valid by maintaining the expected initial conditioris .and ensures that the peak LOCA drywell temperature does .. not. exceed the allowable. temperature of 281° F (Ref, . 2) except for a brief period of . 'less tha'h 20 seconds whi.ch was determined to be acceptable . in Refe_rences* l and 3.
• Exceeding this design temperature may .result in the degradation of the prima:ry containment . structure under accident loads. Equipment inside primary containment required to mitigate the effects of a OBA is ** designed *to operate* and be capable of opE!rati ng under * * . * ... *. envfronmental conditions -expected for.the accident. . . . . Drywell air temperatt1re satisfi.es Criterfon 2 of the NRC . Policy Statement:* * *. * .*In the event of with an initial_drywell average air *. temperature less than or equal to the LCO temperature limit, the resultant peak accident temperature is maintai.ned within . acceptable lilllits for.the drywell. As a result, the ability of primary containment to perform its design function is ** * (continued) . . . .
• 8"3*;6'.""31 Revision No.**1a .. : *"* ' .. ::* **. .. ':.** ... ** ... -:**

" .* *.* Drywell Air Temperature B 3.6.1.4 BASES (continued) APPLICABILITY ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 In MODES I, 2, and 3, a OBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are

• reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining drywell average air temperature within the limit is not required in MODE 4 or 5. With drywell average air temperature not within .the* limit of the LCO, drywell average air temperature must be restored within 8 hours. The Required Action is necessary to return operation to within the bounds of the primary containment analysis. The 8 hour Completion Time is acceptable, considering the sensitivity of the analysis to variations in this parameter, and provides sufficient time to correct minor problems. B.l and B.2 If the drywell average air temperature cannot be restored to . within the limit within the required Completion Time, the plant must be brought to a MODE in which the LCO does not To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within
• 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
• SR 3 . 6 . I. 4
• I Verifying that the drywell average air temperature is within -the LCO limit ensures that remains within the .. limits assumed.for the primary containment analyses. . Drywell air temperature is monitored in various quadrants . and at various elevations. Due to the shape of the drywell, a volumetric average is used to determine 'an accurate represe'ntation of the actual average temperature. * (continued) B 3 .6-3.2 Revision Np. 0 I : '. BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 SR 3.6.1.4.1 (continued) Drywell Air Temperature B 3.6.1.4 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 2. UFSAR, Section 5.2.3.1. 3. Deleted ,.**; B 3.6-33 Revision No. 114 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.5 Reactor Building-to-Suppression Chamber Vacuum Breakers BASES BACKGROUND . . PBAPS UNIT 2 The function of the reactor building-to-suppression chamber vacuum breakers is to relieve vacuum.when primary containment depressurizes below reactor building pressure. If the drywell depressurizes below reactor building pressure, the negative differential pressure is mitigated by flow through the reactor building-to-suppression chamber vacuum breakers and through the drywel l vacuum breakers. The design of the external {reactor building-to-suppression chamber) vacuum relief provisions consists of two vacuum breakers (a check valve and an air operated butterfly valve), located in series in each of two lines from the reactor building to the suppression chamber airspace. The butterfly valve is actuated by a differential pressure signal. The check valve
• is self actuating and can be manually operated for testing purposes. _The two vacuum breakers in series must be closed to maintain a leak tight primary containment boundary. A negative differenti'al pressure across the drywell wall is by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, primary containment spray actuation, and steam condensation in the event of a primary system rupture. Reactor building-to:..suppression chamber vacuum breakers prevent an excessive negative differential pressure across the primary containment boundary. Cooling cycles result in minor pressure. transients in the drywell, which occur slowly and are normally controlled by heating and ventilation equipment.
• Inadvertent spray actuation results in a significant negative pressure *transient and is. the design. basis event postul_ated in sizing the external (reactor chamber) vacuum The external vacuum breakers are sized on the basis of the air flow from the secondary containment that is required to mitigate-the depressurization transient and limit the . maximum negative containment (suppression chamber) pressure
• to within design limits. The maximum depressurization rate is a function of the prjmary containment spray flow rate and. temperature _arid the assumed initial conditions of the * {continued} * ... :_, B *J.6.;-34 Revision No. o BASES BACKGROUND (continued) APPLICABLE *. SAFETY ANALYSES >PBAPS UNIT 2. Reactor Chamber Vacuum Breakers B 3.6.1.5 suppression chamber atmosphere. Low spray temperatures and atmospheric conditions that yield the minimum amount of contained noncondensible gases are for conservatism. The Safety Grade Instrument Gas CSGIG) System supplies pressurized nitrogen gas (from the Containment Atmospheric Dilution CCAD) liquid nitrogen storage tank) as a safety grade pneumatic source to the CAC System purge and exhaust isolation valve inflatable seals, the chamber vacuum air operated isolation butterfly valves and inflatable seal, and the CAC and CAD Systems vent control air operated valves. The SGIG System thus performs two distinct post-LOCA functions: (1) suppojts containment isolation and (2) supports CAD System vent operation. SGIG System requirements. are addressed for each of the supported system and components in LCO 3.6.1.3 "Primary Containment Isolation Valves CPCIVs)," LCO 3.6.1.5, and Reactor Building-to-Suppression Chamber Vacuum Breakers." For the SGIG System, liquid nitrogen from the liquid nitrogen storage tank passes through the liquid nitrogen vaporizer where it is converted to a gas. The gas then flows into a Unit 2 header and a Unit 3 header separated by two globe valves. From each header, the gas then branches to each valve operator or valve seal supplied by the SGIG System. Each branch is separated from the header by a manual globe valve and a check valve. To Support SGIG System functions, the inventory is equivalent to a storage tank minimum required level of;;:: 22 water column; or a technically justified source of 124,000 scf at 250 psig, and a minimum SGIG System header pressure of 80 psig. AnalyticaT methods and involving the reactor chamber vacuum breakers are used as part of the accident. response of the containment systems. Internal Csuppression-chamber-to-drywell) and external building-to-suppression chamber) vacuum breakers continued B 3.6-35
• R.e vi s i on No . 91 BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNIT 2. *. Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 are provided as part of the primary containment to limit the negative differential pressure across the drywell and suppression chamber walls, which form part of the primary containment boundary. The safety analyses assume the external vacuum breakers to be closed initially and to be fully open at 0.75 psid. Additionally, of the four reactor building-to-suppression chamber vacuum breakers (two in each of the two lines from the reactor build.ing-to-suppression chamber airspace), one is assumed to fail in a closed position to satisfy single active failure criterion. Design Basis Accident (OBA) analyses require the vacuum breakers to be closed initially and to remain closed and leak tight with positive primary containment pressure. Three cases were considered in the safety analyses to determine the adequacy of the external vacuum breakers: a. A small break loss of coolant accident followed by actuation of both drywell spray loops; b. Inadvertent actuation of one drywell spray loop during normal operation; and c. A postulated DBA assuming low pressure coolant injection flow out the loss of coolant accident break, which condenses the drywell steam. The results of these*three cases show that the external vacuum with an opening setpoirit of 0.75 psid, are capable of maintaining the differential pressure within design limits. * -The reactor building-to-suppress"ion chamber "vacuum breakers *satisfy Criterion 3 of the NRC Policy . . . All reactor building-to-suppression chamber vacuuin breakers are required to be OPERABLE to satisfy the assumptions used . in the safety* analyses. The requirement ensures that the two vacuum breakers (check valve and air operated butterfly valve) in each of the two lines from the reactor building to (continued) .* B 3.6,..36 Revision No. O BASES LCO (continued) APPLICABILITY ACTIONS PBAPS UNIT 2 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 the suppression chamber airspace are closed. Also, the requirement ensures both vacuum breakers in each line will open to relieve a negative. pressure in the suppression chamber (except during testing or when performing their intended function). In addition, for the reactor building-to-suppression chamber vacuum breakers to be considered OPERABLE and closed, the SGIG System supplying nitrogen gas to the air operated valves and inflatable seal of the vacuum breakers must. be OPERABLE. In MODES 1, 2, and 3, a OBA could result in excessive negative differential pressure across the drywell wall caused by the rapid depressurization of the drywell. The event that results in the limiting rapid depressurization of the drywell is the primary system rupture, which purges the drywell of air and fills the drywell free airspace with steam. Subsequent condensation of the steam would result in depressurization of the drywell. The limiting pressure and temperature of the primary system prior to a OBA occur in MODES I, 2, and 3. Excessive negative pressure inside primary containment could also occur due to inadvertent initiation of the Orywell Spray System. In.MODES 4 and 5, the probabflity and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining reactor building-to-suppression chamber vacuum breakers OPERABLE is not required in MODE 4 or 5. A Note has been added to provi_de clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. With one or more lines with one vacuum breaker not closed, the leaK tight primary containment boundary may be threatened. Therefore, the inoperable vacuum breakers must be restored to OPERABLE status or the open vacuum breaker closed within 72 hours. The 72 hour Completion Time is consistent with requirements for inoperable suppression chamber-to-drywell vacuum breakers in LCO 3.6.1.6, (continued) B 3.6-37 Revision No. O BASES ACTIONS .*:, . PBAPS UN IT 2 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 A.l (continued) "Suppression Chamber-to-Drywel l Vacuum Breakers." The 72 hour Completion Time takes into account the redundant capability afforded by the remaining breakers, the fact that the OPERABLE breaker in each of the lines is closed, and the low probability of an event occurring that would require the vacuum breakers to be OPERABLE during this period. With one or m6re lines with two vacuum breakers not closed, primary containment integrity is not maintained. Therefore, one open vacuum breaker must be closed within 1 hour. This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restored to OPERABLE status within 1 hour. With one line with one or more vacuum breakers inoperable *for opening, the leak tight primary containment boundary is intact. The ability to mitigate an eveht that causes a containment is threatened if one or more. breakers in at least one vacuum breaker penetration are not OPERABLE. inoperable vacuum breaker must be restored to OPERABLE status within 72 This i s co n s i st e n t wit h t he Comp l et i o n T i me fo r Con d it i o n A a n d the fact that the leak ti.ght primary boundary is being If one line has one or more breakers inoperable for. *. opening:and they are not within the Completion Time .in Condition .C, the.remainingvacuum breakers in the remaining line can provide the opening fuhcti on; . The pl ant must be broug[it to a condition in whic.h the.overall plant risk is mi.nimized. To .. *aohi eve status, the pl must be brought to at least MODE 3 within 12 .. hours. Remaining in the Applicability of the LCO is acceptable the plant in MODE 3 is similar. to or lower risk in MODE 4 (Ref. 1) and because the time in MODE 3 __ to perfonn the necessary repairs to re_store the system to OPERABLE* status wi.ll be .short. However, voluntary entry into MODE 4-*may be made as it is also an acceptal:Jle low-risk state. The allowed Time is reasonable, based on operat{ng experience, to reach the required plant conditions from ful r power tonditiohs in an and without
• plant systems. ' -' continued B 3.6-38 Revision No. 66 BASES Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 ACTIONS l...:..1 (continued) SURVEILLANCE REQUIREMENTS PB1WS UN IT 2 With two lines with. one or more vacuum breakers inoperable for opening, the primary containment boundary is intact. However, in the event of a containment depressurization, the function of the vacuum breakers is lost. Therefore, all vacuum breakers in one line must be restored to OPERABLE status wHhin 1 hour. This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour. F.1 and F.2 If any Required Action and associated Completion Time for Conditions A, B, or E cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To . achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.1.5.1 Verifying that the nitrogen inventdry is equivalent to a level in the liquid nitrogen tank 22 inches water column 124,000 scf at 250 psig) will ensure at least 7 days of post-LOCA SGIG System operatibn. This minimum volume of nitrogen allows sufficient time after an accident. to repJenish the nitrogen in order to maintain the design function of the reactor building:to-suppression vacuum breakers. The inventory is verified to ensure that the system is capable of perf6rming its intended function when required. The Surveillance Frequency is
• controlled under the Surveillance Frequency.Control Program. SR 3.6.1.5.2 This SR ensures .that the pressure in the SGIG System header 80 psig. This ensures that the post-LOCA nitrogen pressure provided to the valve operators and seals that is adequate for the SGIG to perform its design function .. The Survei 11 ance Frequency is .controlled under the Surveillance Frequency Control Program.
• continued B 3.6c39 Revi s1 on No: 91 BASES SURVEILLANCE .REQUIREMENTS (continued) PBAPS UN IT 2 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 SR 3.6.1.5.3 Each vacuum breaker is verified to be closed to ensure that a potential breach in the primary containment boundary is not present. This Surveillance is performed by observing local or control room indications of vacuum breaker position or by verifying a differential pressure of 0.75 psid is maintained between the reactor building and suppression chamber. The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program. Two Notes are added to this SR. The first Note allows* reactor building-to-suppression chamber vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers. A second Note is included to clarify that vacuum breakers open due to an actual differential pressure, are not as failing this SR. SR 3.6.1.5.4 Verifying the correct alignment for each manual valve in the SGIG System flow paths provides assurance that the . proper flow paths exist for system This SR does not apply to valves that are locked.or otherwise secured in position, these were verified to be in the correct position prior to locking or securing. This SR does not any or valve manipulation; rather, it. involves verification that those valves capable of being mispositioned are in the correct position.* Thi*s SR does. not to valves that cannot be inadvertently misaligned, such as check The Surveillance Frequency is . I
• contrcilled under the Suryeillance frequericy Control Progrim. . continued B 3.6-40
• Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UN IT 2 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 SR 3.6.1.5.5 Each vacuum breaker must be cycled to ensure that it opens properly to perform its design function and returns to its fully closed position. This ensures that the safety analysis assumptions are valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.5.6 Demonstration of air operated vacuum breaker opening setpoint is necessary to ensure that the safety analysis assumption regarding vacuum breaker full open differential pressure of s 0.75 psid is valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.5.7 This SR ensures that in case the non-safety grade instrument air system is unavailable, the SGIG System will its design function to supply nitrogen gas at the required pressure for valve operators and valve seals supported by the SGIG System. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. L NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.6-41 Revision No. 86 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.6 Suppression Chamber-to-Drywell Vacuum Breakers BASES BACKGROUND PBAPS UNIT 2 --The function of the suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell. There are 12 internal vacuum breakers located on the vent header of the vent system between the drywell and the suppression chamber, which allow air and steam flow from the suppression chamber to the drywell when the drywell is at a negative pressure with respect to the suppression chamber. Therefore, suppression chamber-to-drywell vacuum breakers prevent an excessive negative differential pressure across the wetwell drywell boundary. Each vacuum breaker is a self actuating valve, similar to a check valve, which can be remotely operated for testing purposes. A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, drywell spray actuation, and steam condensation from sprays or subcooled water reflood of a break in the event of a primary system rupture. Cooling cycles result in minor pressure transients in the drywell that occur slowly and are normally controlled by heating and ventilation equipment. Spray actuation or spill of subcooled water out of a break results in more significant pressure transients and becomes -_ important in sizing the internal vacuum breakers. In the event of a primary system steam condensation within the drywell results in the most severe pressure transient. Following-a primary system rupture, air in the drywell.'is-purged .into the suppression chaniber free -airspace, leaving the drywell -full of steam. Subsequent condensation of the steam can be caused in two possible ways, namely, Emergency Core Cooling Systems flow from a _ reCirculation*linebreak, or.drywell_spray actuation
• following a loss* of coolant accident (LOCA). These two cases the maximum depressurizatioil rate of the drywel l. * -. --In addifio-n, the waterleg in the Mark I Vent System downcomer. is-controlled-by* the drywell-:to-suppression -Chamber d'i fferent i a 1 -pressure. lf the drywe 11 pressure is -1 ess than the suppression chamber pressure; there will be an increase in the vent wa:terleg. This will result in an* . -(continued) B 3.6-42 --Revision No. 0 -

BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UNIT. 2 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 increase in the water clearing inertia in the event of a postulated LOCA, .resulting in an increase in the peak drywell pressure. This in turn will result in an increase in the pool swell dynamic loads. The internal vacuum breakers limit the height of the waterleg in the vent system during normal operation. Analytical methods and assumptions involving the suppression vacuum breakers are used as. part of the accident response of the primary containment systems. Internal (suppression chamber-to-drywell) and external (reactor b4ilding-to-suppression chamber) vacuum breakers provided as part of the primary containment to limit the negative pressure across the drywell and suppression walls that form part of the primary containment boundary. The safety analyses assume that the internal vacuum breakers are initially and are fully open at a differential pressure of 0.5 psid. Additionally, 1 of the 9 internal vacuum breakers required to open is assumed to fail in a closed position. The results of the analyses show that the design pressure is not. exceeded even under the worst case accident scenario, The vacuum breaker opening differential pressure and the requirement that 9 of 12 vacuum breakers be OPERABLE are a result of the requ*i rement pl aced on the* vacuum breakers to limit the ient system waterleg height .. The total cross sectional area of the main vent system between the drywell and suppression chamber needed to fulfill this requirement has been established as a minimum of _51.5 times the total break area. In turn, the vacuum

• relief betweeh the drywell and suppression chamber _should be l/16 of the total main vent cross sectional area, with the valves set tp operate at 0.5 psid differential -This was the original design for Peach Bott'om, which 'required 10:_ 18" _vacuum breakers to meet the 1/16 .of the total main vent' cross sectional area. However, current design basis requirement for 9 vacµum breakers .to be *. hne of which is assumed to fail to active failure)., is found in Reference _ -Design _B-asis Accident CDBA) .analyses require the. vacuum be and to remain closed and leak tight, until the sappression pool ii at a positive pressure relative to the drywel l. All. suppression to-drywell -vacuuril breakers are considered closed _if a leak c6nfirms that the bypass area between the drywell and suppression .chamber is less than or equivalent to a diameter hole (Ref. 1). * * -* The vacuum Critefjon 3 of the NRC Policy Statement.* (continued) Revision Nb. 44 BASES (continued) Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 LCD Only 9 of the 12 vacuum breakers must be OPERABLE for opening. All suppression chamber-to-drywell vacuum breakers are required to be closed (except when the vacuum breakers are performing their intended design function). All suppression chamber-to-drywell vacuum breakers are considered closed, even if position indication shows that one or more vacuum breakers is not fully seated, if a leak test confirms that the bypass area between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole. The vacuum breaker OPERABILITY requirement provides assurance that the drywell-to-suppression chamber negative differential pressure remains below the design value. The requirement that the vacuum breakers be closed ensures that there is no excessive bypass leakage should a LOCA occur. APPLICABILITY ACTIONS PBAPS UNIT 2 In MODES 1, 2, and 3, a OBA could result in excessive negative differential pressure across the drywell wall, caused by the rapid depressurization of the drywell. The event that results in the limiting rapid depressurization of the drywell is the primary system rupture that purges the drywell of air and fills the drywell free airspace with steam. Subsequent condensation of the steam would result in depressurization of the drywell. The limiting pressure and temperature of the primary system prior to a OBA occur in MODES 1, 2, and 3. Excessive negative pressure inside the drywell could also occur due to inadvertent actuation of the Drywell Sp.ray System. In MODES 4 and 5, the probability and consequences of these events are reduced by the pressure and temperature limitations in these therefore, maihtaining suppression vacuum breakers OPERABLE is not required in MODE 4 or 5. With one of the required vacuum breakers inoperable for opening (e.g., the vacuum breaker is not open and may be stuck closed or not within its opening setpoint limit, so that it would not function as designed during an event that depressurized the drywell), the remaining eight OPERABLE vacuum breakers are capable of providing the vacuum relief function. However, overall system reliability is reduced (continued) B 3.6-44 . Revision No. 0 BASES ACTIONS PBAPS_ UNIT 2 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 A.l (continued) because a single failure in one of the rema1n1ng vacuum breakers could result in an excessive suppression to-drywel l differential pressure during a OBA. Therefore, with one of the nine required breakers inoperable, 72 hours is allowed to restore the inoperable vacuum breaker to OPERABLE status so that plant conditions are consistent with those assumed for the design basis analysis. The 72 hour Completion Time is considered acceptable due to the low probability of an event in which the remaining vacuum breaker capability would not be adequate. If a required suppression chamber-to-drywell vacuum breaker is inoperable for opening and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To -achieve this status, the plant must be brought to at least MObE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than-the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary into MODE 4 may be made as it is also an acceptable risk state. The allowed Completion Time is reasonable, based on 6perating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. An open vacuum breaker allows communication between the drywell and suppression chamber airspace, and, as a result, there is the potential for suppression chamber overpressurization due to this bypass leakage if a LOCA were to occur. Therefore, the open vacuum breaker must be closed. A short time is allowed to close the vacuum breaker due to the low probability of an event that would pressurize .primary containment. If vacuum breaker position indication is not reliable, an_ alternate method of verifying that the vacuum breakers are must be performed 10 hours.* All suppression chamber-to-drywell vacuum breakers are considered closed, even if the "not fully seated" indication is shown, if a leak test confirms that continued B 3.6-45 Revision No. 66 i, BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 L..l (continued) the bypass between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole (Ref. 1). The required 10 hour Completion Time is considered adequate to perform this test. If the leak test fails, not only must the Actions be taken (close the open vacuum breaker within 10 hours), but also the appropriate Condition and Required Actions of LCD 3.6.1.1, Primary Containment, must be entered. D.l and 0.2 If the open suppression chamber-to-drywell vacuum breaker cannot be closed within the required Completion Time, the plant must be brought to a MODE in which the LCD does not apply. To achieve this Status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions. from full power conditions in an orderly manner and without challenging plant systems. SR 3 . 6 . 1.6 . 1 Each vacuum .breaker is* Verified closed to ensure that this large bypass leakage js present. This is performed by observing the vacuum breaker indication or by performing a test that that the bypass area between the drywell and suppression damber is less thanbr equivalent to* a one-inch *diameter hole. If the bypass test fails, *not only must the
• vacuum be considered open and the appropriate
• and Required of LCD be entered, but also the appropr.i ate Condi tfon and Required Action of LCD 3,6.1.,lmust.be entered:* The Surveillance.Frequency ts .1* controlled .. under the Survei'l lance Frequency Con.trol Program. A Note is.added to SR breakers opened in with the performarice*of a Surveillance to not be considered as failing this _SR.* These periods .of opening vacuum breakers are *
• controlled by plant procedures and do not represent i noperabl'e vacuum breakers. . ., continued B 3.6-46. Revision No. 86 *" *'

BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES . . .

• PBAPS UNIT. 2 .SR 3.6.1.6.2 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 Each required vacuum breaker must be cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position. This ensures that the safety analysis assumptions are valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.6.3 Verification of the vacuum breaker setpoint for full opening is necessary to ensure the safety analysis assumption regarding vacuum breaker full open differential pressure of 0.5 psid valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 127 and 130 to Facility Operating License Nos. DPR-44 and DPR-56, dated February 18, 1988. 2. ME-0161, "Det. Actual # Wetwell to Vacuum _ Breakers Reqd." 3. NEDC-32988-A, Revision 2,. Technical Justification to Modification to Selected Required End Statei for BWR Plants; December 2002 . . . -..
• B *
• Revis-ion No .. 86 I . I. I Suppression Pool Average Temperature B 3.6.2.1
• B 3.6 CONTAINMENT SYSTEMS B 3.6.2.1 Suppression Pool Average Temperature BASES BACKGROUND , .... ** The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the decay heat and sensible energy released during a reactor blowdown from safety/relief valve discharges or from Design Basis . Accidents (DBAs). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment that ensures that the peak containment pressure is maintained below maximum allowable pressure for DBAs (56 psig). The suppression pool must also condense steam from steam exhaust lines in the turbine driven systems (i.e., the High Pressure Coolant Injection System and Reactor Core Isolation Cooling Suppression pool average temperature (along with LCO 3.6.2.2, "Suppression Pool Water Level") is a key indication of the capacity of the suppression pool to fulfill these requirements. *
• The technical concerns that lead to the development of sup.press ion pool average temperature limits are as fa 11 ows: a. Complete steam condensation--the original limit for the end of a LOCA blowdown was 170"F, based on the Bodega Bay and Humboldt Bay Tests; b. Primary containment peak pressure and design pressure is 56 psig and design temperature is 2s1*F (Ref. I); c.
• Condensation oscillation loads--maximum allowable initial temperature is 1I0°F. APPLICABLE The postulated OBA against which the primary containment SAFETY ANALYSES performance is evaluated is the entire spectrum of postulated pipe breaks within the primary containment. Inputs to the safety analyses include initial suppression pool water volume and suppression pool temperature (Ref. 2). An initial pool temperature of 95*f is assumed for the (continued) . PBAPS .UNIT 2 B 3.6,.48 Revision o

. " *.-*-:* I .* ... *, -* .. . ,_ . I .* .. I *.*'* BASES APPLICABLE SAFETY ANALYSES LCO . _:: :: *.1., -; .. *' . PBAPS

• UNIT*2 * -. . . Suppression Pool Average Temperature B3.6.2.l Reference I and Reference 2 analyses. Reactor shutdown at a pool temperature of 110°F and vessel depressurization at a pool temperature of 120°F are assumed fo.r the Reference 2 analyses* .. The lim.it of 105°F, at which testing is terminated, is not used in the safety analyses because DBAs are assumed to not initiate during unit testing. poo1 average temperature satisfies Criteria 2 and 3 of the NRC Policy Statement. A limitation on the suppression pool average temperature is required to provide assurance that the containment conditions assumed for the safety analyses are met. This: limitation subsequently ensures that peak primary containment pressures*and temperatures do not exceed maximum allowable values during a postulated. OBA or any transient resulting in heatup of the suppression *The LCO **requirements are:
• a.
• Average temperature 95°F when any OPERABLE wide* .. range neutron monit6r (WRNM) channel is at l.OOEO % power*or above and no testing that adds heat to the suppression pool is being performed .. This requirement *ensures that licensing bases initial conditions met. * *
• b. Average temperature 105°F when any OPERABLE WRNM . channe 1 is at I. OOEO % power or above and testi rig that adds heat to_ the suppression pool .is being performed. This required value ensures. that. the unit has testi'ng .* **flexibility,-and was.selected to provide margin below* the* 110°F 1 imit at which reactor shutdown* is reql.ilred. *.
• When testing ends, temperature must be restored. to 95°F.within 24 hours according-to*Required . Action A.2. Therefore, the time period that the temperature is * > 95.°F is short enough not *to cause* a **.significant increase in unit risk .. -c.. 110° F *when* all 'OPERABLE WRNM . " channels are below: 1.00EO % power .. This requirement ensures that* the unit will be shut down at > 110°F .. The pool is.designed to .absorb dec:;ay and sensible.* . heat but could be heated beyond design 1 by the ** . steam if the reactor is* not shut down. . * *.*" Ccontfoued) *** -.. * .' . 8 3.6-49 * . ** Revision No. 24. .. , ** ..

BASES LCO {continued) APPLICABILITY ACTIONS

• PBAPS UN IT 2 Suppression Pool Average Temperature B 3.6.2.1 Note that WRNM indication at l.OOEO % power is a convenient measure of when the reactor is producing power essentially equivalent to 1% RTP. At this power level, heat input is approximately equal to normal system heat losses. In MODES 1, 2, and 3, a DBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining suppression pool average temperature within limits is not required in MODE 4 or 5. A.I and A.2 With the suppression pool average temperature above the *specified limit when not performing testing that adds heat to the suppression pool and when above the specified power indication, the initial conditions exceed the conditions assumed for the Reference 1, 2, and 3 analyses. However, primary containment cooling capability still exists, and the primary containment pressure suppression function will occur at temperatures well above those assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The 24 hour Completion Time is adequate to allow the suppression pool average temperature to be restored below the limit. Additionally, when suppression pool temperature is > 95°F, increased monitoring of the suppression pool temperature is required to ensure that it remains s 110°F. The once per hour Completion Time is adequate based on past experience, which has shown that pool temperature increases relatively slowly except when testing that adds heat to the suppression pool is being performed. Furthermore, the once per hour Completion Time is considered adequate in view of other indications in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition. If the suppression pool average temperature cannot be restored to within limits within the required Completion ,Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the power must be reduced to below l.OOEO % power for all OPERABLE WRNMs (continued) B 3.6-50 Revision No. 24 BASES ACTIONS 1* I PBAPS
• UN II 2 B.l (continued) Suppression Pool Average Temperature B 3.6.2.l within 12 hours. The 12 hour Completion Time is reasonable, based on operating experience, to reduce power from full power conditions in -0rderly manner and without
• challenging plant systems. C. l Suppression pool average temperature is allowed to be > 95°F when any OPERABLE WRNM channel is at % power or above, and when testing that adds heat to the suppression pool is being performed. However, if temperature is > 105°F, all testing must be immediately suspended to preserve the heat absorption capability of the suppression pool. With the testing suspended, Condition A is entered and the Required Actions and associated Completion Times are applicable. D.l. D.2. and D.3 Suppression pool average temperature > ll0°F requires that *the reactor be shut down immediately. This is accomplished by placing the reactor mode switch in the shutdown position. Further cooldown to MODE 4 is required at normal cooldown rates (provided pool temperature 120°F). Additionally, when suppression pool temperature is > II0°F, increased monitoring of pool temperature is required to ensure that it remains 120°F. The once per 30 minute Completion Ti me is adequate, . based on operating experience. *Given the high suppression pool average temperature in this Condition, the.monitoringFrequency is increased to twice that of Cohd it fan A. . Furthermore, the 30 minute Comp 1 et ion Ti me is considered adequate in view of o_ther i ndi cat i ans .. available in the control room, including alarms, to alert the operitorto an abnormal pool average tempetature condition.
• E. l and E. 2 If suppression pool average temperature*. cannot be maintained 120°F, the plant must be* brought to a MODE in whfch the LCO does not To stattis, the reactor pressure must be reduced t() < 200 psig within 1.2 hours, *and the plant must be bfought.to least MODE 4 within-. -*
• B 3.6-51 Revision .. No. 24 I BASES ACTIONS SURVEILLANCE REQUIREMENTS REFtRENCES PBAPS UNIT 2 E.l and E.2 (continued) Suppression Pool Average Temperature B 3.6.2.1 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. Continued addition of heat to the suppression pool with suppression pool > 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure. Furthermore, if a blowdown were to occur when the was > the maximum allowable bulk and local temperatures could be exceeded very quickly. SR 3.6.2.1.l The suppression pool average temperature is regularly monitored to ensure that the required 1imits are satisfied. The average temperature is determined by taking an arithmetic average of OPERABLE suppression pool temperature channels. The Surveillance Frequency is contr.ol led under the Survei 11 ance Frequency Control Program. 5 minute Frequency during testing is justified by the rates at which tests will heat up the suppression pool, has been shown to be acceptable based on operating experience, and provides assurance that allowable pool temperatures not exceeded. The Frequency is justified in of* other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pogl temperature condition. 1. UFSAR, Section 5.2. 2. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 3. NUREG-0783. B 3. 6-52: Revision No, 114 Suppression Pool Water Level B 3.6.2.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.2 Suppression Pool Water Level BASES BACKGROUND PBAPS*UNIT 2 The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the energy associated with decay heat and sensible heat released during a reactor blowdown from safety/relief valve (S/RV) discharges or from a Design Basis Accident (OBA). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment, which ensures that the peak containment pressure is maintained below the maximum allowable pressure for DBAs (56 psig). The suppression pool must also condense steam from the steam exhaust lines in the *turbine driven systems (i.e., High Pressure Coolant Injection (HPCI) System and Reactor Core Isolation Cooling (RCIC) System) and provides the main emergency water supply source for the reactor vessel. The suppression pool volume ranges between 122,900 ft3 at the low water level limit of 14.5 feet and 127,300 ft3 at the high water level limit of 14.9 feet. If the suppression pool water level is too low, an insufficient amount of water would be available to adequately condense the .steam from the S/RV quenchers, main vents, or HPCI and RCIC turbine exhaust lines. Low
• suppression pool water level could alsri result in an inadequate emergency makeup water source to the Emergency . Core Cooling System. The lower volume would also absorb less steam energy before heating up excessively. Therefore, a minimum suppression pool water level iS specified.
• If the suppressiori pool level is too high, it . result in excessive clearing loads from S/RV discharges and excessive pool swell loads during a OBA LOCA. Therefore, a maximum pool water level is specified. This LCO specifies. an acceptable range to prevent the suppression pool water level from being either too high or too low. (continued)* B 3 .6-53 . Revision No. 0 Suppression Pool Water Level B BASES (continued) APPLICABLE Initial suppression pool water level affects suppression SAFETY ANALYSES pool temperature response calculations, calculated drywell pressure during vent clearing for a OBA, calculated pool swell loads for a OBA LOCA, and calculated loads due to S/RV discharges. Suppression pool water level must be maintained within the limits specified so that the safety analysis of Reference I remains valid. LCO APPLICABILITY ACTIONS PBAPS UNIT 2 Suppression pool water level satisfies Criteria 2 and 3 of the NRC Policy Statement. A limit that suppression pool water level 14.5.feet and s 14.9 feet is required to ensure that the primary containment conditions assumed for the safety analyses are met. Either the high or low water level limits were used in the safety analyses, depending upon which is more conservative for a particular calculation. In MODES 1, 2; and 3, a OBA would cause significant loads on the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. The . requirement for maintaining suppression pool water level within limits in MODE 4 or 5 is addressed in LCO 3.5.2, With suppression pool water level outside the limits, the conditions assumed for the safety analyses are not met. If . water level is below the minimum level, the pressure suppression function still exists as long as main vents are covered, HPCI and RCIC turbine exhausts are covered, and S/RV quenchers are covered. If suppression pool water level is above.the maximum level, protection against overpressurization still exists due to the margin in. the peak containment pressure analysis and the capability of the Drywell Spray System. Therefore, continued operation for a limited time is allowed. The 2 hour Completion Time is sufficient to restore suppression pool water level to within limits. Also, it takes into account the low probability of an event *impacting the suppression pool water level occurring during this interval. (continued) B 3.6-54 Revision No. 0 I BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS REFERENCES . ',._-*; PBAPS UNIT 2 B.1 and B.2 Suppression Pool Water Level B 3.6.2.2 If suppression pool water level cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion are reasonable, based on operating experience, to reach the required plant condttions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.2.2.1 Verification of the suppression pool water level is to ensure that the required limits are satisfied. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Sections 5.2 and 14.6.3. B 3.6-55.* Revision No. 86 RHR Suppression Pool Cooling B 3.6.2.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling BASES BACKGROUND PBAPS UN IT 2 Following a Design Basis Accident CDBA), the RHR Suppression Pool Cooling System removes heat from the suppression pool. The suppression pool is designed to absorb the sudden input of heat from the primary system. In the long term, the pool continues to absorb residual heat generated by fuel in the reactor core. Some means must be provided to remove heat from the suppression pool so that the temperature inside the primary remains within design limits. This function is provided by two redundant RHR suppression pool cooling subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES. Each RHR suppression cooling subsystem contains two motor driven pumps, two heat exchangers and a heat exchanger cross tie. line, and is manually initiated and independently controlled. The two subsystems perform the suppression pool cool.ing function by circulating water from the suppression pool. through the RH R heat
• exchangers and return i n g it to the suppression pool via the full flow test linei. The High Pressure Service Water CHPSW) System circulating through the tube side of the heat exchangers, exchanges heat with the pool water and heat to the external heat sink. The heat removal capability of cine pump and two heat in one subsystem are sufficient to meet the overall OBA pool cooling requirement for loss of coolant _accidents (LOCAs) and transient events such as a turbine trip or stu:ck.ppen safety/re.lief valve CS/RV) .. S/RV leakage and High Coolant Injection System and Reactor Core . I sol a ti on* Cool i r:ig System. t"esti ng i ricrease *suppression pool
• The RHR Pool Cooling System is also used to lower the suppression pbol water bulk temperat0re following
• Each subsystem is equipped with.an RHR heat excha.nger cross tie line,; located downstream of. each RHRpump discharge and upstream of each heat exchanger 1nlet, which allows* one RHR to aligned to supply _both RHR heat exchangers in the * .. same subsystem for*suppr.ession pool c"ooling when only one . RHR pump is available. The RHRheat exchanger cross tie valve is normally closed, and is assume.d*by designed basis* to be placed in ser_vice one hourfollowing a design basis accident or transient when insufficfent electr.ic power is av*atlable (e.g., single :EOG failure) tooperate tv.io RHR pumps * * (continued)* Revision No. 114 RHR Suppression Pool Cooling B BASES (continued) APPLICABLE SAFETY ANALYSES LCO APPLICAB-I LITY ACTIONS PBAPS UN.Ir 2 Reference 1 contains the results of analyses used to predict primary containment pressure and temperature following large and small break LOCAs. The intent of the is to demonstrate that the heat removal capacity of the RHR Suppression Pool Cooling System is adequate to maintain the primary containment conditions within design limits. The suppression pool temperature is calculated to remain below the design limit. The RHR Suppression Pool Cooling System satisfies Criterion 3 of the NRC Policy Statement. During a OBA, a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below design limits (Ref. 1). To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE with power from two safety related independent power Therefore, in the event of an accident, at least one is OPERABLE assuming the worst case single failure. An RHR suppression pool cooling subsystem is OPERABLE when one of the pumps, two heat exchangers in the same RHR subsystem, the associated RHR heat exchanger tie line, two HPSW System pumps capable of providing cooling to the two exchangers and associated piping, instrumentation, and controls are OPERABLE. Management of gas voids is important to RHR Suppression Pool I Cooling System OPERABILITY. . In MODES 1, 2, and 3, a OBA could cause a release'of radioactive material to primary containment and cause a heatup and pressurization 6f primary containment. In MODES 4 and 5, the and consequences of these
• events are reduced due to the pressure and temperature these MODES. Therefore, the RHR Suppression Pool Cooling System is not requiied to in MODE 4: or 5. * *
• With one RHR suppression pool cooling sGbsystem inoperable, the inoperable subsystem must be restored* to OPERABLE status. with.in 7 days; -In this Condition, the remaining RHR suppression pool cooling subsystem j.s adequate to perforfu the primary_ conta*i nment cooling function. However, the continued B 3.6-57 :Revision No. 126 BASES ACTIONS PBAPS *uN IT 2 A.l (continued) RHR Suppression Pool Cooling B 3. 6 .. 2. 3 overall feliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment cooling capability. The 7 day Completion Time is acceptable in light of the redundant RHR suppression pool cooling capabilities afforded by the OPERABLE subsystem and the low probability of a OBA occurring during this period. If one RHR suppression pool cooling subsystem is inoperable and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made *as it is also an acceptable low-risk state. The allowed . Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly*manner and without challenging plant systems. With two RHR suppression pool cooling subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 *hours. In this condition, there is a substantial loss of the primary containment pressure and temperature mitigation function. The 8 hour Completion Time is based on this loss of function and is considered acceptable due to the low probability of a OBA afid because alternative methods to remove heat from primary containment are available. D.1 and D.2 If the Required Action and associated Completion Time of Condition C cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued) B 3.6-58 Revision No. 66 BASES (.continued) SU RV EI LLANC E REQUIREMENTS SR 3.6.2.3.1 RHR Suppression Pool Cooling B 3.6.2.3 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident This is acceptable since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.2 .. 3.2 Verif.Yi-ng that each required RHR pump develops a flow* rate 8,600 :gpm while operating in the pocil cooling mode w1th flow thtbugh the associated heat exchanger ensures pump perfnrmance not degraded cycle. Flow is a hormal test bf centrifugal pump performance by ASME' Code (Ref. 3). This test confirms one point on .th*e-pump des.ign curve, *and the :results are in'c!icatJve of overall per.formance.: Suc-h inservite inspecticins confirm component OPERABILITY, trend performance, *and detect incipient failures*by*indicating: abnofmal performance. The Frequency ot this SR is in -acc'Ordance with the _tnservi ce Testing Program; PBAPS UN IT-2 SR 3.6.2.3.3 --. -. . . Verification of between the *normal and alternate power source (4kV emergency bus)* for each RHR flow control valve and each.RHR cross-tie demonstrates that AC power will be available 'to operate the required valves following loss of power to any .si qgl e 4kV emergency bus. --The ability to -(continued) B 3.6-59 Revision No. 114 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 -SR 3.6.2.3.3 (continued) RHR Suppression Pool Cooling B 3.6.2.3 provide power to each RHR motor-operated flow control valve and each RHR cross-tie valve from either of two independent 4kV emergency buses ensures that a single failure of a DG will not result in failure of the RHR operated flow control valve and the RHR cross-tie operated valve; therefore, failure of the manual transfer capability will result in inoperability of the associated RHR Suppression Pool Cooling subsystem. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.2.3.4 RHR Suppression Pool Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR Suppression Pool Cooling Subsystems and may also prevent water and pump Selection of RHR Suppression Pool Cooling -system locattons susceptible to gas is based on a review of -design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and _The design review is supplemented by system walk downs to validate the system high points and to confirm the location and of important components that can betome sources of gas or could otherwise gas to be trapped or difficult to remove during maintenance or restoration. Susceptible
• locations depend on plant *and system configuration, such as stand-by versus operatirig conditions. The.RHR-Suppression Pool Cooiing System is OPERABLE-when it is sufficiently filled with water. Acceptance criteria are established for the of Qas at l ocati ol')s .. If accumui ated gas .is discovered that exceeds the acceptance criteria fqr the susceptible location '(or the volume oJ-accumulated ga*s at one or more_ susceptible locations exceeds an acceptance criteri.a_for gas volume at -the sue-ti on or discharge of a pump), the Survei 11 ance is not If the accumulated gas is eliminated or brought within -the accephnce *criteria limits during-performance of the* Surveil 1 a nee,-the SR is met and past system OPERABILITY is evaluated-under the Corrective Action Program. If it is determined by subsequ*nt evaluation that the RHR S u p p r e s s _ i o n P o o l C o o l i n g Sy s t em i s n o t re n d e r e d by the gas (i.e., the system is (contfnued) _ B 3.6-59a' Revision. No. 127 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS -UN IT 2 SR 3.6.2.3.4 (continued) RHR Suppression Pool Cooling B 3.6.2.3 sufficiently.filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits, RHR Suppression Pool Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or conditioris, the plant or safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to* assure system OPERABILITY during the Survei 11 ance interval. The is modified by a Note. The Note recognizes that the
• of the sur0eillance is l{mited to the RHR system The HPSW system components have been .determined to not be required to be in the scope of this due to operating experience and the design of the system. The S1,1rveilTance Frequency 1s controlled under the Frequency Control Program. The Frequericy may vary by location susceptible to gas accumulation. 1. UFSAR, Section 14.6.3. 2. NEDC:32988-A, Revision 2, Technical Justification to Support Risk-Informed .Modification to Selected Required End States for BWR Plants, December 2002. 3; ASME Code for Operation and Maintenance of Nuclear Power Plants. B 3.6c59b R*evi si on No. 126 L i i RHR Suppression Pool Spray B 3.6.2.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray BASES BACKGROUND PBAPS UNil 2 Following a Design Basis Accident (OBA), the RHR Suppression Pool Spray System removes heat from the suppression chamber airspace. The suppression pool is designed to absorb the sudden input of heat from the primary system from a OBA or a rapid depressurization of the reactor pressure vessel (RPV) through safety/relief valves. The heat addition to the suppression pool results in increased steam in the suppression chamber, which increases primary containment pressure. Steam blowdown from a OBA can also bypass the suppression pool and end up in the suppression chamber airspace. Some means must be provided to remove heat from the suppression chamber so that the pressure and temperature inside primary containment remain within analyzed design limits. This function is provided by two redundant RHR suppression pool spray subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES. Each of the RHR suppression pool spray subsystems contains two motor driven pumps, two heat exchangers and a heat exchanger cross tie line, which are manually initiated and independently controlled. The two RHR suppression pool spray subsystems perform the suppression pool spray function by water the suppression pool through the RHR. heat exchangers and it to the suppression pool spray spargers. The spargers only atcommodate a small portion of the total RHR pump flow; the remaindEr of the flow to the suppression pool through the suppression pool cooling return line. Thus, both. suppression.pool cooling and suppression pool spray functions are performed when the Suppression. Pool Spray System is initiated. High Pressure Service Waier, through the tube side of the heat exchangers, exchanges heat with the pool water' ; and discharges this heat to the heat sink. Either RHR suppression pool spray subsystem is sufficient to condense the steam from small bypass leaks from the drywell to the suppression chamber airspace during*the postulated OBA. . Each suppression pool spray subsy'stem is equipped with a cross tie line, located downstream of each RHR pump discharge and of each exchanger inlet, which allows one pump to altgned to* supply both RHR heat exchangers {ri continued B 3.6-60 Revision No. 114 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES LCD APPUCABI LITY . ,_., PBAPS UN IT 2' RHR Suppression Pool Spray B 3.6.2.4 the same subsystem to remove additional heat from the suppression pool when only one RHR pump is available. The cross tie is normally closed, and is assumed by design basis analyses to be placed in service one hour following a design basis accident or transient when insufficient electric power is available to operate two RHR pumps in a subsystem. Reference 1 contains the results of used to predict primary containment pressure and temperature following large and small break loss of coolant .accidents. The intent of the analyses is to demonstrate that the pressure reduction capacity of the RHR Suppression Pool Spray System is *adequate to maintain the primary containment conditions within design limits. 'The time history for primary . containment pressure is calculated to demonstrate that the maximum pressure remains below the design limit. The RHR S8ppression Pool Spray System satisfies Criterion 3 of the NRC Policy Statement. In the event of a OBA, a m1 ni mum of one RHR suppression pool spray is required to mitigate potential bypass paths and maintain the primary tohtainment peak pressure the design 1). To ensure that. these requirements .are met, two RHR suppression pool spray be OPERABLE with power.from two related power supplies. Therefore, in the event of an accident; at least.one is OPERABLE assuming *.the worst. case single active fai lur.e. An RHR suppression pool spray is OPERABLE when one of the pumps, two heat exchangers. in the same subsystem the associated heat .*exchanger cross* tie line; two HPSW System pumps* capable of. cooling to the heat and *
• coritrols are OPERABLE. * -*I ' * ' ' . Management of gas: voids' is* to RHR Suppression Pool System OPERABILifY 'In MODES.I, 2, and-3,*a OBA could cause pressurj_zation of. primary cOn.tainrilent .. *In MODES 4 *and 5, t.he probability and .conseq*uences of these .events are reduced due to the pressure and temperature limitations in Therefore.,
• mai_nt,ai-hing *"RHR suppression pool spray subsystems OPERABLE* is* not re.gui red in. MODE _4 or 5. * * '*, (continued) .. B 3. 6-6L Revision 12_6 RHR Suppression Pool Spray B 3.6.2.4 BASES (continued) ACTIONS A.1 . PBAPS UN IT 2 With one RHR suppression pool spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In Condition, the remaining OPERABLE RHR suppression pool spray subsystem is adequate to perform the primary containment bypass leakage mitigation function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment bypass mitigation capability. The 7 day Completion Time was chosen in light of the redundant RHR suppression pool spray*capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period. With both RHR.suppression pool spray subsystems inoperible, at least one subsystem must be restored to OPERABLE status within B hours. In this Condition, there is a substantial loss of the primary containment bypass leakage mitigation functipn. ,The 8 Completion Time is based on this loss of function and is cons.i dered acceptable due to the low* ptobability of a DBA and alternative methods to remove heat from primary containment are available. If the inoperable RHR suppfession pool spray subsystem(s) cannot be restored to OPERABLE status within the associated Complet1on Time, the plant must be brought to *a MODE in which the.overall plant risk is>mini1T1ized ... To achieve this *status,.-t:he plant must be:Jfrought to at.-least MODE 3 within 12 hours ... Remaihi ng in the Appl i cabi 1 ity 'of the LCO is . acceptable* because the plant risk in MODE 3 iS similar. to or than the risk in MObE 4 (Ref. 2) and because the time sp*ent in MObE 3 to perform the necessary repairs to restore the to OPERABLE will be . . volu.ntar,Y_ entry into MODE 4 may be made as it is also an acceptable lowcrisk state*. The allowed Completion Time is reasonable, based on operating experience, to* reach the requi*red plant conditions *from fUll power. conditions in *an orderly manner and without_* chal l ehgi ng plant system's. (continued) Revision No. 66 I I I 1* I I BASES (continued) SURVEILLANCE REQUIREMENTS SR 3.6.2.4.1 RHR Suppression Pool Spray B 3.6.2.4 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR suppression pool spray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct positi6n prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time in the accident analysis. This is acceptable since the RHR suppression pool cooling mode is manually initiated. This SR does not require any or manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Frequency Control Program. SR 3.6.2.4.2 This is performed to veri.fy that the spray nozzles are n6t bbstructed and that flow will be provided when required. The Surveillance Frequency is controlled under the s.urvei 11 ance Frequency Control Program. SR 3.6.2.4.3 . Deleted . * (continued)
• PBAPS. UN IT 2 B 3.6-63 Revision No. 130*

BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UNIT **2 SR 3.6.2.4.4 RHR Suppression Pool Spray B 3.6.2.4 RHR Suppression Pool Spray System p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR Suppression Pool Spray Subsystems and may also prevent water hammer and pump cavitation.

• Selection of RHR Suppression Pool Spray System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentati*on drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configurationi such as stand-by versus operating conditions. The RHR Suppression Pool Spray System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible
• locatiohs exceeds an. criteria for volume the suction or discharge of a pump), the Surveillance is not. met. If the gas is eliminated or brought within* the acceptance during of the * . 11 Surveillance, the SR is met and past OPERABILITY is evaluated under the Corrective Action Program. If it is determined by s0bsequent evaluation that the RHR Suppression Pool Spray System is not rendered inoperable by the accumulated gas (i.e., the is filled water), the surveil*lance may be declated met. . Accumulated gas should be eliminated or brought within the acceptance criteria RHR Suppression Pool Spray System l ocaU ons susceptible to gas accumulation ate *monitored and; if gas is found, volume is compared to the acceptance criteria for the location. Susceptible lotations in the same system flow path which are subject tci the same gas intrusion mechanisms may be verified by monitoring a representative subset of *
• susceptible locations. Monitoring may not be practical lbcations that are inaccessible due to radio]ogital or environmental tonditicins, the plant or personnel safety. For. these locations alternative methods ciperating remote monitoring) may be used-(continued) B 3.6-63a Revision No. 127 -

BASES SURVEILLANCE REQUIREMENTS* REFERENCES

• PBAPS UN IT 2 SR 3.6.2.4.4 (continued)* RHR Suppression Pool Spray B 3.6.2.4 to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval. The SR is modified by a Note. The Note recognizes that the scope of the surveillance is limited to the RHR system components. The HPSW system components have been determined to not be required to be in the scope of this* surveillance due to operating experience and the design of the system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation. 1. UFSAR, Sections 5.2 and 14.6.3. 2. NEDC-32988-A, Revision 2, Technical Justification to Support Modification to Selected Required End States for BWR December 2002. B 3.6-63b Revision No. 126 I RHR Drywell Spray B 3.6.2.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.5 Residual Heat Removal CRHR) Drywell Spray BASES BACKGROUND PBAPS UN IT 2 Drywell Spray is a mode of the RHR system which may be initiated under post accident conditions to reduce the temperature and pressure of the primary containment atmosphere. The Drywell Spray function is credited in design basis analyses to limit peak drywell temperature following a steam line break inside of the Drywell and may be used to mitigate other loss of coolant accidents inside of the Drywel l. This function is provided by two redundant Drywel l Spray subsystems. The of this LCD is to ensure that both subsystems are OPERABLE in applicable MODES. Each of the RHR drywell spray subsystems contains two motor driven pumps, two heat exchangers and a heat exchanger tie line, which are manually initiated and independently controlled. The two RHR drywell spray subsystems perform the drywell spray function by circulating water from the suppression pool through the RHR exchangers and discharging the cooled suppression pool water into the drywell space the drywell spray sparger and spray nozzles. The spray then effects a temperature and pressure reduction through the tombined effects of evaporative and convective cooling, depending on the drywell atmosphere. If the. atmosphere is superheated, a evaporative cooling process will ensue. If the environment in the .drywell is saturated; 'temperature and pressure wi 11 be reduced vi a a cooling process. Each drywell spray sparger line is by one
• indepehdent RHR drywell spray subsystem. If required, a small portion* of* the spray fl o.w ca*n be di rec.ted to the suppresston pool spray spa rger and spray nozzles. High . Pressure Servi.ce Water, circulating through the tube side of the heat exchangers;. exchanges heat with. the suppression pool water *on.the shell side of,_the heat exchangers and discharges this heat to the .exte.rnal he.at sink.
• Each drywelT subsystem ::*is. equipped with. a RHR heat* exchanger cross-tie line,* located downstream of each RHR pump discharge arid of each exchanger inlet, which allows pump to be aligned to supply both RHR heat:* exchangers in the same subs,Ystem to* provide additional* containment heat remoVcil. capabi.lity when. only *6ne RHR pump is civai la bl e:: RHR heat exchanger .cross*-ti e is riormal ly
• and is in the basis ftnalyses to be placedjn service one hour following a desjgn basis accident or. transient .when i nsuffi ci ent el ettri c power is available to RHR in a subsystem. (continued) . B 3. 6-63c Revision N.o, 126 I BASES (£ontinued) APPLICABLE SAFETY ANALYSES LCD APPLICABILITY PBAPS. UNIT 2 RHR Drywell Spray B 3.6.2.5 Reference 2 contains the results of analyses used to *predict primary containment pressure and response following a spectrum of small steam line sizes. Steam line breaks are the most limiting events for drywell temperature since steam has higher energy content than liquid. These analyses, with primary focus on the drywell temperature response, take credit for containment sprays and structural heat sinks in the drywell and the suppression pool airspace. These analyses demonstrate that, with credit for containment spray (drywell and pool), drywell temperature is maintained within limits for Environmental Qualification (EQ) of equipment located in the drywell *for the analyzed spectrum* of small steam line breaks. The RHR Drywell Spray satisfies Criterion 3 of the NRC Policy Statement. In event of a small steam line break in the a minimum of one RHR drywell spray subsystem is credited in the design analyses to mitigate the rise in drywell temperature and caused by the steam line break, and to maintain the primary containment peak temperature and pressure below the design (Ref. 2). To ensure that these requirements are met, two RHR drywell spray subsystems (one in each loop) must be OPERABLE with power from two safety related independent power supplies. Therefore, in the event of an acctdent, at least one subsystem OPERABLE assuming the worst ca.s_e single active failure. An *RHR. drywell spray subsystem is OPERABLE when one of pumps,* .two heat exchangers in same subsystem, the associated RHR heat.exchanger Jine, two HPSW pumps capable of cooling to the two a s s o c i a t e d p i p i n g , v a l v e s , i n st r um en t a t i on., a n d c on t r o l s a re OPERABLE. Management *of gas voids is important to RHR Drywel l Spray System OPERABILITY. In MODES 1, 2, and 3, a steam line break in the drywell could cause a rise in primary containment temperature and pressure. In MODES 4 and 5, the probability and consequences of steam line breaks are reduced due to the pressµre and limitatioris in these MODES. Therefore, maintaining RHR drywell spray subsystems
• OPERABLE required in MODE 4 or 5. .B 3.6*-63d (continued) Rev1sion No. 126 I RHR Drywell Spray B 3.6.2.5 BASES (continued) ACTIONS PBAPS UN IT 2 With one RHR drywell spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE RHR drywell spray subsystem is to mitigate the effects of a steam line break in the drywell. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced ability to mitigate the temperature rise associated with a stea.m line break in the drywell, for which drywell sprays are credited. The 7 day Completion Time was chosen in light of the RHR drywell spray capabilities afforded by the OPERABLE subsystem and the low probability of a steam line break in the occurring during this period. With both RHR drywell spray subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours. In this Condition, there is a substantial loss of the_ ability to mitigate the temperature rise associated with a steam line break in the drywell, for wh_ich drywell sprays. are credited. hour. Completion Time is on this lOss of function and is acceptable due to the low probability 6f a in ihe and alternative methods to .remove heat from primary containment are avail able. C.1 and C.2 *-If .. the. inoperable RHR drywell spray subsystem(s) cannot be restored to OPERABLE status within the associated Compietion Time, the plant be brought to-a MODE in which the [CO does not apply. To achieve status, pl ant must be brought to at least MODE 3 within 12 hOurs
• and MODE 4 within 36 hours. The allowed Completion Tim.es reasonable, on operating to reach the required pl ant conditi ans from full power conditi ans in an orderly manner and without challenging pl ant * * * * * * . ( c 0 n t i nu e d ) . . B 3.6-63e Revision No. 126 I BASES (continued) SURVEILLANCE REQUIREMENTS 2 SR 3.6.2.5.1 RHR Drywell Spray B 3.6.2.5 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR drywell spray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident pdsition provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR drywell mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.2.5.2 This Surveillance is performed to verify that the spray nozzles are not obstructed and that flow will be provided when required. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.2.5.3 Deleted (continued) B 3.6-63f Revision No. 130 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 2 SR 3.6.2.5.4 RHR Drywell Spray B 3.6.2.5 RHR Drywell Spray System p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR Drywell Spray systems and may also prevent water hammer and pump cavitation. Selection of RHR Drywell Spray System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The desigh review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwis& cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. The RHR Drywell Spray System is when it is sufficiently filled water. Acceptance criteria are established for the volume.of accumulated gas at susceptible locations. If gas is discovered that exceeds . the .acceptance criteria for the susceptible location (or the vo.l ume of accumulated gas at* one or rricire susceptible locations exceeds ah acceptance criteria for gas volume at the suction or discharge of a pump), the Survei 11 ance is not met. If*the accumulated gas is eliminated or brought within criteria limits during performance of the Surveillance, the SR is metand past system OPERABILITY is under the Corrective Program. If it is determined by subsequent that the RHR Drywell .Sptay is by the accumulated gas the sjstem is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas**** should be eliminated or brought the acceptance lfmits; * * .RHR Drywell. Spray.System locations susceptible to gas
• accumulation *a re mon.i to red and, .'.i.f gas is found*; the gas volume is compared to the acceptance for the . location:.*. Susceptible locations in the same sys tern *fl ow* . path which are subject to the same gas intrusion mechanisms may be verjfi ed by mohitori ng a r'epresentati ve subset of suscepti*ble* locations.
• Moni,toring may not be practical for *1bc;ations .. that are inaccessi_bl-e due to radiological or** environmental the plant or . personnel safety. For these alternative methods (e.g., .operating parameters, remote monitorjhg)* may be used t6'monitor*the location, Monitoring is not .. (continued) B 3.6-63g Revision No; 127 ,.

BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 SR 3.6.2.5.4 (continued) RHR Dryw_el l Spray B 3.6.2.5 required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoririg the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval. The SR is modified by a Note. The Note recognizes that the scope of the survei.ll ance *is limited to the RHR system components. The HPSW system components have been determined to not be required to be in the scope of this surveillance. due to operating experience and the design of the system. The Surveillance Frequency is controlled the Surveillance Frequency Control Program. The Frequency may vary by location susceptible to gas accumulation. 1. UFSAR, Sections and 14.6.3. 2. *NEDC-33566P -"Safety Analysis Report for Exelon Peach Bottom. Station Units '2 and 3, Constant Pressure Power *Uprate" Revision 0. * -\. -.* . -* .. *B-3.6-63h--.. Revision No. 126 . I

• B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Deleted CAD System B 3.6.3.1 THE INFORMATION FROM THIS TECHNiCAL SPECIFICATIONS BASES SECTION HAS BEEN DELETED. TECHNICAL SPECIFICATIONS BASES PAGES B 3.6-65 THROUGH B 3.6-69 HAVE BEEN INTENTIONALLY 6MITTED. PBAPS UN IT 2 B.3.6-64 Rev-ision No. *80 Primary Containment Oxygen Concentration B 3.6.3.2 B 3.6 CONTAINMENT SYSTEMS B Primary Containment Oxygen Concentration BASES BACKGROUND AP PU CABLE SAFETY ANALYSES PBAPS UN IT 2 All nuclear reactors must be designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis. The primary method to control hydrogen is to inert the primary containment. With the primary containment inert, 'that is, oxygen concentratjon < 4.0 volume percent (v/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration. The capability to inert the primary containment and maintain oxygen < 4.0 v/o works together with the Containment Atmospheric Dilution (CAD) System to provide redundant and diverse methods to mitigate events that produce hydrogen. For example, an event that rapidly generates hydrogen from zirconium metal water reaction will result in excessive hydrogen in primary containment, but oxygen concentration will remain< 4.0 v/o and no combustion can occur. Long term generation of both hydrogen and oxygen from radiolytic decomposition of water may eventually result in a combustible .mixture in primary containment, except that the CAD System dilutes and removes hydrogen and oxygen gases faster than they can be produced from radiolysis and again no combustion can occur. This LCO ensures that oxygen concentration does not exceed 4.0 v/o during operation in the applicable conditions. The Reference 1 calculations assume that the primary cohtainment is inerted when Design Basis Accident loss of coolant accident occurs. -Thus, the hydrogen assumed to be released to the primary containment as a result of metal water reaction in the reactor core will not produce combustible gas mixtures in the primary containment. Oxygen, which is subsequently generated by radiolytic decomposition of water, is diluted and removed by the CAD System mori rapidly than it is produced. Primary containment concentration satisfies Criterion 2 of the NRC Policy Statement. (continued) B 3.6-70 Revision No. 80 I BASES (continued) Primary Containment Oxygen Concentration B 3.6.3.2 LCO The primary containment oxygen concentration is maint.ained < 4.0 v/o to ensure that an event that produces any amount of hydrogen does not result in a combustible mixture inside primary containment. APPLICABILITY ACTIONS . -* .... PBAPS UNIT 2 The primary containment oxygen concentration must be within the specified limit when primary containment is inerted, except as allowed by the relaxations during startup and shutdown addressed below. The primary containment must be inert in MODE I, since this is the condition with the highest probability of an event that could produce lnerting the primary containment is an operational problem because it prevents containment access without an appropriate breathing apparatus. Therefore, the primary containment is inerted as late as possible in the plant startup and de-inerted as soon as possible in the plant shutdown. As long as reactor power is < 15% RTP, the potential for an event that generates significant hydrogen is low and the primary containment need not be inert. *Furtherniore, the probability of an event that generates hydrogen occurring within the first 24 hours of a startup, or within the last 24 hours before a shutdown, is low enough that these nwindows,n when the primary_ containment is not 1nerted,.are also justified. The 24 hour time period is a reasonable amount of time to allow plant personnel to perform inerting or de-dnerting. ----. . . ' If oxygen concentration_ is i!: 4.0 v/o at -ariy time while .. *opera-ting in MOOE I, with the exceptfon of the relaxations a 11 owed during startup and shutdown, oxygen concentration
• must be restored to < 4.0 v/o within 24 hours. The 24 hour _ Completi<>n Time* is allowed when oxygen concentration is >-4.0 v/o because*of the *av.ail ability of other hydrogen mitigating -systems (e.-g., the CAD. and the low probability and.long duration of an event that would amounts of hydrogen occurring during this period. * (continued) B 3.6-71 Revision No. 0 BASES Primary Containment Oxygen Concentration B 3.6.3.2 ACTIONS Ll (continued) *SURVEILLANCE REQUIREMENTS REFERENCES PEiAPs* UNIT 2 If oxygen concentration cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE iri which the LCD does not apply. To achieve this status, power must be reduced 15% RTP within 8 hours. The 8 hour Completion Time is reasonable, based on operating experience, to reduce reactor power from full. power conditions in an orderly manner and without challenging plant systems. SR 3.6.3.2.1 The primary (drywell and suppression chamber) must be determined to be inert by verifying that oxygen concentration is< 4.0 v/o. The Surveillance Frequency is under the Surveillance Frequency Control *Program. 1. UFSAR, Section **.-... Revision No. 86

'.'* . 1* 1'.* . : , ... Secondary Containment B 3.6.4.1 B 3.6 CONTAINMENT SYSTEMS. B 3.6.4.1 _Containment .* . , .BASES.* BACK(JROUND --' ' . APPLICABLE ** SAFETY ANALYSES * .. -.* PBAPS. UNIT. 2 .. . .

• t*" . . The of the secondary containment to conta1n and hold.up fission that may leak from containm.ent following a Design .Basis Accident (OBA).* In conjunctioh with operation of the Gas Tteatment (SGT) System and closure of certain valves whose 1 ines
• penetr;:ite the secondary containment, the secondary .. containment is designed.* to* reduce the activity 1 evel of the ** *fission products prior to. release to the environment and ta isolate and contain fission products that .are released
• during certain operations that take place inside primary containment, when primary is not required to be OPERABLE, or that. take pl ace outside.* primary containment. is a that completely en.closes the pri niary containment and those components that be to contain primary system fluid. forms a control. volume that serves t6 hold up and* di lute the f_i ssi on pr'oducts. It is possible for the pressµ re in the control volume to *r; s.e relative to the environmental to pump motor heat.
• Toad additions)._ To prevent ground level exfi1tration while all qwi ng the secondary coritai nment to be designed as a converit1 onal structure,. the secondary contai*nment *requires support 'systems to maintain the bontrol 1 ess than 'the .external pressure. Requirements for these * . syst.eins are specified separately in LCO 3. 6 A. 2,. "Secondary Isolation Valves and LCd 3:6.4.3, * "Standby Gas Treatinerit System*." * .There.are two principal accidents for which credit is .taken for secondary cohtai nment OPERABILITY .. These are a 1 oss of * . coolant. accident (LOCA) (Ref. 1) and a fuel handling accident . inside secondary .contajnment .(Ref. 2) *involving RECENTLY IRRADIATED FUEL. The secondary containment performs no active in to each.of these limiting events; (continued} *. .. * ..
• B **3.6-73*. .* . Revision No. 75 .** *:.'::*. . <* '*; .. , ... :':-. ' '* : *. .:-.

I I . . * ... :< *. ,* ;',*-.. :, . BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABILITY . ACTIONS .. *-.... ". -: . ' . ; *. . . . PBAPS .. UNIT* 2. Secondary Containment B 3.6.4.1 however, its leak tightness is required to ensure that fission products entrapped within the ,econdary containment structure will be treated by the SGT System prior to discharge to the environment.

• Secondary containment satisfies Criterion 3 of the NRC Policy Statement. An OPERABLE secondary containment provides a control volume into *hich fission products that leak from *primary containment, or are released from the'reactor coolant pressure boundary components located in secondary containment, can be processed prior tb release to the . environment. For the secondary containment to be considered OPERABLE, it must have adequate l .eak tightness to ensure that the required vacuum can be established and maintained. *In MODES 1, 2, ahd 3, a LOCA could lead to a product rel ease to primary containment that* 1 ea ks to secondary containment. Therefore, secondary containment OPERABILITY is requited during the same operating conditions that require primary containment OPERABILITY. In MODES A and *s,theprobability and consequences of _the LOCA are* reduced due to. the pressure.and temperature** * .. 1 imi tati ans* i ri. t.hese MODES .. Therefore, mai ntai ni ng * . *secondary containment OPERABLE is not required iil MODE 4_or 5, except for other situations for which significant .. * . rel eases of radi cacti ve material can be postulated' such as . during operations with a potential for draining thereact.or *.vessel (OPDRVs), or: during movement of RECENTLY IRRADIATED . FUEL CISSembl i es in. the secondary contai nm:ent. However' ... . . outside ground level hatches (hatches H15 .through H19. -and Torus room ac.cess hatch H33} may not be op¢ned during . movement of irradiated *fuel. This w11:1 maintain CR oases.*
• acceptable .. * *.* .. .,--. . . . .. .* .. *.
• containment is inoperable, it' must be to OPERABLE status wi thi:ri 4 hours .. The 4 hour Completion .Time provides a period of time to corre.ct .the problem that* is commenjurate with the importance* of me1intaining seconde1ry
• c;ontai nment duri hg MODES t, 2; and. 3. This ti me period a)so ensures that the* probabi 1 i ty of an accident (requiring * * ... secondary containment OPERABILITY) occurr1 ng during periods: .*
• wtwre secondary contai.my1ent is inoperable is minimal. nued) **.:: .. :. *B 3.6-74 *Revision' No. 7S **. .. -:* *".: . . '.; **._.* .. .:*

I BASES ACTIONS (continued) *.,'. **", PBAPS UNIT 2 Secondary Containment B 3.6.4.1

• lf secondary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the overall pl ant risk is *.minimized. To achieve this status, the pl ant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant. risk in MODE 3 is similar to or lower than the* risk in MODE 4 (Ref. 3) and because the'time spent in MODE 3 to perform the necessary*repairs to restore the system to OPERABLE status wi 11 *.be short. However, voluntary entry into MODE 4 may be made as it. is al so an accept ab 1 e 1 ow-risk state. The allowed Completion Time is reasonable,* based on operating *experience, to reach the required plant conditions from full *power conditions in an orderly manner and without challenging plant systems .. C.1, and C.2 Movement of RECENTLY IRRADIATED FUEL assemblies in the secondary containment and OPDRVs can be postulated to cause fission product release to the secondary containment. In such cases, the secondary is the only barrier to release -0f fission products to the environment. Therefore, movement of RECENTLY IRRADIATED FUEL assemblies must be immediately suspended if the secondary containment is inoperable.* Suspension of t.hese activities shall not preclude completing an action a component to a safe position'. :Also, be immediately initiated to suspend OPDRVs. to minimize the probabi 1 i ty of a vesse 1 draindown and subsequent potential for fission product rel ease. Acti ans .must continue until OPDRVs are suspended. Required Action C.1 has been modified by a Note stating that LCO 3. 0 . 3 is not appl .i ca.b 1 e, s i nee the movement . of RECENTLY IRRADIATED FUEL can only be performed in MODES 4 and 5. (continued) . *.* B 3.6..:75 Revis.ion No. 75 *
• BASES (continued) SURVEILLANCE REQUIREMENTS . PBAPS UNIT. 2 SR 3.6.4.1.1 Secondary Containment B 3.6.4.1 Verifying that secondary containment equipment hatches are closed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the deiired negative pressure does not occur and provides adequate assurance that exfiltration from the secondary containment will not occur. In this application, the term "sealed" has no connotation of leak tightness. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.4'.l.2 Verifying that one se.condary containment access door in each access opening is closed provides adequate assurance that exfiltration from the secondary containment will not occur. An access:opening contains at least one inner*and one outer door.
• In some cases, secondary containment access openings are shared such that there are multiple inner or outer doors. The intent is to not breach the secondary containment, which is achieved by maintaining the* inner or outer portion of the barrier closed. SR 3.6.4.1.2 provides an exception to allow brief, unintentional, simultaneous opening of both an inner and outer secondary containment access dbor. The Surveillance Frequency {s controlled under the Surveil1ance Frequertcy Program. SR 3.6.4.l.j and SR 3.6.4.1.4 SGT System exhausts the.secondary containment atmosphere to the environment through appropriate treatment equipment. Each SGT subsystem is tjesigned to draw down pressure in the secondarj containment 0.25 inches of vacuum water gauge in 180 seconds and mai.ntain pressure in the secondary containment at 0:25 inch:es *of vacuum water gauge *for 1 hour at a flow *rate 10, 500 cfin. To ensure that al 1 fi s*si on products released tci the secondary containment .are treated, SR and SR 3.6,4.1,4 verify that a:pressure in the* secondary containment that is* 1 ess than the lowest postulated , press.ure external* to the seconc(ary containment boundary can be established and maintained. When the SGT System is operating as designed,* the e_stablishmerit and maintenance* of secondary contatnment_pressure cannot be accomplished if. the contalnment boundary is nqt-intact .. Establishment of this pressure is confirmed by SR which demonstrates that the'secondary containment can be drawn down 0.25 inches. of vacuum water gauge in 180 *
• continued . B 3.6-76 Revisfon No.120 '

BASES SURVEILLANCE REQUIREMENTS . REFERENCES PBAPS UNIT 2 .. -... Secondary Containment B 3.6.4.1 SR 3.6.4.1.3 and SR 3.6.4.1.4 (continued) seconds using one SGT subsystem. SR demonstrates that the pressure in the secondary containment can be maintained 0.25 inches of vacuum water gauge for 1 hour using one SGT subsystem at a flow 10,500 cfm. The 1 hour test period allows secondary containment to be in thermal equilibrium at steady state conditions.* The primary purp6se of these SRs is to ensure secondary containment integrity. The secondary purpose of these SRs is to ensure that the SGT subsystem being tested functions as designed. There is a Separate LCO with Surveillance

• which serves the primary of ensuring OPERABLITY of the SGT System. The i noperabil ity of a SGT subsystem does not necessarily constitute a failure of these to the secondary containment .OPERABILITY. The Surveillance Frequency is tontrolled under the Surveillance Frequency Control Program . 1. UFSAR, Section 14.6.3. 2. UFSAR, Section 14.6.4. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. Revision No. 97 i.: I I ! *;' . **. . -.. ' .. ,:;*. " ... -* ,_ .* *. :. SCI Vs B 3.6.4.2 B 3.6 .CONTAINMENT SYSTEMS B 3.6.4.2 Secondary Coritainment Isolation Valves (SCIVs) *BASES BACKGROUND . ' . APPLICABLE** .. SAFETY.ANALYSES ** .... . . ,*:. . .. ,. PBAPs* UN1T*2 .. * .. ... The function of the SCIVs, in combination with other accident mitigation sy$tems, is to control fission product release during and following postulated Design Basis
• Accidents (DBAs) (Refs. 1 and 2). Secondary containment isolation within the time. limits specified for those
• i sol ati on valves designed to close automatically ensures . that fission products that leak from primary containment* following a OBA, or that are released during certain operations when pr1mary contairiment is noi required t6 be OPERABLE or take place outside primary containment, are maintained within the secondary The OPERABILITY requirements for SCIVs help ensure that an adequate secondary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. These isolattrin devices consi$t of either
• passive devices or (automatic) devices. Manual . valves, de-activated automatic valves secured in their .. closed position (including check valves wi:th flow through the valve and flange$ are considered devices. . * . .*.. . *.. . ** .. ** * ... * . *.* .. * . . . : . . . Automatic SCIVs close oh a secondary containment isolati9n signal to establish a boundary for untreated radioactive material within se.condary containment following a OBA or * *. other * * *
• Other penetrati ans .are isolated by the use of Valves,.1 n the . closed position or blindflahges . . *. . . The SC.IVs must.be OPERABLE to ensure tl]esecondary *containment barrier to fiSsi on product rel eases is . . . .. . establ .i shed. The Pri hc.i pal. accidents for .which the secondar.Y'.> * . ' con.tai riment boundary iS required are a: 1 oss' of cool ant ... accident (Ref. 1) and a0:fuel handling accident* i nsi.de .* .* secondary.containment {Ref. 2) involving RECENTLY IRRADIATED.* . . FUEL The secondary containment performs rio. active function .*. in .respor1se to. e1 ther of these 1 i mi ting.* events, . but the*. * .*(continued} .. *** **.::, .. **, .-***. B 3.6-78 **Revision No. 75. .*.:: *.
• 1 I I r BASES APPLICABLE SAFETY ANALYSES (contin[.!ed) LCO APPLICABILITY . .
• PBAPS *uNIT 2 . SC IVs . B 3.6.4.2 boundary by SCIVs is required to ensure that leakage frpm the primary containment is processed by the Standby Gas Treatinent (SGT) System before being released to the environment; . Mai ntai ni ng SC IVs OPERABLE with i sd11ati on ti mes within .limits ensures that fission products.will remain trapped inside containment so that they can be treated by the SGT System prior to discharge to the environment. SC IVs satisfy Criterion 3 of the NRC Policy Statement. SCIVs form a part of the containment boundaty. The *SCIV safety function is related to control of offsite radiation releases* resulting from DBAs. The power operated automatic isolation valves are considered OPERABLE when their isolation times are within limits and the valves actuate on an automatic isolation signal. The .. valves covered by this LCD, along with their associated times, are listed 2. The normally closed isolation valves or blind flanges are considered OPERABLE wh.en manual valves are closed or open in with controls, * . SCIVs are and secured-in cl-0sed position, and blind flanges are in place. These passive or dev1ces. are listed in Reference 2. In MODES1, 2, and 3, a OBA could lead to a fission product release to: the primary containment that leaks to the secondary conta.i nment. Therefore, the OPERABILITY* of SC IVs is required.
• In MODES 4 and 5, the probability and consequences of these events are reduced due to pressure and temperature limitations in these MODES. Therefore, SCIVs OPERAS.LE is not required in MODE 4 or 5, except for other *situations under which radioactive releases can be postulated, such as during operations with a potential for draining the react6r vessel (OPDRVs) or during movement *of RECENTLY IRRADIATED FUEL assemblies in the secondary containment. SCIVs are only required to be OPERABLE during OPDRVs or hahdl i ng RECENTLY IRRADIATED FUEL. Moving irradiated fuel assemblies in the secondaty containment may al so occur in MODES 1*, 2, and 3. (continued) B*3.6-7!3 Revision No. 75 SCI Vs B 3.6.4.2 BASES (tontinued) ACTIONS The ACTIONS are modified by three Notes. The first Note allows penetration flow paths to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator, who is in continuous communication with the control room, at*the controls of the isolation device. In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated. PBAPS UNIT 2 The second Note provides clarification that for the purpose of this LCO separate Condition entry is allowed for each penetration flow path. This is acceptable, since the *Required Actions for each Condition provide appropriate compensatory actions for each inoperable SCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent Condition entry and application of associated Required Actions. The third Note ensures appropriate remedial actions are taken, if necessary, if the affected system.(s) are rendered i noperab 1 e by an i noperab 1 e SC IV.
• A.I and A.2 In the event .that there are o*ne or more penetration flow paths with one SCIV the affected perietration
• flow path(s) must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. I sol at ion barriers that meet thi.s. criterion* are a closed and automatiC SCIV, a closed manual valve, and a bl ind flange.
• for penetrations isolated in* accordance with .* Required Action 1, the device used to isolate the . .
• penetration should be. the *closest avail able device to secondary contai.nment. The Required Action must be . completed within the 8 hour Completion *Time *. *The specified time period is reasonal>le considering the time required to **iSolate the penetratfon, and probability of a OBA, which requires *the SClVs to close, occurring during this short time is very low.
• for affected penetrations that have been isolated in with Required Action A.I, the affected . . *. penetration must. be verified to be isolated on a periodic basis *... This is necessary t() that secondary * (continued) -.,
• B 3.6-80 *. .* Revision
• O BASES ACTIONS PBAPS UNIT 2.* A.1 and A.2 (continued) SCI Vs B 3.6.4.2 containment penetrations required to be isolated following an accident, but no longer capable of being automatically isolated, will be in the isolation position should an event occur.* The Completion Time of once per 31 days is appropriate because the isolation devices are operated under administrative controls and the probability of their misalignment is low. This Required Action does not require testing or device manipulation. Rather, it involves verification that the affected penetration remains isolated. Required Action A.2 is modified .by two Notes. Note 1 applies to devices located in high radiation areas* and allows them to be verified closed by of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment, once they have been to be the proper position, is *1 ow. With two SCIVs in one or more penetration flow paths i nope ral5 le, the affected penetration fl ow path must be. isolated within 4 hoGrs. The method of isolation must include the use of at *1ea*st_on*e isolation barrier that canti6t affected by a single active failure. I.solation' barriers that meet this criterion are a closed and *.de-activated automaticvalve.,.a closed manual valve, and a . blind fTange .. The 4* hour Completion Time is reasonable* considering the time reCJuired to isolate.the penetration and the of a OBA, ch. requires* SCIVs to close, occurring duri.ng'this short time, is very low. The Conditi9n been modified by a stating that C6ndition on1y applicaijle to penetratibn paths with two isolation valves. This clarifies that only .Condition A is if orie SCIV jnoperable in eaCh of two (continued) B Revision Nq. 57

.. _* ... '-' .* *-. .. :.* ... :** . * .: ... -,.* ... .. ";' *-... *,, o-** I BASES ACTIONS *(continued) I.*.* '.!: .. SURVEI L_µNCE *. REQUIREMENTS . .... :' .. ' . ; * .. PB{\PS'UNIT*2 .*.,,_'_: * ... , SCI Vs B 3.6.4.2 C.1 and C.2 If any Required Action and associated Time canriot be the plant must be.brought to *a MODE in Which the LCO dries not apply. To achieve this status, the plant must .be brought to at least within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. *.If any Required Action and associated Completion Time are not met, the must' be placed in a condition in which .the LCO.does not apply. If applicable, CORE ALTERATIONS and the movement of RECENTLY* IRRADIATED FUEL assemblies in the ** secondary containment must be immediately suspended. * *Suspension of this activity shall not preclude completi6n of. movement of a component to a safe position. Also, if . * . appl i cab 1 e' actions must be immediate 1 y initiated to suspend . OPDRVs .in order to .minimize the probability of a vessel' *

• draindown and the subsequent potential for fission product rel ease.
• Actions must continue uriti 1 OPDRVs are suspenc:led,. Required D:1 has 'been modified by a Note stating that** LCO 3:o*.3 is not applicable, since .th.e movement of .RECENTLY* . IRRADIATED FUEL can only *.be performed in_ MODES 4 and S .* . *; .. This SR verifies t_hat each secondary ccmtainment manual.*.** .** .* iscfl ati on *valve and blind flange that :j s* not l o'cked' sealed' ..o_r otherwise secured and_ is required to be closed during* accident conditions is closed.* Th(;} SR helps to ensure tt)at *.*post accident leakage Of radi cacti Ve* fl u;.ds **Or gases O.Lits,i de, .'o.f the.secondary containment bci.urn;Jary withi'n design': , .. limits. This SR does not re.qui re any testing or valve* .. manipulation. Rather, if involves verification that those. SCIVs in secondary' containment that are capable of being . . mi sposi ti oned are in the correct position. * * * * (conti .\ : .. *, .**.* . *-* ...... " . 8 .. 3 .6-82 ... .-: .. Revision No. 75 ****,* ..

BASES SURVEILLANCE PBAPS UNIT 2 SR 3.6.4.2.1 (continued) SCI Vs B 3.6.4.2 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing. Two Notes have been added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of of these SCIVs, once they have been verified to be in the proper position, is low. A second Note has been included to clarify that SCIVs that are open under administrative* controls are not required to meet the SR during the time the SCIVs are open. SR 3.6.4.2.2 Verifying that the isolation time of each power operated automatic SCIV is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCIV. wil1 isolate in a time period less than or equal to that assumed in the safety analyses. The Frequency of this SR is in accordance with the Inservice Testing Program. SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a secondary containment isolation signal is required to prevent leakage of radioactive from secondary containment following a OBA or other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a secondary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. (continued) B 3.6-83 Revision No. 86 BASES (continued) REFERENCES PBAPS. UNIT 2 1. UFSAR, Section 14.9.2. 2. Technical Requirements Manual. --,: B 3.6-84 SCI Vs B 3.6.4.2 Revision No. 86 SGT System B 3.6.4.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.3 Standby Gas Treatment {SGT) System BASES BACKGROUND --PBAPS--UNIT 2 -The SGT System is required by UFSAR design criteria {Ref. 1). The function of the SGT System is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment. A single SGT System is common to both Unit 2 and Unit 3 and consists of two fully redundant subsystems, each with its own.set of ductwork, dampers, valves, charcoal filter train, and controls. Both SGT subsystems share a common inlet plenum. This inlet plenum is connected to the refueling floor* ventilation exhaust duct for each Unit and to the suppression chamber and drywell of each Unit. Both SGT subsystems exhaust to the plant offgas stack through a common exhaust duct served by three 100% capacity system fans. -SGT System fans OAV020 and OBV020 automatically start on Unit 2 secondary containment isolation signals. SGT System fans OCV020 and OBV020 automatically start on Unit 3 secondary containment isolation signals. -. . . . . Each _charcoal train coniists of listed in order of the direction of the air flow): a. -A demister or moisture separator; b. c. An electric heater; A prefilter; A high eff-i'ciency_ air {HEPA) filter; e. It charcoal adsorber; and 'f. -_ A -second HEPA f i 1 ter. The SGT,-Systemis sized such-that eachl00% capacity fan will "provide a flow rate of 10,500 cfm *at 20 inches water gauge static pressure to support the control of fission ... _ product releases. The SGT System *is_ designed to restore and mainta*in secondary containment at a negative pressure of --0.25 inches water gauge* relative to the following -. . -. --B Revision No. 0 BASES BACKGROUND (contin!,Jed) APPLICABLE SAFETY ANALYSES LCO . PBAPS 'UN IT . 2 SGT System* B 3.6.4.3 the receipt of a secondary containment isolation signal.* Maintaining this negative pressure is based upon the existence of calm wind conditions (up to Smph), a maximum SGT System flow rate of 10,500 cfm, outside air temperature of gs*F and a temperature of 1S0°F for air entering the SGT System from inside secondary containment.

• The demister is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the ai rstream to less than 70% (Ref'. 2). The prefil ter removes large particulate matter, while the HEPA filter removes fine particulate matter and protects the charcoal from fouling. The charcoal adsorber removes gaseous elemental iodine and organic iodides, and the final HEPA filter collects any carbon fines exhausted from the charcoal adsorber. The SGT System automatically starts and operates in response to actuation signals indicative of conditions or an accident that could require operation of the system. Following initiation, two charcoal filter train fans (OAV020 and OBV020). start. Upon verification that both subsystems are operating, the redundant subsystem is normally shut down. The design basis for the SGT System is to mitigate the consequences of a loss of coolant accident and fuel handling accidents (Ref *. 2). For all events analyzed, the SGT System is shown to be automatically initiated to reduce, via filtration and adsorption, the radioactive material released to the environment. * * *
• The .SGT System satisfies Criterion 3 of the NRC Pol icy .
• Statement. Following a DBA, a minimum of one SGT subsystem is required to maintain the secondary containment at a negative pressure with respect to the environment and to process gaseous releases. Meeting the LCO requirements for two OPERABLE subsystems ensures operation of at least one SGT subsystem in the event of a single active failure. (continued). B 3.6-86 Revision a*

.. ; *." *.*** .... -' .. *.** BASES LCO * (continued)* APPLICABILITY ' .. ;* ACTloNS ... . ".'* *. .*,.', ' PBAPS UNIT. 2** .. SGT System . B 3 .. 3 For* Unit 2, one SGT subsystem is OPERABLE when one charcoal *filter train, one fan (OAV020) and associated ductwork,

• dampers, valves, and controls are OPERABLE.* The second SGT subsystem is OPERABLE when the other *Charcoal filter train, one fan (OBV020) and associated ductwork, damper, valves, and controls are OPERABLE. In MODES 1, 2, and 3, a OBA could lead to a fission product release to primary containment that leaks to .* containment. Therefore, SGT System OPERABILITY is required. during these .MODES. In MODES 4 and 5, the and of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT System in OPERABLE status is not required in MODE 4 or 5, ex6ept for other under which significant releases* of: radioactive material can be postulated, such as during .* -Operations with a potential for draining the reactor Vessel * (OPDRVs), or during .moVenient of RECENTLY. I.RRADIATED FUEL assemblies. in the secondary containment. The SGT System is only required to. be OPERABLE *during OPDRVs or handling *of RECENTLY IRRADIATED FUEL. . * . A.1 *With one SGT subsystem i rioperabl e: the inoperable .** inust be restored to OPERABLE status in 7 days.* In this . *. Condition, the remaining OPERABLE: SGT subsystem is adequate. to pei-for:-ni the required radioactivity release control .
• funGti on. *However, the qveral l
• sysfem reli ability is .. . r'educed
• becau*se a single fail u*re tn the OPERABLE subi:oystem could result in. the radioactivity release controi function * *not being adequately performed. The 7 Completion Ti me on cionsideratton such factors as the ;. *
• availability of the OPERABLE SGf subsystem and the .*low probability of ci DBA occurring during' :this period>** *B.1 If the SGT subsystem cannot .restored to :OPERABL.E status , within*the required Completion 'rime il1 MODE 1, 2, or 31 the: .. plant must be brought.to a MODE in which the overall plant * *.risk is minimized, To>achieve this status, :the plant must.be . *.brought t<f at least MODE .. 3 wi'thi n
• 12 hours<: Remaining . in :the *-. *, , ... (continued). .. .B Revi.sion No/ 715 **.-:*.

.* ... *. BASES ACTIONS I I -* 1-;_ *_.* **.*>>,. . : -: ... *.:_-. *, .. ** *1, .** ... **. ';'*" . *.'* .. ;. ,._.-.":. ,* .-__ :._.*, ,**,* * ... -. .. :_:.-: *, .. ---** * .. ***:*-:: *-"*--* -'* PBAPS UNIT 2 B.1 (continued) SGT System . B 3.6A.3 Applicability of the'LCO is acceptable because the plant' risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE.3 to perform the necessary repairs to restore the system to OPERABLE status will be However, voluntary entry into MODE 4 may be made. as it is. al so an acceptable 1 ow-risk state. The allowed Completion Time is reasonable, based on operating .experience,* to reach the required plant conditions from full power conditions in an orderly manner and without plant systems. . . c .1 I c

• 2 o 1 ! <:!-'J.9. co 2 ;-2 During movement of RECENTLY IRRADIATED FUEL assemblies, in the secondary containmenf or during OPDRVs, when Required Abtion A.1:cannot be completed within the Completion . Time; ."the OPERABLE SGT subsystem should immediately be placed in operati o'n. .lhi s ac.ti on ensures that the reinai ni ng . . .
• subsystem is OPERABLE,: tha.t *no failures tha1; could prevent . automatic actuation have cc.curred, and .that any other failure .. woui d be readi) y' det.ected . 'An alternative to Requited Action C.1 is to immediately -suspend. 8'cti vi ti es . that Iii potf}nti al .. for.-rel ecising : radfoat:t;ive material . to the secondary contai nitient' -thus . .
• placihg :the:, plant.in a corid:ition that rili nimizes risk .. If applicable_;'-movement' of RECENTLY IRRADIATED. FUEL assemblies must inimed'iately be)-suspended. Suspension of -this activity * , must not preclude completion of* mc:ivement .. of-a: *component *to a . .sate position. .. Al. s*o, it applicable, .. act-1-ons must .* * ... --; minedi a tel y be i ni tfateid to suspend OPDRVs in order to * .. -. ' . nii rii mi ?'.e the probabi l ify of' .a 1 d i:ai rid own an_d . -* subsequent,potenti;al. :for .f-i 'ssion
• prqduct rE3lease .; Actions* ** * -.111ust**c6i1tinue *unti_l :OPDRys. are suspended;
• _ * . .* ... ,_ -* --*.* . : --._ .. -.*,_ ' . ... -.,:*_ :: .-.. The Required Acti ans' ;(}f Conqi ti9n' C -have been rliodi fi ed by. a .. . Note statihg "that :LCO. 3.0 .. 3 is 'riot applicable,* sin.Ce the* ' . movement be ;r;** *. MODES 4 and 5 .. * . . . . -. . . . , . .. ; . . {continued) -. : .*._.*_. -'* ' .. .*:_..*-*:.* :*.: .... .>* -* *.. *-*--:: ** *: ., . . .: **. . .*. '**.*'.-'" .. ,. ..... .-..... B '3.6-88 Revi Np: 75' .-_ -... * ..... , ..

BASES SGT System B 3.6.4.3 ACTIONS .bL..l (continued) SURVEILLANCE REQUIREMENTS ..

• 0PBAPS UN IT 2 If both SGT subsystems are inoperable in MODE 1, 2, or 3, the SGT System may not be capable of supporting the required radioactivity release control function. Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCD is acceptable because the plant risk in MODE 3 is -similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state .. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. E.1 and E.2 When two SGT subsystems are inoperable, if applicable, movement of RECENTLY IRRADIATED FUEL assemblies in secondary containment must be Suspension of this actjvity shal*l not preclude comp1etion of movement Qf a comprinent to a safe positton. Also, if applicable, actions must immediately be jnitiated to suspend OPnRvs in order to* the probability of a vessel and potential for fission product release. Actions must continue until are suspended.
• Required Action E.l been modified by a Note stating that LCD 3.0,3 js not since the movement of RECENTLY IRRAD.IATED .fUEL can. only be performed in MODES 4 and 5. SR 3 *. 6 .4 . 3 : l ' ' Operating each SGT subsystem* (including each filter train fan) 15 minutes ensures that*b6th subsystems are OPERABLE and that all>associated controls are fUnctioning properly. It also ensures 'that block(lge, fan or motor failure' or: excessive. yibration can be detected for c;orrective action. Operation with the on (automatic.heater cycling to maintain* temperature) 15 minutes periodically is sufficient to moisture Qn. the adsorbers and HEPA Ji lters si nee during idle peri.oqs *** fnstrumenf air: is injected i hto the filter* plenum to keep the * . filters The Surveil lcinc;e Frequency is controlled under the , . Survei i lance Frequency Contrc:i1. Program. . * .. continued B .. RevisionNo. 86 I I i 1.
• BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES . UNIT 2 SR 3.6.4.3.2 SGT System B 3.6.4.3 This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and .the physital of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP. SR 3.6.4.3.3 This SR verifies that SGT subsystem starts on of an actual or simulated initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary. Cpntainment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 1.5.1.6. 2. UFSAR, Section 14.9. 3. Revision 2, Technical to Support *Risk-Informed Modification to Selected Required End for BWR Plants, December 2002, . B' 3.6-90 *Revision Nci. 86*

HPSW System B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 High Pressure Service Water (HPSW) System BASES BACKGROUND PBAPS UNIT' 2 . The HPSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shutdown following a Design Basis Accident (DBA) or transient. The HPSW System is operated whenever the RHR heat exchangers are required to operate in the shutdown cooling mode or in the suppression pool cooling or spray mode of the RHR System. The HPSW System consists of two independent and redundant subsystems. Each subsystem is made up of a header, two 4500 gpm pumps, a suction source, valves, piping and associated instrumentation. Either of the two subsystems is capable of providing the required cooling capacity with one pump operating to maintain safe shutdown conditions. The two subsystems are separated from each other by a normally closed motor operated cross tie valve, so that failure of one subsystem will not affect the OPERABILITY of the other subsystem. The normally closed cross tie valve is supplied with redundant safety related power supplies to ensure that a single failure will not prevent. it from being opened when required during a design basis event. A line connecting the HPSW System of each unit is also provided. Separation of*the two units HPSW Systems is provided by a of two locked* closed, manually operated valves. The HPSW System is* destgned with redundancy so that no single active.* component failure can prevent it from achieving its function. The HPSW* System is described in the. UFSAR,. Section 10:7, Reference.1. Normal cooling water pumped by the HPSW pumps from the.* * *conowingo the tube of the RHR heBt exchangers, and to discharge pond. The .required level for .the pumps in the bay of the pump 98.5 ft Conowingo batum (CD) $ 113 ft CD. The level ensures net positive suction head and the maximum level corresponds to the level in the pump baj with water solid up to the motor baseplate: An_* alternate supply* and discharge path (from the emergency heat .sink) is available in the unlikely event the Conowingo*dam or the floods .. This lineup, h6wever, has to manually aligned; (continued).* 'B 3. 7-1 Revision 114 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES . PBAPS _UNIT 2 HPSW System B 3.7.1 The system is initiated manually from the control room. If operating during a loss of coolant accident (LOCA), the system is automatically tripped to allow the diesel generators to automatically power only that equipment necessary to reflood the core. The system (using a single HPSW pump) is assumed in the analysis to be manually started 10 mi.nutes after the LOCA. At one hour after the LOCA, a second HPSW pump is assumed to be started, with the HPSW cross tie line placed .in service if required to provide cooling water to two RHR heat exchangers. The RHR System design permits the system to be initiated as early as 5 minutes after LPCI initiation. The HPSW System removes heat from the suppression pool to limit the suppression pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment. can perform its function of limiting the release of radioactive materials to the environment a LOCA. The ability of the HPSW System to support long term cooling of the reactor or primary containment is discussed in References 2 and 3. These analyses explicitly that the HPSW System will provide adequate cooling support to the equipment required for safe shutdown. These analyses include the evaluation of the long term primary containment response after a design basis LOCA. The safety analyses for long term cooling were performed for various combinations of RHR System failures. The worst case single failure that affect the performance of the HPSW System any failure that would disable one HPSW subsystem. As discussed in the UFSAR, Section 14.6.3 (Ref. 4) for these analyses, manual initiation the HPSW subsystem and the associated RHR System is assumed to occur 10 minutes after a OBA. Manual alignment of the HPSW cross tie is assumed at 1 hour after a OBA, with a failure of a single diesel generator, to ensure that *two HPSW are available to provide the required cooling flow to two RHR heat exchangers within a containment cooling/spray subsystem. Opening of the cross tie motor operated valve removes separation between the two HPSW subsystems; however, because the cross tie valve is opened only after a single diesel generator failure has occurred, an additional failure does not need to be considered, and independence of the two HPSW subsystems is not required following the OBA single diesel generator (continued) B 3.7-2 Revision No. 114 BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNiT-2 HPSW System B 3.7.1 The HPSW flow assumed in-the analyses is 4500 gpm _per pump with two pumps operating providing flow through the two required RHR heat exchangers. In this case, the maximum suppression chamber water temperature and pressure are less than or equal to l88°F and 43 psig, respectively, well below the design temperature of 281°F maximum allowable pressure of 56 psig. The HPSW System satisfies 3 of the NRC Policy Statement. Two HPSW sµbsystems and the *HPSW cross tie line (which allows two HPSW subsystems within the same unit to be connected) are required to be OPERABLE to provide the*required redundancy to ensure that the system functions to remove post-accident heat loads, assuming the worst case single active failure occurs coincident with the loss of offsite power. A HPSW subsystem-is considered OPERABLE when: a. Two pumps are OPERABLE; and b. An OPERABLE flow path is capable of taking suction '.from t_he pump structure .and transferring the water to the.required RHR heat exchanger at t_he assum_ed fl ow rate. -Additfonally; 'the HPSW cross tie valve (which allows the HPSW subsistems to be must be closed so that failure of one subsystem will not affect of the other subsystems. HPSW tie a. 'TheHPSW_CrOSS tie_valve is OPERABLE; and ' ' b. *An OPERABLE path is* capable of cross connectfng or

• i.soi'ating the HPSW subsystems. An *adequate suction source is not in th.is LCD _since the minimum*net positive suction* head (98.5 ft Conowingo Datum (CD) .in the pump bay) and normal heat sink temperature requirements. are bounded.by the-emergency service water pump_ and norn:ial heat sink* requirements (LCOJ.7.*z, "Emerge_ncy Sen/ice Water CESW) System and Normal . Heat Si n k"' ) . . . (continued) *'--*::. B 3. 7-3 No*; 114 BASES (continued) APPLICABILITY ACTIO.NS PBAPS
• UN IT 2 HPSW System B 3.7.1 In MODES 1, 2, and 3, the HPSW System is required to be OPERABLE to support the of the RHR System for primary *containment cooling (LCD 3.6.2.3, "Residual Heat Removal (RHR) Suppression Pool Cooling," and LCD 3.6.2.4, "Residual Heat
• Removal (RHR) Suppression Pool Spray") and decay_ heat removal (LCD 3.4.7, "Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown"). The Applicability is. therefore consistent with the requirements of systems. In MODES 4 and 5, the OPERABILITY requirements of the HPSW *System are determined by the systems it supports, and therefore, the requirements are not the same for all facets of operation in MODES 4 and 5. Thus, the LCOs of the RHR shutdown cooling system, which requires portions of the HPSW System to be OPERABLE, wi 11 govern. HPSW System operatiOn in MODES 4 and 5. With one HPSW subsystem inoperable, the inoperable HPSW subsystem must be to OPERABLE status within 7 days. With the unit in thts condition, the remaining OPERABLE HPSW subsystem is adequate to *perf6rm the HPSW heat removal function. However, the overall reliability is reduced because a failure in the OPERABLE HPSW subsystem could result in* of HPSW function. The Completion Time is based on the redundant HPSW capabilities afforded by the OPERABLE and the low probability .of an event occurring requiring during this period. The Required Action is.modified by .a Note indicating that .the* applicable Conditions of LCD 3.4.7, be Requited Actions taken if an tnoperable HPSW subsystem results in an inoperable RHR shutdown cooling subsystem. This is an exception to LCD 3.0.6 and ensures the proper actions are taken for these With an inoperable cross tie line, the HPSW cross tie line must be restored to an OPERABLE status within 7 days. With an HPSW cross tie line, if no additional failures occur, and two HPSW subsystems OPERABLE, then the two OPERABLE and flow* paths ensure two HPSW pumps are available to (continu_ed) B 3.)-4 Revision No. 114 *
• BASES ACTIONS I I'. PBAPS UNIT 2-B.1 (continued) HPSW System B 3.7.1 provide adequate heat removal capacity following a design basis accident. However, the overall reliability is reduced because a single failure in the HPSW System could result in a loss of HPSW System function. Therefore, continued operation is permitted only for a limited time. The Completion Time is based on remaining heat removal capacity, and the low probability of a DBA occurring during this period. C.l If one HPSW subsystem or the HPSW cross tie is inoperable and* not _restored within the provided Completion Time, the plant be brought to a condition in which the overall plant risk is minimized. To this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and becaus§ the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time,is teasonable, based on operating experience, to reach the plant conditions from full power conditions in an orderly and without challenging plant systems. With both* HPSW st,tbsystems inoperable, .. the HPSW System is -not *capable of performing its *intended function. _ At least one *
• subsjstem must be restor§d to OPERABLE .within 8 .. The 8 hour Completion Time for restor1ng one HPSW subsystem to status, is based on the Times provided for.* _the RHR pool c6oling and-spray _functions. The Required Action is modified by a Note indi-cating that the.* applicable of LCO 3.4,7, be entered and Required Attions taken if inoperable HPSW subsystem results in an RHR shutdo0n cooling subsystem, This is an exception to LCO 3.0.6 and ensures the proper actions are taken .. for these components. * * (continued) B 3:7-5 Revision 114 BASES ACTIONS (continued) SURVEI-LLANCE REQUIREMENTS PBAPS UN IT 2 E.1 and E.2 HPSW System B 3.7.1 If the HPSW subsystems cannot be restored to OPERABLE status within the associated Completion Time of Condition D, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3-within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. SR 3.7.1.1 Verifying the correct alignment for each manual and power operated valve in each HPSW subsystem flow path provides assurance that the proper flow paths will exist for HPSW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be realigned to its accident position. This is acceptable because the HPSW System is a manually initiated This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is confrolled under the Surveillance Frequency Control Program. SR 3.7.1.2 Verification of manual transfer between the normal and alternate power source (4kV emergency bus) for the HPSW cross-tie operated valve and each RHR heat exchanger HPSW outlet valve *demonstrates that AC power will be available to operate the valves following loss of power to any single 4kV emergency bus. The ability to provide power to the HPSW cross-tie valve and each RHR heat exchanger HPSW outlet valve from either of two independent 4kV emergency buses ensures that a single failure of a DG will not result in failure of a required HPSW System flow path; therefore, failure of the manual transfer capability will result in inoperability of the associated HPSW subsystem. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. (continued) B 3;7-5a Revision No. 114 I i BASES (continued) REFERENCES * .. :.. PBAPS UNIT-2 1. UFSAR, Section 10.7. 2. UFSAR, Chapter 14. HPSW System B 3.7.1 3. NEDC-33566P, Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 4. UFSAR, Section 14.6.3. 5. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR.Plants, December 2002. ' .: ., .* _,, B 3.7-Sb Revisi*on No. 114 I .

ESW System and Normal Heat Sink B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 Emergency Service Water (ESW) System and Normal Heat Sink BASES BACKGROUND APPLICABLE -SAFETY ANALYSES PBAPS UNIT 2 The ESW System is a standby system which is shared between Units 2 and 3. It is designed to provide cooling water for the removal of heat from equipment, such as the diesel generators (DGs) and room coolers for Emergency Core Cooling System equipment, required for a safe reactor shutdown following a Design Basis Accident (OBA) or transient. Upon receipt of a loss of of:fsite power signal, or whenever any diesel generator is in operation, the ESW System will provide cooling water to its required loads. The ESW System consists of two redundant subsystems. Each of the two ESW subsystems consist of a 100% capacity 8000 gpm pump, a suction source, valves, piping and associated instrumentation. Either of the two subsystems is -capable of providing the required cooling capacity to -support the required systems for both units. Each subsystem provides coolant in separate piping to common headers; one each for the DG coolers, Unit 2 safeguard equipment coolers, and Unit 3safeguard equipment coolers. The design is such that any single active failure will not affect the ESW System from providing coolant to the required loads. Cboling water is pumped from the normal heat sink (Conowingo Pond) via the pump structure bay by the ESW pumps to the essential components. After removing heat from the components, the water is discharged to the discharge pond, or the emergency cooling tower in certain test alignments. -An alternate suction supply and discharge path (from the emergency heat sirik) 'is avaflable in the unlikely event the Conowing6 dam fails or:the-pond floods. This lineup, -however, -has* to be manually *aligned. --Sufficlent water inventory is available for all ESW System post LOCA-cooling requirements for a 30 day period with no additjonal makeup water* source The abi-lity . -the -ESW System to support long term cooling of the reactor containment is assuined in evaluations of the equipment -requj red for safe reactor shutdown presented in the UFSAR,. Chapter 14 (Ref. IF These analyses include the of the long term primary containment response after a design bas i s LOCA. -----. ' -(continued) _B 3.7-6 Revision No. 4 BASES . APPLICABLE SAFETY ANALY.SES (continued) LCO APPUCABI LITY PBAPS .UNIT 2 ESW System and Normal Heat Sink B 3.7.2 The ability of the ESW System to provide adequate cooling to the identified safety equipment is an implicit assumption for the safety analyses evaluated in 1. The ability to provide onsite emergency AC power is dependent on. the ability of the ESW System to cool the DGs. The long term cooling capability of the RHR and core spray pumps is also. dependent on the cooling provided by the ESW System.** ESW provides cooling to the HPCI and RCIC room coolers; however, cooling function is not required to support HPCI or RCIC System operability. The ESW System, together with the Heat Sink, satisfy Criterion 3 of the NRC Policy Statement. The ESW subsystems are to the degree that each ESW pump has separate controls, power supplies, and the operation of one does not depend on the other. In the event of a OBA, one subsystem of ESW is required to provide the minimum heat removal capability assumed in the safety analysis for the system to which it supplies cooling water. Tri ensure this requirement is met, two subsystems of ESW must be OPERABLE. At least one subsystem will operate, if the worst single active failure occurs with the loss of offsite power. A i.s considered OPERABLE when it has an OPERABLE normal sink, one OPERABLE pump, and an OPERABLE flow path capable of takirig suctioh from the pump str0cture arid the water to the appropriate equipment. The OPERABILITY of the normal heat sink is based on having a and water level in pump bay of 98.5 ft Conowingo Datum (CD) and 113 ft CD respectively and a maximum water temperature of 92°F. isolation of the ESW System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of the ESW System. In MODES 1, 2, and 3, the ESW System and normal heat sink to be OPERABLE to support OPERABILITY of the equipment serviced by the ESW System. Therefore, the ESW System and normal heat sink are required to be OPERABLE iri these MODES. . . . . continued B 3.7-7 Revision Nb . .iog* BASES APPLICABILITY (continued) ACTIONS S U RV E I L LAN C E REQUIREMENTS PBAPS UN IT 2 . ESW System and Normal Heat Sink B 3.7.2 In MODES 4 and 5, the OPERABILITY requirements of the ESW System and normal heat sink are determined by the systems they support, and therefore the requirements are not the

• same for all facets of operation in MODES 4 and 5. Thus, the LCOs of the systems supported by the ESW System and normal heat sink will govern ESW System and.normal heat sink OPERABILITY requirements in MODES 4 and 5. With one ESW subsystem inoperable, the ESW subsystem must be restored to OPERABLE status within 7 days. With the unit in this condition, the remaining OPERABLE ESW subsystem is to perform the heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE ESW subsystem could result in loss of ESW function. The 7 day Completion Time is based on the redundant ESW System capabilities afforded by the OPERABLE subsystem, the *1ow probability of an event occurring during this time period, and is consistent with the allowed Completion Time for restorfng an inoperable DG. B.l and B.2 If the ESW System cannot be restored to OPERABLE status within the associated Completion Time, or both ESW subsystems are inoperable, or the normal heat sink is inoperable, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full powe0 conditions in an orderly manner and without challenging unit systems. SR 3.7.2.1 This SR verifies the water level in the pump bay of the pump structure to be sufficient for the proper operation of the ESW pumps (the pump's ability to meet the minimum flow rate and anticipatory actions required for flood conditions are considered in determining these limits). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.7-8 Revision No. 109 ---------

BASES S U RV E I L LAN C E REQUIREMENTS (continued) PBAPS UNIT 2 ESW System and Normal Heat Sink B 3.7.2 Verification of the normal heat sink temperature ensures that the heat removal capabiltty of the ESW and HPSW systems is within OBA analysis. The water temperature is determined by using instrumentation that averages multiple inputs that measure the normal heat sink temperature. The Surveillance Frequency is control under the Surveillance Frequency Control Program. Additionally, to ensure that the 92°F normal heat sink temperature is not exceeded, this surveillance requires hourly monitoring of the normal heat sink when the temperature is greater than 90°F. The once 'per hour monitoring takes into consideration normal heat sink temperature variations and the increased monitoring frequency needed to design basis assumptions and equipment limitations are not exceeded in this condition. SR 3*.7.2.3

• Verifjing the cbrrect alignment for each manual and power valve in subsystem flow path provides assurance the flow paths will exist for ESW operation. This SR daes rint apply to valves that are . locked, sealed, or secured in position, since these va.lves were verified to be in the*correct position prior to locking,_ sealing; or securing ..
• A valve.is also allowed to be in the nonaccident position, and yet considered ih the positiori, prcivided it ccin be automaticailyrealign_ed to* its accident position within the time ..
• This SR does not require any testing or valve mani,pulation; rather, it involves.verification that those valves capable of being misposlti'oned are in the
• c'orrect posifi on. Th.is SR does* riot apply to valves that* *cannot be. inadvertently mi sa_l i gned, such as check valves .. . . ' . -. . . . This SR .is modified by a Note i.ndicatlng that isolation Of
• 0the ESW Sysfem 'to: components or systems may render those or inoperable, but d6es'not affect OPE RABI LfTY of the ESW System. , As such, wheh all ESW pumps, valves, ahd but a*branch corinection _Off* *the maih header* is iS:olated, the ESW System is stil.l 0 PE RABLE< . . The lance Frequency *.-is control*l ed under the* *' Survei 11 a.rice Frequency Control Program. :*_.* (continued) B 3. 7-9 Revision BASES SURVEILLANCE REQUIREMENTS (continued) REFER.ENCES PBAPS. UNIT 2 ESW System and Normal Heat Sink B 3.7.2 SR 3.7:2.4 This SR verifies that the ESW System pumps will automatically start to provide cooling water to the required safety related equipment during an accident event. This is demonstrated by the use of an actual or simulated initiation signal. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Chapter 14. 2; NEDC-32988-A, Revision 2, Techni.cal Justification to Support Modification to Selected Required *End States for BWR Plants, December 2002 .. . *.:*** .. -.*. B3.)-10*.

Emergency Heat Sink B 3.7.3 B 3.7 *PLANT SYSTEMS B 3.7.3 Emergency Heat Sink BASES BACKGROUND P BA:P S . UN IT 2 The function of the heat sink is to provide heat **removal capability so that the Unit 2 and 3 reactors can be safely 5hutdown in the event of the unavailability of the normal sink (Conowingo Pond). The heat sink supports the dissipation of sensible and decay heat so that the two reactors can be when normal heat sink is unavailable to flooding or failure of the Conowingo dam. This function is provided via the Emergency Service Water CESW) System and the High Pressure Service Water System ( HPSW). The emergency heat sink consists of an induced draft three *cell cooling tower with an integral storage reservoir, three cooling tower fans, two ESW booster pumps, valves, piping, and associated instrumentation. The emergency cooling tower, equipment, valves; and of the emergency heat sink are designed in accordance with seismic Clciss I criteria. Standby is provided to ensure the emergency heat sink is tapab)e of operating during a loss of offsite power.

• When the normal heat sink (Conowingo Pond)' is lost or when flooding occurs .* sluice gates in the pump structure housing the ESW pumps and HPSW pumps are closed. Water-is then* provided through two gravity fed lines from the heat sink reservoir into the pump structure pump bays. The ESW and HPSW pumps then cooling to heat exchangers required to bring the Unit 2 and 3 reactors to *safe conditions. Return water from the ttPSW Sy5tem flows directly to two of the three cells of the emergency
• cooling tower. Return water from the ESW System flows through one the two ESW booster pumps and is pumped into one of the emergency cooling tower by the HPSW System. This configuration allows for closed cycle operation of the ESW and HPSW Systems. Sufficient capacity (3.55 million gallons*of water) is when the minimum water level is 17 feet above the i . . bottom of the emergericy heat sink reservoir, to support simultaneous shutdowh of Units Zand 3 for 7 days without makeup water. After 7 days, water will_ be provided from the Susquehanna River or from tank trucks. (continued) B 3 ._7-11 *-Revision No. *67 BASES (continued) APPLICABLE SAFETY ANALYSES LCD PBAPS UN IT 2 Emergency Heat Sink B 3.7.3 The emergency heat sink is required to support removal of heat from the Unit 2 and 3 reactors, prima.ry containments, and other safety related equipment by providing a seismic Class I heat sink for the fSW and HPSW Systems for shutdown of the reactors when the normal non-safety grade heat sink (Conowingo Pond) is Sufficient water inventory is available to supply all the ESW and HPSW System cooling requirements of both units during shutdown with a concurrent loss of offsite power for a 7 day period with no additional makeup water available. The ability of the emergency heat sink to support the shutdown of both Units 2 and 3 in the event of the loss of the normal heat sink is presented in the UFSAR (Ref. 1). . The Emergency Heat Sink satisfies Criterion 3 of the NRC Policy Statement. In the event the normal heat sink is unavailable and offsite power is lost, the emergency heat sink is required to provide the minimum heat removal capability for the ESW and HPSW Systems to safely shutdown both units. To ensure this requirement is met, the emergency heat sink must be OPERABLE. The emergency heat sink is considered OPERABLE for Unit 2 when it has an OPERABLE flow path from the ESW System with one OPERABLE ESW booster pump, an OPERABLE flow path from the Unit 2 HPSW System, two of the three cboling tower cells *I and two of the three associated fans OPERABLE .* one OPERABLE gravity feed line from the emergency sink reservbir into the pump bays with the capability to connect the Unit 2 and 3 pump structure bays, or one OPERABLE gravity feed line from the emergency heat sink to the Unit .2 pump bay the Unit 2 Unit 3 bays not connected, and the capability exists to manually isolate the ESW and HPSW pump structure bays from the Conowingo Pond. Valves in the required flow paths are considered OPERABLE if they can be manually aligned to their correct position. The OPERABILITY of the emergency heat sink also requires a minimum water level in the emergency heat sink reservoir of 17 feet. continued B 3.7-12 Revision No. 92 BASES LCD (continued) APPLICABILITY ACT IONS PBAPS UN IT 2 Emergency Heat Sink B 3.7.3 Emergency heat sink water temperature is not addressed in this LCD since the maximum water temperature of the emergency cooling tower reservoir has been based on historical data, to be bounded by the normal heat sink requirements (LCD 3.7.2, "Emergency Service Water (ESW) System and Normal Heat Sink"). In MODES 1, 2, and 3, the emergency heat sink is required to be OPERABLE to provide a seismic Class I source of cooling water to the ESW and HPSW Systems when the normal heat sink is unavailable. Therefore, the emergency heat sink is .required to be OPERABLE in these MODES. In MODES 4 and 5, the OPERABILITY requirements of the emergency heat sink are determined by the systems it supports in the event the normal heat sink is unavailable. With one required emergency cooling tower fan inoperable, action must be taken to restore the required emergency cooling tower fan to OPERABLE status within 14 days. The 14 day Completion Time is based on the remaining heat removal capability, the low probability of an event occurring requiring the inoperable emergency cooing tower fan to function, and the capability of the remaining emergency cooling tower fan,.
• With the emergency heat sink inoperable for reasons other than Condition A, the emergency heat sink must be restored to OPERABLE status within 7 days. With the unit in this condition, the normal heat sink (Conowingo Pond) is adequate to perform the heat removal function; however, the overall reliability is reduced. The 7 day Completion Time is based on the remaining heat removal capability and the low probability of an event occurring requiring the emergency heat sink to be OPERABLE during this time period. continued B 3.7-13 Revision No. 1 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 C.l and C.2 Emergency Heat Sink B 3.7.3 If the emergency heat sink cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. SR 3.7.3.1 This SR ensures adequate long term (7 days) cooling can be maintained in the event of flooding or loss of the Conowingo Pond. With the emergency heat sink water source below the minimum level, the emergency heat sink must be declared inoperable. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.7.3.2 Operatinci required cooling tower fan for 15 ensures that all required fans are OPERABLE and that all-associated controls are functioning properly. It also ensures that fah or motor failure, or excessive -vibration, can be detected for corrective action. The Surveillance Frequenty is controlled the Surveillance Fr_eque*ncy Control Program.* .1. UFSAR, Section 10.24. B 3.7-14 Revisioh No. 86 MCREV System B 3.7.4 B 3.7 PLANT SYSTEMS B 3.7.4 Main Control Room Emergency Ventilation (MCREV) System BASES BACKGROUND PBAPS UN IT 2 The MCREV System provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke. The MCREV System consists of two independent and redundant high efficiency air filtration subsystems and two 100% capacity emergency ventilation supply fans which supply and provide emergency treatment of outside supply air and a CRE boundary that limits the inleakage of unfiltered air. Each filtration subsystem consists of a high efficiency particulate air (HEPA) an activated charcoal adsorber section, a second HEPA filter, and the associated ductwork, valves or dampers, doors, barriers and instrumentation. Either emergency ventilation supply fan can operate in conjunction with either filtration subsystem. HEPA filters remove particulate matter, which may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowirig time for decay. A dry gas purge is provided to each MCREV subsystem during idle periods to prevent moisture accumulation* in the filters.* The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. lhis area encompasses the control room, and may encompass other non-critical areas to which other frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected dur1ng normal natural events, and accidents conditions. The* CRE boundary is the combination Of floor, roof, ducting, dampers, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that.the in leakage of unfiltered air into the.CRE will n6t exceed the inleakage in the licensing bases analyses of design basis accident (OBA) consequences and chemical hazards to CRE occupants. Since the equipment required and. the allowable ihleakage is different for radiological and chemical events, the CRE boundary distinguishes the boundaries each event. The CRE and its are defined in the Control Room Envelop Habitability Program. continued B 3.7-15 Revision No; 116 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 MCREV System B 3.7.4 The MCREV System is a standby system that is common to both Unit 2 and Unit 3. The two MCREV subsystems must be OPERABLE if conditions requiring MCREV System OPERABILITY exist in either Unit 2 or Unit 3. Upon receipt of the initiation signal(s) (indicative of conditions that could result in radiation exposure to CRE occupants), the MCREV System automatically starts and pressurizes the CRE to minimize infiltration of contaminated air into the CRE. A system of dampers isolates the CRE along the radiological and outside air, taken in at the normal ventilation intake, is passed through one of the charcoal adsorber filter subsystems for removal of airborne radioactive particles. During normal control room ventilation system restoration following operation of the MCREV system, the automatic initiation function of MCREV will briefly be satisfied by operator actions and controlled procedural steps. If all normal and air conditioning were lost, the control room operator would initiate an emergency shutdown of non-essential equipment and lighting to reduce the heat generation to a minimum. Heat removal would be accomplished by conduction through the floors, ceilings, and walls to adjacent rooms and to the environment. Additionally, the MCREV System is designed to maintain a habitable ehvironment in the CRE for a 30 ccintinuous occupancy after a DBA without exceeding 5 rem total effective dose equivalent (TEDE). A single MCREV subsystem will pressurize the CRE relative to the external areas adjacent to the CRE radiological boundary to minimize infiltration of air from all surrounding areas adjacent to the CRE radiological boundary.-MCREV System operation in maintaining CRE habitability is discussed in the UFSAR, Chapters 7, 10, and 12, (Refs. 1, 2, and respectively). The ability of the MCREV System to maintain the habitability of the CRE is an explicit assumption for the safety analyses presented in the UFSAR, Chapters 10 and 12 (Refs. 2 and 3, respectively). The MCREV System is assumed to operate following a DBA, as discussed in the UFSAR, Section 14.9 (Ref. 4). The radiological doses to the CRE occupants as a result of the various DBAs are summarized in Reference 4. No single active or passive electrical failufe will cause the loss of outside or recirculated air from the CRE. continued B 3. 7-16 Revision ]o. 116 BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNIT 2 MCREV System B 3.7.4 The MCREV System provides protection from smoke or hazardous chemicals to the CRE occupants. A periodic offsite chemical survey, and procedures for onsite chemicals, are essential elements of CRE protection against hazardous chemicals. The system design is based on low probability of offsite sources of toxic gas, based on a chemical survey of the surrounding areas. Those offsite sources of toxic gas with a greater than low probability are evaluated in accordance with Regulatory Guide 1.78 (Ref. 10) or Regulatory Guide 1.95 (Ref. 11) and determined to be acceptable for continued habitability. The offsite chemical survey is conducted periodically to determine any change of condition that may need to be addressed: The onsite chemicals are controlled procedurally such that they do not affect CRE habitability adversely. Although the MCREV system does not have a toxic gas mode, evaluations have been performed to assess the impact of toxic gas on control room habitability. The evaluations have. concluded that based on either the low probability of hazardous chemical events occurring or operator action to don Self Contained Breathing Apparatuses CSCBAs) and secure the control room additional prritection from offsite hazardous chemicals is not required. Only new chemicals or thanges in quantities of chemicals identified as part of the chemical survey will be analyzed further for control room habitability purposes. The MCREV System satisfies Criterion 3 of the NRC Pol1cy Statement. Two redundant subsystems of the MCREV System are required to be OPERABLE to ensure that at least one is available, if a single active failure disables the other subsystem. Total MCREV System failure, such as from a loss of both ventilation subsystems or from an CRE boundary, could result in dose of 5 rem total effective dose CTEDE) to the CRE occupants in the event of a OBA or for toxic gas events, result in incapacitation of the CRE inhabitants. Each MCREV subsystem is considered OPERABLE when the individual components necessary to limit CRE occupant radiation exposure are OPERABLE. A subsystem is considered OPERABLE when: a. One Fan is OPERABLE; (continued) B 3.7-16a Revision No. 116 BASES LCO (continued) PBAPS UN IT 2 b. MCREV System B 3.7.4 HEPA filter and charcoal adsorbers are not excessively restricting flow and are capable of performing their filtration functions; and c. Ductwork, valves, and dampers are OPERABLE, and air flow can be maintained. A subsystem may be considered operable using either.the A or B fan combined with either the A or B Filter bank. In nrder for the MCREV subsystem to be considered OPERABLE, the CRE radiological boundary must be maintained such that the CRE occupant dose from the large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs. In order for the subsystem to be considered OPERABLE, the CRE boundaries must be maintained OPERABLE, including the integrity.of the walls, floors, ceilings, and ductwork. Temporary seals may be used to maintain the boundary. For hazardous chemical events, the CRE chemical boundary is OPERABLE when the CRE occupants can be protected from hazardous chemicals. The in leakage limit for hazardous chemicals is defined and established in the hazardous chemical analyses (Ref. 12 and 13). If measured inleakage is greater than the limit established in the analyses, or if a new hazardous chemical (not meeting the screening criteria of Reference 10 or Reference 11) or increased quantity of an existing chemical is determined to exist, then the CRE chemical boundary is considered inoperable, unless continued habitability is evaluated as being acceptable (Ref. 10, 11). For smoke events, the CRE boundary is OPERABLE when the CRE occupants can be protected from events external or internal to the plant. For smoke events, no regulatory limit exists for the amount of smoke allowed in the CRE. However, if smoke enters the CRE such that mitigating actions are required, then the CRE boundary is considered inoperable. The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls. This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls should be proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition when a need for CRE isolation is indicated. (continued) B 3.7-16b Revision No. 121 MCREV System B 3.7.4 BASES (continued) APPLICABILITY ACTIONS PBAPS UNIT 2 In MODES 1, 2, and 3, the MCREV System must be OPERABLE to ensure that the CRE will remain habitable during and following a DBA, since the DBA could lead to a fission product release. In MODES 4 and 5, the probability and consequences of a DBA are reduced because of the pressure and temperature limitations in these MODES. Therefore, maintaining the MCREV System OPERABLE is not required in MODE 4 or 5, except for the following situations under which significant radioactive releases can be postulated: ' a. During operations with potential for draining the reactor vessel COPDRVs); b. During CORE ALTERATIONS; and* c. During movement of irradiated fuel assemblies in the secondary containment. With one MCREV subsystem inoperable, for reasons other than an i npperabl e CRE boundary, the inoperable MC REV subsystem must be restored to OPERABLE status within 7 days. *with the unit in this condition, the remaining OPERABLE MCREV subsystem is adequate to maintain control room temperature and to perform the CRE occupant protection function. However, the overall is reduced because a in the subsystem could result in loss of MCREV System function. The.7 day Completion Time is on the low probability *of a DBA riccurring during this time and that the remaining subsystem can provide the required B.1. B.2 and 'B.3. If the unfiltered inleakage of potentially air past a CRE bouhdary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of DBA consequences (allowed to be up fo 5 rem total effective dose equivalent *CTEDE)), protection of CRE occupants from hazardous chemicals or smoke that have been licensed to occur, the CRE boundary is Actions* must be taken to restore an OPERABLE CRE boundary within 90 days. continued B 3.7-17 Revision No. 116 BASES ACTIONS PBAPS UNIT 2 B.1. B.2 and B.3 (continued) MCREV System B 3.7.4 During the period that the CRE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke (Refs. 6, 7, 10 and 11). Action must be taken within 24 hours to verify that in the event of a OBA; the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of OBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke as required. These mitigating actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the conditionj of whether entry is intentional or unintentional. The 24-hour Completion Time is reasonable based on the low probability of a OBA occurring during this time period, and the initiation of mitigating actions.-The 90 day completion Time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor and maintain it in a safe shutdown condition in the event of a OBA ..
• In addition, the 90 day Completion Time is a reasonable time to diagnose, plan and repair, and test most problems with the CRE boundary. In MODE 1, 2, or 3, if the inoperable MCREV subsystem or the CRE cannot be restored to OPERABLE status within the required Completion Time; the must be placed in a MODE that overall plant risk. To achieve this status, unit must be placed at least MODE 3 withih 12 in the Applicability of the LCQ is acceptable because -the plant risk iri MODE 3 is similar to or lower than the risk MODE 4 (Ref; 5} and because the time spent in MODE 3 to perform the necessary repairs to restore the system -to OPERABLE will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on to reach the required unit conditions. from full power conditions in an orderly manner and without challenging unit systems. *
• continued B 3. Revisi.on No. 116 BASES ACTIONS (continued) PBAPS UNIT 2 !?._: __ _____ !? __ :_?._: __ ____ _P. __ :_? __ :_?_ ____ MCREV System B 3.7.4 The Required Actions of Condition D are modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown. During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, if the inoperable MCREV subsystem cannot be restored to OPERABLE status within the required Completion Time, the OPERABLE MCREV subsystem may be placed in operation. This action ensures that the remaining subsystem is OPERABLE, that no failures that would prevent automatic actuation.will occur, and that any active failure will be readily detected. An alternative to Required Action D.1 is to immediately suspend activities that present a potential for releasing radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and the iubsequent potential for fission product release. Actions must continue until the OPDRVs are suspended. E.1 If both MCREV subsystems are inoperable in MODE 1, 2, or 3 for reasons other than an inoperable CRE boundary (i.e., Condition B), the MCREV System may not be capable of performing the intended function. Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued) B 3.7-l9 Revision No. 68 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 F.l. F.2 and F.3 MCREV System B 3.7.4 The Required Actions of Condition Fare modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations .. Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown. During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, with two MCREV subsystems or with one or more MCREV subsystems inoperable due to an inoperable CRE boundary, action must be taken immediately to suspend activities that a potential for releasing radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in the secondary containment must be suspended immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position. If applicable, actions must be initiated immediately to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until the OPDRVs are suspended. SR 3.7.4.l This.SR verifies that a subsystem in a standby mode starts on demand and continues to operate for 15 minutes. Standby systems .should be checked periodically to ensure that they start and function properly. As the and normal operating conditions of this system are hot severe, testing each subsystem periodically provides an adequate check on this system. The Frequency is controlled under the Surveillance Frequency Control Program.
• SR 3.7.4.2 This SR verifies that the required MCREV testing is performed in accordance with the Ventilation Filter Testihg Program CVFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additiona1 information are discussed in detail in the VFTP. contin0ed B 3.7-20 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 2 SR 3.7.4.3 MCREV System B 3.7.4 *This SR verifies that on an actual Dr simulated initiation signal, each MCREV subsystem starts and operates. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.4 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.7.4.4 This SR verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program. The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of DBA consequences is no more than 5 rem whole body dose or its equivalent to any part of the body and the CRE occupants are protected from hazardous chemicals and smoke that have been licensed to occur. This SR verifies that the unfiltered air inleakage into the CRE through the radiological and chemical boundaries is no greater than the flow rates assumed in the licensing basis analyses of DBA consequences and control room habitability evaluations for hazardous chemicals. When unfiltered air inleakage is greater than the assumed flow rate, Condition B must be entered. Required Action B.3 allows time to restore the CRE boundary to OPERABLE provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident. Mitigating actions are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref. 6) which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 7). These mitigating actions may also be used as mitigating actions as required by Required Action B.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 9). Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis DBA consequence or chemical habitability analyses, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status. (continued) B 3.7-20a Revision No. 116 BASES (continued) REFERENCES PBAPS 2. 1. UFSAR, Section 7.19 . . 2. UFSAR, Section 10.13. 3. UFSAR, Section 12.3.4. 4. UFSAR, Section 14.9. MCREV System B 3.7.4 5. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. 6. Regulatory Guide 1.196, "Control Room Habitability at Light-Water Nuclear Power Reactors", May 2003. 7. NEI 99-03, "Control Room Habitability Assessment", June 2001. 8. TSTF-448, Rev. 3, "Control Room Habitability" dated 8/8/06 and "Corrected Pages for TSTF-488, Rev. 3, Control Room Habitability", dated 12/29/06. 9. Letter from Eric J. Leeds (NRC) to James W. Davis CNEI) dated January 30, 2004, "NEI Draft White Paper, Use of Generic Letter 91-18 process and Alternative Sburce
• Terms in the Context* of Room Habitability." 10. NRC Regulatory Guide 1.78, Evaluating the Habitability of i Nuclear Power Plant Control Room during a Postulated Hazardous Chemical release, Rev: 0. 11. NRC Guide 1.95, Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release, Rev. 0. . . 12. Calculation PM-1085, "Peach Bottom Atomic Power Station Control Room Habitability Analysis for the Off-site Chemicals*." I 13; Calculation PM-1175, "Contr.ol' Room Habitability. for Chemicals Stored Onsite." B 3.7-21 Revision No. 121 Main Condenser Offgas B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Main .Condenser Offgas BASES BACKGROUND During unit operation, steam from the low pressure turbine is exhausted directly into the condenser. Air and noncondensible gases are collected in the condenser, then exhausted through the steam jet air ejectors (SJAEs) to the Main Condenser Offgas System. The offgas from the main condenser normally includes radioactive gases. The Main Condenser Offgas System has been incorporated into the unit design to reduce the gaseous radwaste emission. This system uses a catalytic recombiner to recombine
• radiolytically dissociated hydrogen and oxygen. The gaseous mixture is cooled and water vapor removed by the offgas recombiner condenser; the remaining water and condensibles are stripped out by the cooler condenser and moisture separator. The remaining gaseous mixture (i.e., the offgas recombiner effluent) is then processed by a charcoal adsorber bed prior to release. APPLICABLE The main condenser offgas gross gamma activity rate is an SAFETY ANALYSES initial condition of the Main Condenser Offgas System failure event, discussed in the UFSAR, Section 9.4.5 LCO PBAPS UNIT 2 (Ref. The analysis assumes a gross failure in the Main Condenser Offgas System that results in the rupture of the Main Condenser Offgas System pressure boundary. The gross ganuna activity rate is controlled to ensure that, during the event, the calculated offsite doses will be well within the limits of 10 CFR 100 (Ref. 2) or the NRC staff approved licensing basis. The main condenser offgas limits sat1sfy Criterion 2 of the NRC Policy Statement. To ensure compliance with. the assumptions of the Main Condenser Offgas System failure event (Ref. I), the. fission product release rate should be consistent with a noble gas release to. the reactor coolant of 100 pCi/MWt-second after decay of 30 minutes. The LCO is established consistent (continued) B 3.7-22 Revision No *. O BASES LCO (continued) APPLICABILITY ACTIONS PBAPS UN IT 2 Main Condenser Offgas B 3.7.5 with this requirement (3293 MWt x 100 µCi/MWt-second = 320,000, µCi/second) and is based on the original licensed rated thermal power. The LCD is applicable when steam is being exhausted to the main condenser and the resulting noncondensibles are being processed via the Main Condenser Offgas System. This occurs during MODE 1, and during MODES 2 and 3 with any main steam line not isolated and the SJAE in operation. In MODES 4 and 5, steam is not being exhausted to the main condenser and the requirements are not applicable. If the offgas radioactivity rate limit is exceeded, 72 hours is allowed to the gross gamma activity rate to within the limit. The 72 hour Completion Time is reasonable, based on judgment, the time required to complete the Required Action, the large margins associated with permissible dose and exposure limits, and the low probability of a Main Condenser Offgas System rupture. B.l. B.2. and B.3 If the gross gamma activity rate is not restored to within the limits in the associated Completion Time, all main steam lines or the SJAE must be isolated. This isolates the Main Condenser Offgas System from the source of the radioactive steam. The main steam lines are considered isolated if at least one.main steam isolation valve in each main steam line is closed, and at least one main steam line drain valve in each drain line inboard of the main steam isolation valves is closed. The 12 hour Completion Time is reasonable, based on operating experience, to perform the actions from full power conditions in an orderly manner and without challenging unit systems. An alternative to Required Actions B.l and B.2 is to place the unit in a MODE in which the overall plant risk is minimized. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant .risk continued B 3.7-23 Revision No. 66 BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 B.l. B.2. and B.3 (continued) Main Condenser Offgas B 3.7.5 in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. SR 3.7.5.1 This SR requires an isotopic analysis of an offgas sample to ensure that the required limits are satisfied. The noble gases to be sampled are Xe-133, Xe-135, Xe-138, Kr-85m, Kr-87, and Kr-88. If the measured rate of radioactivity increases significantly (by 50% after for expected increases due to changes {n THERMAL POWER), an isotopic analysis is also performed within 4 hours after the increase is noted, to ensure that the increase is not indicative of a sustained increase in the radioactivity rate. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated and the SJAE is in .operation.* Only in thts condition can radioactive fission gases be in the Main Condenser System at significant rates. 1. UFSAR, Section 9.4.5. 2. 10 CFR -100. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.7.-24 Revision No. 86 Main Turbine Bypass System B 3.7.6 B 3.7 Plant SYSTEMS B 3.7.6 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit startup, sudden load reduction, and cboldown. It allows excess steam flow from the reactor to the condenser without going through the turbine. The bypass capacity of the system is 22.4% of the Nuclear Steam Supply System rated steam flow. Sudden load reduciions within the . capacity of the steam bypass can be accommodated without safety relief valves opening or a reactor scram. The Main Turbine Bypass System consists of nine modulating type hydraulically actuated bypass valves mounted on a valve manifold. The manifold is connected with two steam lines to the four main steam lines upstream of the turbine stop valves. The bypass valves are controlled by the bypass control function of the Pressure Regulator and Turbine Generator Control System, as discussed in the UFSAR, Section 7.11.3 (Ref. 1). The bypass valves are normally closed. However, if the total steam flow signal exceeds the turbine control valve flow signal of the Pressure Regulator and Turbine Generator Control System, the bypass control function will output a bypass flow signal to bypass valves. The bypass valves will then open sequentially to bypass the excess flow through connecting piping and a pressure reducing to the condenser. APPLICABLE The Main Turbine Bypass System is expected to function SAFETY ANALYSES during the electrical load rejection transient, the turbine trip transient, and the feedwater controller failure maximum demand transient, as described in the UFSAR, PBAPS UNIT 2 Section 14.5.1.1 (Ref. 2), Section 14.5.1.2.1 (Ref. 3), and Section 14.5.2.2 (Ref. 4). However, the feedwater controller maximum demand transient is the limiting licensing basis transient which defines the MCPR operating limit if the Main Turbine Bypass System is inoperable. Opening the bypass valves during the pressurization events mitigates the increase in reactor vessel pressure, which affects the MCPR during the event. The Main Turbine Bypass System satisfies Criterion 3 of the NRC Policy Statement. (continued) B 3.7-25 Revision No. 136 BASES (continued) Main Turbine Bypass System B 3.7.6 LCD The Main Bypass System is required to be OPERABLE to limit peak pressure in the main steam lines and maintain reactor pressure within acceptable '1 imi ts during events that cause rapid pressurization, so that the Safety Limit MCPR is not exceeded. With the Main Turbine Bypass System inoperable, modifications to the APLHGR operating limits (LCD 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), the MCPR operating limits (LCD 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and the LHGR operating limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)") may be applied to allow this LCO to be met. The operating limits for the inoperable Main Turbine Bypass System are specified in the COLR. An OPERABLE Main Turbine Bypass System requires the minimum number of bypass valves, specified in the COLR, to open iri response to increasing main steam line pressure. This response is within the assumptions of the applicable analyses (Refs. 2, 3, and 4). APPLICABILITY ACTIONS PBAPS UNIT 2 The Main Turbine Bypass System is required to be OPERABLE at 23% RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the applicable safety analyses transients. As discussed in the Base*s for LCD 3.2.3, "LINEAR .HEAT GENERATION.RATE (LHGR)," and LCO 3.2.2, sufficient margin to these limiis exists 23% RTP. Therefore, these requi.rements are only necessary when operating at br above this power level. If the Main Turbine Bypass Sistem'is inoperable (one or more required bypass v*alves as specified in the COLR inoperable), or the required thermar operating limits for an inoperable Main Bypass as in the COLR1 are not applied, the assumptions of the design basis transient analyses may not be met .. Under such circumstances, prompt action taken to restore the Main Turbine Bypass System to OPERABLE or adjust the thermal operating limits accordihgly. The 2 hour Completion Time is reasonable, based on the time to complete the Required. Action and low probability of an event occurring during . th.is requiring the Main' Turbine Bypass System. continued B 3.7-26 Revision No. 114 BASES Main Turbine Bypass System B 3.7.6 ACTIONS B.1 (continued) SU RV EI LLANCE REQUIREMENTS PBAPS UN IT 2 If the Main Turbine Bypass System cannot be restored to OPERABLE status or the required thermal operating limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 23% RTP. As discussed in the Applicability section, operation at< 23% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the applicable safety analyses transients. The 4 hour Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner without challenging unit systems. SR 3.7.6.1 Cycling each main turbine bypass valve through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will function when required. The Surven lance Frequency is controlled under the Survei 11 ance Frequency Control Program. SR 3.7:6.2 The Maih Turbine Bypass System is required to actuate automatically to perform its design function. This SR that, with the system initiation signals, the valves will actuate to their required position. The Surveillance Frequency is. controlled under the Surveiilance Frequency Control Program. continued B3.7-27 Revision No. 114 BASES SU RV E ILLA NC E REQUIREMENTS (continued) REFERENCES PBAPS UN IT 2 SR 3.7.6.3 Main Turbine Bypass System .B 3.7.6 This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analyses. The response time limits are specified in COLR. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 7.11.3. 2. UFSAR, Section 14.5.1.1. 3. UFSAR, Section 14. 5. 1. 2. 1. 4. UFSAR, Section 14.5.2.2. 5. Deleted B 3.7-28 Revision No. 111 Spent Fuel Storage Pool Water Level B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Spent Fuel Storage Pool Water Level BASES BACKGROUND APPLICABLE SAFETY ANALYSES LCO PBAPS UNIT 2 The minimum water level in the spent fuel storage pool meets the assumptions of iodine decontamination factors following a fuel handling accident. A general description of the spent fuel storage pool design is found in the UFSAR, Section 10.3 (Ref. 1). The assumptions of the fuel handling accident are found in the UFSAR, Section 14.6.4 (Ref. 2). The water level above the irradiated fuel assemblies is an implicit assumption of the fuel handling accident. A fuel handling accident is evaluated to ensure that the radiological consequences are well below the guidelines set forth in 10 CFR 50.67 (Ref. 3) as modified by Regulatory Guide 1.183, Table 6. A fuel handling accident could release a fraction of the fission product inventory by breaching the fuel rod cladding as discussed in Reference 2. The fuel handling accident is evaluated for the dropping of an irradiated fuel assembly onto the reactor core. The consequences of a fuel handling accideht over the spent fuel storage pool are less severe than those of the fuel handling accident over the reactor core. The water level in the spent fuel storage pool provides for absorption of water soluble fission product gases before being released_to the secondary containment atmosphere. Noble gases are not retained in the water and particulates are retained in the water (RG 1.183, Appendix B, Item 3). The spent fuel storage pool water level satisfies Criteria 2 and 3 of the NRC Policy Statement. The specified water level (232 ft 3 inches plant elevation, which is equivalent to 22 ft over the top of irradiated fuel assemblies seated in the spent fuel storage pool racks) preserves the assumptions of the fuel handling accident analysis (Ref. 2). As such, it is the minimum required for fuel movement the spent fuel storage pool. (continued) B 3.7-29 Revision No. 75 BASES (continued) APPLICABILITY ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES PB'APS UN IT 2 Spent Fuel Storage Pool Water Level B 3.7.7 This LCO applies during movement of fuel assemblies in the spent fuel storage pool si nee the potential for a rel ease of fission products exists. Required Action A.l is modified by a Note indicating that LCO 3.0.3 does not apply. If moving fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of fuel assemblies is not a sufficient reason to require a reactor shutdown. When the initial conditions for an accident cannot be met, action must be taken to preclude the accident from occurring. If the spent fuel storage pool level is less than required, the movement of fuel assemblies in the spent fuel storage pool is suspended immediately. Suspension of this activity shall not preclude completion of movement of a fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring. SR 3.7.7.1 This SR verifies that sufficient water is available in the event of a fuel handling accident. The water level in the spent fuel storage pool must be checked periodically. The Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 10.3. 2. UFSAR, Section 14.6.4. 3. 10 CFR 50.67. B 3.7-30 Revision No. 86 AC Sources -Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources-Operating. BASES BACKGROUND PBAPS UN IT 2 The unit AC sources for the Class lE AC Electrical Power Distribution System consist of the offsite power sources, and the onsite standby power sources (diesel generators (DGs)). As required by UFSAR Sections 1.5 and 8.4.2 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems. The Class lE AC distribution system is divided into redundant load groups, so loss of any one group does not prevent the minimum safety functions from being performed. Each load group has connections to two qualified circuits that connect the unit to multiple offsite power supplies and a single Dq. The two qualified circuits between the offsite transmission network and the onsite Class lE AC Electrical Power Distribution System are by multiple, independent offsite power One of these qualified circuits can be connected to either Of two offsite sources: the preferred offsite source is the 230 kV Nottingham-Cooper line which supplies the plant through the 230/13.8 kV startup and emergency auxiliary transformer 2; the alternate offsite source is the auto-transformer (500/230 kV) at North which feeds a 230/13.8 kV regulating transformer (startup and emergency auxiliary tr-ans former no. 3), the 3SU regulating transformer and the switchgear. The aligned source is further stepped d6wn via the 2SU transformer switchgear through the kV emergency auxiliary no. 2. The circuit can be. connected to either of two offsite sources: the preferred offsite'source is the*230 kV Peach Bottom-Newlinville which a Z30/13.8 kV trinsformer (startup transformer no. 343); the alternate offsite source is the (500/230 kV) at North Substation which feeds a 230/13.8 kV regulating transformer (startup and transformer no. 3) 3SU regulating transformer switchgear. The aligned source is* further stepped down via the transformer switchgear continued B 3.8-1 Revision No. 82 BASES BACKGROUND (continued) PBAPS UN IT 2 AC Sources -Operating B 3.8.1 through the 13.2/4.16 kV emergency auxiliary transformer no. 3. In addition, the alternate source can only be used to meet the requirements of one offsite circuit. A detailed description of the offsite power network and circuits to the onsite Class lE ESF buses is found in the UFSAR, Sections 8.3 and 8.4 (Ref. 2). A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class lE emergency bus or buses. The determination of the operability of a qualified source of offsite power is dependent upon grid and plant factors that, when taken together, describe the design basis calculation requirements for voltage regulation. The combination of factors ensures that the offsite source(s), which provide power to the plant emergency buses, will be fully capable of supporting the equipment required to achieve and maintain safe shutdown during postulated accidents and transients. The plant consist of the status of the Startup Transformers' (2SU, 343SU, 3SU) load tap (LTC's), the status of the Safeguard Transformers (2EA and 3EA) and the alignment of the emergency buses on the Safeguard Buses (00A019 and OOA020). For an offsite source to be considered its respective LTC's must be in service and in automatic. The grid factors consist of actual grid voltage levels (real time) and the post trip contingency voltage drop percentage value; The minimum offsite source voltage levels are established by the voltage regulatiori calculation. The transmission system operator (TSO) will notify* Peach Bottom when* an agreed upon 1 imit is approached. post trip contingency percentage voltage_drop is a calculated value deterll)ined by the TSO that would occur as a r_esult of fhe tripping of one Peach Bottom generator. The* TSO wi 11 n9tify Peach Bottom* when an agreed upon l i init is exceeded. The voltage regu1ation calculation establishes the acceptable voltage drop based upon plant configuration. continued . . B 3.8-2 *Revision No. 90 BASES BACKGROUND (continued) PBAPS UNIT 2 AC B 3.8.1 Due to the 3SU source being derived from the tertiary of the #l. Auto Transformer, its operability is influenced by both the 500 kV and 230 kV systems. The 2SU and 343SU sources operability is influenced only by the 230 kV system. Peach Bottom unit post trip contingency voltage drop percentage calculations are performed by the PJM Energy Management System (EMS). The PJM EMS consists of a primary and backup system. Peach Bottom will be notified if the real time contingency analysis capability of PJM is lost. Upon receipt of this notification, Peach Bottom is to request PJM to provide an
• assessment of the current condition of the grid based on the tools that PJM has available. The determination of the operability of the offsite sources would consider the assessment provided by PJM and whether the current condition of the grid is bounded by the grid studies previously performed for Peach Bottom. Variations to any of these factors is permissible, usually at the sacrifice of another factor, based on plant conditions. Specifics regarding these variations are controlled by plant or by condition specific design calculations. A description of the Unit 3 offsite power sources is provided in the Bases for Unit 3 LCD 3.8.1, "AC Operating," The description is identical with the exception that the two offsite circuits provide power to the Unit 3 4 kV emergency buses Ci .e., each Unit 2 offsite circuit is common to its respective Unit 3 offsite circuit except for the 4 kV emergency bus feeder breakers). continued B 3.8-2a Revision No. 90 BASES BACKGROUND (continued) PBAPS UNIT 2 AC Sources-Operating B 3.8.1 The onsite standby power source for the four 4 kV emergency buses in each unit consists of four DGs. The four DGs provide onsite standby power for both Unit 2 and Unit 3. Each DG provides standby power to two 4 kV emergency one associated with Unit 2 and one associated with Unit 3. A DG starts automatically on a loss of coolant accident (LOCA) signal (i.e., low reactor water level signal or high drywell pressure signal) from either Unit 2 or Unit 3 or an emergency bus degraded voltage or undervoltage signal.* After the DG has started, it automatically ties to its respective bus after offsite power is tripped as a consequence of emergency bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs also start and operate in the standby mode tying to the emergency bus on a LOCA signal alone. Following the trip of offsite power, all loads are stripped from the emergency bus. When the DG is tied to the emergency bus, loads are then sequentially connected to its respective emergency bus by individual timers associated with each auto-connected load following a permissive from a voltage relay monitoring each emergency bus. In the event of a loss of both offsite power sources, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown of both units and to mitigate the consequences of a Design Basis Accident (OBA) such as a LOCA. Within 59 seconds after the initiating signal is received, all automatically connected loads needed to recover the unit or maintain it in a safe condition are returned to The failure of any*one DG does not impair safe shutdown because each DG serves an independent, redundant 4 kV emergency bus for each unit. The remaining DGs and emergency buses have sufficient capability to mitigate .the consequences of a DBA, support the shutdown of the other unit, and maintain both units in a safe condition. Ratings for the DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 12). Each of the four DGs have the following ratings: a. 2600 kW-continuous, b. 3_000 kW-2000 hours, c . 310 0 kW...:... 2 0 0 hours , d. 3250 kW-30 minutes. (continued) B 3.8-3 Revision No. 114 BASES (continued) AC B 3.8.1 APPLICABLE The initial conditions of OBA and transient analyses in the SAFETY ANALYSES UFSAR, Chapter 14 (Ref. 4), assume ESF systems are OPERABLE. LCO PBAPS UNIT 2 The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS}, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.5, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) System; and Section 3.6, Containment Systems. The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining the onsite or offsite AC sources OPERABLE during accident conditions in the event of: a. An assumed loss of all offsite power or all onsite AC power; and b. A worst case single failure.
• AC sources satisfy Criterion 3 of the NRC Pol icy Stat,ement. Two qualified circuits between the offsite transmission network and the onsite Class IE Distribution System and four separate and independent DGs ensure ava i1 ability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an abnormal operational transient or a postulated DBA. In addition, since some equipment required by Unit 2 is powered from Unit 3 sources (i.e., Standby Gas Treatment (SGT) System, emergency heat sink components, and Unit 3 125 VDC battery chargers), qualified circuit(s) between the offsite transmission network and the Unit 3 onsite Class IE AC electrical power distribution subsystem(s) needed to support this equipment must also be OPERABLE. An OPERABLE qualified Unit 2 offsite circuit consists of the incoming breaker and disconnect to the startup and emergency auxiliary transformer, the respective circuit path to the emergency auxiliary transformer, and the circuit path to at least three Unit 2 4 kV emergency buses including feeder (continued) B 3.8-4 Revision No. O BASES LCO (continued) PBAPS UNIT 2 AC Sources -Operating B 3.8.1 breakers to the three Unit 2 4 kV emergency buses. If at least one of the two circuits does not provide power or is not capable of providing power to all four Unit 2 4 kV emergency buses, then the Unit 2 4 kV emergency buses that each circuit powers or is capable of powering cannot all be the same (i.e., two feeder breakers on one Unit 2 4 kV emergency bus cannot be inoperable). If two feeder breakers are inoperable on the same 4kV bus, then Condition A (and Condition E if an inoperable DG exists) must be entered for one offsite circuit being inoperable even if both offsite circuits otherwise provide power or are capable of providing power to the other three 4kV buses. An OPERABLE qualified Unit 3 offsite circuit's requirements are the same as the Unit 2 circuit's requirements, except that the circuit path, including the feeder breakers, is to the Unit 3 4 kV emergency buses required to be OPERABLE by LCO 3.8.7, "Distribution Systems-Operating." Each offsite circuit must be capable of .maintaining rated frequency and voltage, and iccepting required loads during an accident, while connecte_d to the emergency buses. Each DG has two ventilation supply fans; a main supply fan and a supplemental supply fan. The supplemental supply fan provid_es additional . air cooling to the generator area. Whenever outside air temperature is greater than or equal to 80° F, each DG's main supply fan and supplemental. supply fan are requi;red to be OPERABLE for the associated DG to be Whenever, outside air temperature is less than 80° F, the supplemental supply fan is not required be OPERABLE for the associated DG to be OPERABLE, however, the main *supply fan is required to be.OPERABLE for the as_sociated DG to be OPERABLE. Each DG must be capable. of starting, accelerating to rated speed and voltage, and corinecting to its Unit 2 4 kV emergency_ bus on detect.ion of bus undervol tage. This s_equence must be acc.ompl'ished within 10 seconds. Each.DG must also be capable of accepting requir.ed loads within the assumed loading sequence intervals, and niust continue to operate until .otfsite power restored to the emergency buses. These capabilities are required to be met from a. variety of initial conditions,. such as DG in standby with the engine ,hot_ and DG in standby with the engine at ambient condition. Additional DG capabilities must be demonstrated to meet required Surveillances, e.g., capability of the DG t? to standby on an*ECCS"signal while operating _in* pa.rallel test. mode.* Proper sequencing of {ncluding tripping of all loads, is a required function for DG OPERABILITY. (continued) B 3.8-5 Revision No. 73 BASES LCD (continued). APPLICABILITY .ACTIONS PBAPS UN IT 2 -----------------------, AC Sources-Operating B 3.8.1 In addition, since some equipment required by Unit 2 is powered from Unit 3 sources, the DG(s) capable of supplying the Unit 3 onsite Class lE AC electrical power distribution subsystem(s) needed to support this equipment must be OPERABLE. The OPERABILITY requirements for these DGs are the same as described above,* except that each required DG must be capable of connecting to its respective Unit 3 4 kV emergency bus. (In addition, the Unit 3 ECCS initiation logic SRs are not applicable, as described in SR 3.8.1.21 Bases.) The AC sources must be separate and independent (to the extent possible) of other AC sources. For the DGs, the separation and independence are complete. For the offsite AC s6urces, the and independence are to the _extent practical. A circuit may be connected to more than one 4 kV emergency bus division, with automatic transfer capability to the other circuit OPERABLE, and not violate separation criteria. A circuit that is not connected to at least three 4 kV emergency buses is required to have OPERABLE automatic transfer interlock mechanisms such that it can provide power to at least three 4 kV emergency buses to support OPERABILITY of that circuit. The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:
• a. Acceptable fuel design limits and reactor coolant pressure boundary limits ar-e not exceeded as a result of abnormal operational transients; and b. Adequate core coolirig is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated OBA. The AC power requirements for MODES 4 and 5 are covered in LCD 3.8.2, "AC Sources-Shutdown." A Note prohibits the application of LCD 3.0.4.b to an inoperable DG. There is an* increased risk associated with entering a MODE or other specified condition in the Applicability with an inOperable DG and the provisions of LCD which al into a MODE or other specified condition in the Applicability with the LCD not met after performance risk assessment addressing inoperable systems and components, should not be applied in this circumstance. To a highly reliable remains with one offsite circuit inoperable, it is necessary to verify the. availability of the remainiog offsite circuits on a more frequent Since the Required Action only "perform," a failure of SR 3.8.1.1 acceptance criteria does continued B 3.8-6 Revision 52*

BASES ACTIONS PBAPS UNIT 2 A.I (continued) AC Sources-Operating B 3.8.I not result in a Required Action not met. However, if a second circuit fails SR 3.8.I.I, the second offsite circuit is inoperable, and Condition.D, for two offsite circuits inoperable, is entered. Required Action. A.2, which only applies if one 4 kV emergency bus cannot be powered from any offsite source, is intended to provide assurance that an event with a coincident single failure of the associated DG does not result in a complete loss of safety function of critical systems. These features (e.g., system, subsystem, division, component, or device) are designed to be powered from redundant safety related 4 kV emergency buses. Redundant required features failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has no offsite power. The Completion Time for Required Action A.2 is intended to allow time for the operator to evaluate and repair any discovered inoperabilities. This Completion Time also allows an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both: a. A 4 kV emergency bus has no offsite power supplying its loads; and b. A redundant required feature on another 4 kV emergency bus is inoperable. If, at any time during the existence of this Condition. (one offsite circuit inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked. Discovering no offsite power to one 4 kV emergency bus of the onsite Class IE Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with any other emergency bus that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before the unit is subjected to transients associated with shutdown. (continued) B 3.8-7 .Revision 5 BASES ACTIONS PBAPS UN IT 2 A.2 (continued) AC Sources -Operating B 3.8.1 The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class lE Distribution System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 hour Completion Time takes into account the component OPERABILITY of the redundant to the inoperable required Additionally, the 24 .hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a OBA occurring during this period. The 4 kV emergency bui design and loading is sufficient to allow operation to continue in Condition A for a period not to exceed 7 days. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems .. In this condition, however, the remaining OPERABLE offsite circuits and the four DGs are adequate to supply to the onsite Class lE System. 7 day Completion takes into account the redundancy, capacity,. and capability of the remaining AC sources, *reasonable* time for repairs, and the low probability of a OBA this period. continued B 3.8-8 Revision No .. 85 BASES ACTIONS (continued) PBAPS UN IT 2 AC Sources-Operating B 3.8.1 The 33 kV Conowingo Tie-Line, using a separate 33/13.8 kV transformer, can be used to supply the circuit normally supplied ,by startup and emergency auxiliary transformer no. 2. While not a qualified circuit, this alternate source is a direct tie to the Conowingo Hydro Station that provides a highly reliable source of power because: the line and transformers at both ends of the line are dedicated to the support of PBAPS; the tie line is not subject to damage from adverse weather conditions; and, the tie line can be isolated from other parts of the grid when necessary to ensure its availability and stability to support PBAPS. The availability of this highly reliable source of offsite power permits an extension of the allowable out of service time for a DG to 14 days from the discovery of failure to meet LCO 3.8.1.a or b (per Required Action B.5). Therefore, when a DG -is inoperable, it is necessary to verify the availability of the Conowingo Tie-Line immediately and once per 12 hours thereafter. The Completion Time of "Immediately" reflects the fact that in order to ensure that the full 14 day Completion Time of Required Action B.5 is available for completing preplanned of a DG, prudent plant practice at PBAPS dictates that the availability of the Conowingo Tie-Line be verified prior to making a DG inoperable for preplanned The Conowingo-Tie-Line is available and satisfies the requirements of Required Action B.l if: 11 the Conowingo line is iupplying power to the l3.8kV SBO Switchgear OOA306; 2) all equipment required, per SE-11, to connect power from the Conowingo Tie-Line to the emergency 4kV buses and to isolate all non-SBO loads from the Conowingo Tie-Line is available and accessible; and 3) communications with the Conowingo control room _indicate that reqyired equipment at_ Conowingo is -'If Retjuired B.l is not met or the continued -B 3.8-9 Rev-fsion NO. 85 BASES ACTIONS PBAPS UNIT 2 B.l (continued) AC Sources -Operating B 3.8.1 status of the Conowingo Tie-Line changes after Required Action B.l is initially met, Condition C must be immediately entered. To ensure a highly reliable power source remains with one DG inoperable, it is necessary to verify the availability of the required offsite circuits on a more frequent. basis. S_ince the Required Action only specifies "perform," a* failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered. Required Action B.3 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss.of safety function of critical systems. These features are designed to be powered from redundant safety related 4 kV emergency buses. Redundant required features failures consist of inoperable features associated with an emergency bus redundant to the emergency bus that has an inoperable DG. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both: a. An inoperable DG exists; and* b. A redundant required feature on another 4 kV emergency bus is inoperable. If, at any time during the existence of this Condition (one DG inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked. Discovering one DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DGs results in (continued) B 3.8-10 Revision 5 BASES ACTIONS PBAPS UN IT 2 -B.3 (continued) AC Sources-Operating B 3.8.1 *starting the Completion Time for the Required Action. Four hours from the discovery of these events existing is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown. The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class lE -Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low -probability of a OBA occurring during this period. B.4.1 and B.4.2 Required Action B.4.1 provides an allowance to avoid u ri n e c es s a r y t e s t i n g o f 0 P E RAB LE D Gs . If i t ca n b e determined that the cause of the inoperable DG does not exist on the OPERABLE DGs,*SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), they are declared inoperable upon d_iscovery,_and Condition For Hof LCD is entered, as applicable. Once the failure is repaired, and the common cause failure no longer exists, Required Action B.4.1 is satisfied.* If the cause of the initial inoperable DG carinot be not to exist on the remaining DGs, of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DGs. In the event the inoperable DG is _restored to OPERABLE status prior to.completing either B.4.1 or B.4.2, the PBAPS Corrective Action Program will continue to evaluate the I common cause possibility, This continued evaluation, however, is no longer required the 24 hour constraint imposed while in Conditirin B. According to Generic Letter 84-15 (Ref. 5), 24 hours is a reasonable time to confirm that the OPERABLE DGs are not affected by the sime problem as the inoperable DG. continued B 3.8-11 Revision 60 BASES AC Sources -Operating B 3.8.1 ACTIONS B.5 {continued) PBAPS UNIT 2 The availability of the Conowingo Tie-Line provides an additional source which permits operation to continue in Condition B for a period that should not exceed 14 days from discovery of the failure to meet LCO 3.8.1.a or b. In Condition B, the remaining OPERABLE DGs and the normal offsite circuits are adequate to supply electrical power to the onsite Class IE Distribution System. The Completion Time of Required Action B.5 takes into account the enhanced reliability and availability of offsite sources due to the Conowingo Tie-Line, the capacity, and capability of the other remaining AC sources, reasonable time for repairs of the affected DG, and low probability of a DBA occurring during this period. The Completion Time for Required Action B.5 also establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1.a orb. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 7 days. This situation could lead to a total of 14 days, since initial failure of LCO 3.8.1.a or b, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 7 days (for a total of 21 days) allowed prior to complete restoration of the LCO. The 14 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet LCO 3.8.1.a orb. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The 14 day Completion Time would also limit the maximum time a DG is inoperable if the status of the Conowingo Tie-Line changes from being available to being not available (this is discussed in Required Action C.l Bases discussion). As in Required Action B.3, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that the LCO was initially not met, instead of the time that Condition B was entered. {continued) B 3.8-12 Rev i s ion No. 1 J BASES ACTIONS PBAPS UNIT 2 B.5 (continued) AC B 3.8. l The extended Completion Time for restoration of an inoperable DG afforded by the availability of the Conowingo Tie-Line is intended to allow completion of a diesel generator overhaul; however, subject to the diesel generator reliability program, INPO performance criteria, and good operating practices, using the extended Completion Time is permitted for *other reasons. Activities or conditions that increase the prooability of a loss of offsite power (i.e., switchyard maintenance or severe weather) should be considered when scheduling a diesel generator outage. In addition, the effect of other inoperable plant equipment should be considered when scheduling a diesel generator outage. If the avail ability of the Conowingo Tie-Line is not verified within the Completion Time of Required Action B.I, or if the status of the Conowingo Tie-Line changes after Required Action B.l is initially met, the DG must be restored to OPERABLE status within 7 days. The 7 day Completion Time begins upon entry into Condition C (i.e., upon discovery of failure to meet Required Action B.I). However, the total time to restore an inoperable PG cannot exceed 14 days (per the Completion Time of Required Action B.5). ..-. The 4 kV emergency bus design and loading is sufficient to allow operation to continue in Condition B for a period that should not exceed 7 days, if .the Conowingo Tie-Line is not availabl°e (refer to Required Action B.l Bases discussion) .. In Condition C, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the . onsite .class lE .. Distribution System. The 7 day Completion Time takes into account the redundancy, capacity, and *

• capability of the remaining AC .sources, reasonable time for repairs, and low probability oLa DBA occurring during this period. * (continued) B 3.8-13 Revision No. 0 BASES ACTIONS . (continued) PBAPS UNIT 2 D.l and D.2 AC 83.8.1 Required Action D.l addresses actions to be taken in the event of inoperability of redundant required features concurrent with inoperability of two or more offsite circuits. Required Action 0.1 reduces the vulnerability to a loss of function. The Completion Time for taking these actions is reduced to 12 hours from that allowed with one 4 kV emergency bus without offsite power (Required Action A.2). The rationale for the reduction to 12 hours is that Regulatory Guide 1.93 (Ref. 6) allows a Completion Time of 24 hours for two offsite circuits inoperable, based upon the assumption that two complete safety divisions are OPERABLE. (While this Action allows more than two circuits to be inoperable, Regulatory Guide 1.93 assumed two circuits were all that were required by the LCD, and a loss of those two circuits resulted in a loss of all offsite power to the Class IE AC Electrical Power Distribution System. Thus, with the Peach Bottom Atomic Power Station design, a loss of more than two offsite circuits results in the same conditions assumed in Regulatory Gui de I. 93. ) When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours is appropriate. These features are designed with redundant safety related 4 kV emergency buses. Redundant required features failures consist of any of these features that are inoperable because any is on an emergency bus redundant to an emergency bus with inoperable offsite circuits. The Completion Time for Required Action D.l is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also a 11 ows for an except ion to the normal "ti me zero" for
• beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both: *
• a. Two or more offsite circuits*are inoperable; and b. A required feature is inoperable. * (continued) B 3.8-14 Revision No. O ----------------------------------*----------------------------

' BASES ACTIONS D.1 and D.2 (continued) AC B 3.8.1 If, at any time during the existence of this Condition (two or more offsite circuits inoperable i.e., any combination of Unit 2 and Unit 3 offsite circuits inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked. According to Regulatory Guide 1.93 (Ref. 6), operation may. continue in Condftion D for a period that should not exceed 24 hours. This level of degradation means that the offsite electrical power system may not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the .immediately accessible offsite power sources. Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable. However, two factors tend to decrease the severity of this degradation level: a. The configuration of the redundant AC electrical power system that remains avai"lable is not susceptible to a single bus or switching failure; and b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite Ac* source. With two or more of the offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case.single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour Completion Time provides a period of time to effect restoration of all but one of the offsite circuits conunensurate with the importance of maintaining an AC electrica*l power system capable of meeting its design criteria. (continued) e*3.s-1s Revision No. 0 BASES ACTIONS PBAPS UNIT 2

• AC Sources-Operating . B 3.8.l D.l and D.2 (continued) According to Regulatory Guide 1.93 (Ref. 6), with the available offsite AC sources two less than required by the LCO, operation may continue for 24 hours. If all offsite sources are restored within 24 hours, unrestricted operation may continue. If all but one offsite source is restored within 24 hours, power operation continues in accordance with Condition A. E. l and E.2 Pursuant to LCO 3.0.6, the Distribution Systems-Operating ACTIONS would not be entered even if all AC sources to it
• were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition E are modified by a Note to indicate that when Condition E is entered with no AC source to any 4 kV emergency bus, ACTIONS for LCO 3.8.7, "Distribution Systems-Operating," must be immediately entered. This allows Condition E to provide requirements for the loss of the offsite circuit and one DG without regard to whether a 4 kV emergency bus is de-energized. LCO 3.8.7 provides the appropriate restrictions for a de-energized 4 kV emergency bus. According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition E for a period that should not exceed 12 hours. In Condition E, individual redundancy is lost in
• both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the
• reliability of the power systems in this Condition may appear higher than that in Condition D (loss of two or more offsite circuits). Thh difference in.reliability is offset . by the susceptibility of this power system configuration to a single bus or switching .failure. The 12 hour Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a OBA occurring during this period. (continued) B 3.8-16 Revision No. o BASES ACTIONS (continued) PBAPS UN IT 2 AC Sources -Operating B 3.8.1 With two or more DGs inoperable, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown, (The immediate shutdown could cause grid instability, which could result in a total loss of AC power.) Since any inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the* risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation. According to Regulatory Guide 1.93 (Ref. 6), with two or more DGs inoperable, operation may continue for a period that should not exceed 2 hours. (Regulatory Guide 1.93 assumed the unit has two DGs. Thus, a loss of both DGs results in a total loss of onsite power. Therefore, a loss of more than two DGs, in the Peach Bottom Atomic Power Station design, results in degradation no worse than that assumed in Regulatory Guide 1.93.) If the inoperable AC electrical power source(s) cannot be restored to OPERABLE status within the associated Completion Time (Required Action and associated Completion Time of Condition A, C, D, E, or F not met; or Required Action B.2, B.3, B.4.1, B.4.2, or B.5 and associated Completion Time not met), the unit must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 11) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. continued B 3.8-17 Revision No. 66 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 H.1 AC Sources -Operating B 3.8.l Condition H corresponds to a level of degradation in which redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system may cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown. The AC sources are designed to permit inspection and testing of all important areas and features, especially those that have a stan_dby function, in accordance with UFSAR, Section 1.5.1 (Ref. 7). Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are consistent with the recommendations of Regulatory Guide 1. 9 (Ref. 3), Regulatory Guide 1.108 (Ref. 8), and Regulatory Guide 1.137 (Ref. 9). As Noted at the of the SRs, SR 3*.8.l.l through SR 3.8.1.20 are applicable.only to the Unit 2 AC sources and SR 3._8.1.21 is applicable only to the Unit 3 AC sources. Where the SRs herein specify voltage and frequency toleranc*es, the following summary is applicable. The minimum steady state output voltage of 4160 V corresponds to the minimum steady state voltage analyzed in the PBAPS emergency bG voltage regulation study. This value allows for voltage drops to motors and other equipment down through the 120 V specified maximum steady state output voltage .. of 4400 Vis .. equal to the*max.imum steady state operating voltage .specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals* of 4000 v motors is no more than the maximum rated steady state operating voltages. The specified minimum and.maximum f.requencies of the DG are 5B.8 Hz and 61.2 Hz, respectively. These values are equal to +/- 2% of the -60 Hz nominal frequency and are derived from the found in Regulatory Guide 1.9 (Ref. 3). The surve_iliance requirement allowance of +/- 2% for the EDG fr,equency is intended to _allow, for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. (continued) . B 3.8-18 Revision No. 71 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS U.N IT 2 SR. 3.8.1.1 AC Sources-Operating B 3.8.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source and that appropriate independence of offsite circuits is maintained. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition. To minimize the wear on moving parts that do not get lubritated when the engine is not running, these SRs have been modified by a Note (Note 2 for SR 3.8.1.2 and Note 1 for SR 3.8.1.7) to indicate that all DG starts for these Surveillances may be by an engirie prelube period and followed by a warmup prior to loading. For the purposes of this testing, the DGs are started from standby conditions. Staridby conditions for a DG mean that the diesel coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations. In order to reduce stress and wear on diesel the manufacturer recommends a modified start in.which the starting speed of DGs*is-limited, warmup is limited to lbwer Speed; and the are gradual1y to synchronous prior to.loading. These start procedures are the intent of Note j'to SR 3.8.1.2, which is only app.licable when such modified start procedures are recommended by the manufacturer.
• SR 3.8.1.7 requires that the DG starts from standby and voltage and within lO seconds.* The minimum and frequency stated in the SR are those to ensure the
• continued B .3. 8-19 Revi.sion No. 86 J BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 AC Sources-Operating B 3.8.1 SR 3.8.1.2 and SR 3.8.1.7 (continued) DG can accept DBA loading while maintaining acceptable voltage and frequency levels. Stable operation at the nominal voltage and frequency values is also essential to establishing DG OPERABILITY, but a time constraifit is not imposed. This is because a typical DG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by load application. The surveillance requirement allowance of+/- 2% for the EDG frequency is intended to allow for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. This period may extend beyond the 10 second acceptance criteria and could be a cause for failing the SR. In lieu of a time constraint in the SR, PBAPS will monitor and trend the actual time to reach steady state operation as a means of ensuring there is no voltage regulator or governor degradation which could cause a DG to become inoperable. The 10 second start requirement supports the assumptions in the design basis LOCA analysis of UFSAR, 8.5 (Ref. 10). The 10 second start requirement is not to SR 3.8.1.2 (see Note 3 of SR 3.8.1.2), when a modified start procedure as described above is used. If a modified start is not used, the 10 second start requirement of SR 3.8.1.7 applies. Since SR 3.8.1.7 requires a 10 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This procedure is the intent of Note 1 of SR 3.8.1.2. To minimize testing of the DGs, Note 4 to SR 3.8.1.2 and Note 2 to SR 3.8.1.7 allow a single test (instead of two tests, one for each unit) to satisfy the requirements for. both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS *uN IT *2 SR 3.8.1.3 AC Sources-Operating B 3.8.1 This Surveillance verifies that the DGs are capable of synchronizing and accepting a load approximately equivalent to that corresponding to the continuous rating. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time *that the DG is connected to the offsite source. This Surveillance verifies, indirectly, that the DGs are capable of synchronizing and accepting loads equivalent to post accident loads. The DGs are tested at a load approximately equivalent to their continuous duty rating, even though the post accident loads exceed the continuous rating. This is acceptable regular surveillance testing at post accident loads is injurious to the DG, and imprudent because the same level of assurance in the ability of the DG to provide post accident loads can be by monitoring engine parameters during surveillance testing. The values of the testing parameters can then be qualitatively compared to expected values at post accident engine loads. In making this comparison it is necessary to consider the engine parameters as interrelated indicators of remaining DG capacity, *rather than independent indicators. The important engine parameters to be considered in making this comparis6n include, fuel rack position, scavenging air pressure, exhaust temperature and pressure, engine output, jacket water temperature, and lube oil temperature. With the DG operating at or near continuous rattng and the observed values of the above parameters* less than expected post accident values, a qualitative extrapolation which shows the DG is capable of accepting post accident loads can be made without detrimental testing. Although no power factor requirements are established by this SR, the DG is.norma.lly operated at a power factor between 0.8 lagging and 1.0. The Q.8 value is the design rating of the machine, while 1.0 is an operational limitation. The load band is provided to avoid routine* overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.8-21 Revision No .. 86 I BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.1.3. (continued) AC Sources -Operating B 3.8.1 Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are m1nimized. Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid. perturbations. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance. To minimize testing of the DGs, Note 5 allows a single test (instead of two tests, one for each to satisfy the requirements for both units, with the DG synchronized to the 4 kV emergency bus of Unit 2 for one periodic test and to the 4 kV emergency bus of Unit 3 during the next periodic test. This is allowed since the main purpose of the Surveillance, to ensure DG OPERABILITY, is still being verified on the proper frequency, and each unit's breaker control circuitry, which is only being tested every second test (due to the staggering of the tests), historically have a very low failure rate. Note 5 modifies the specified frequency for each unit's breaker control circuitry to the total of the combined Unit 2 and Unit 3 frequencies. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. In addition, if the test is scheduled to be performed on Unit 3, and the Unit 3 TS allowance that provides an exception to performing the test is used (i.e., when Unit 3 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note to Unit 3 SR 3.8.2.1 provides an exception to performing this test) or if it is not preferable to perform the test on a unit due to operational concerns (however time is not to exceed the total combined frequency plus grace), then the test shall be performed synchronized to the Unit 2 4 kV emergency bus. continued B 3.8-22 Revision No. 86 I BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 2 SR 3.8.1.4 AC Sources-Operating B 3.8.1 This allowance is acceptable provided that the associated unit's breaker control circuitry portion of the Surveillance is performed within the total combined frequency plus SR 3.0.2 allowed grace period or the next scheduled Surveillance after the Technical Specification allowance is no.longer applicable. This SR provides veri fi ca ti on that the level of fuel oil in the day tank is adequate for a minimum of 1 hour of DG operation at full load. The level, which includes margin to account for the unusable volume of oil, is expressed as an equivalent volume in gallons. The Sufveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.1.5 Microbiological foul.ing is a major cause of fuel oil degradation. There numerous bacteria that can in fuel oil and cause fouling, but all must have a water in 6rder to survive. Periodic removal of water from the fuel oil day tahks eliminates the necessary environment for bacterial survival. This is the most effective means of controllirig microbiological fouling. In addition; it elimiriates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources; inclDding condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel otl by bacteria. Frequent checking for and removal of* accumulated water minimizes fouling and provides data regardihg the wateftight integrity of the fuel .oil system. The Surveillance Frequency is controlled under the Survei 11 ance Frequency C0ntr61 Program ... This SR is for preventive maintenante. The presence bf water not necessarily represenf a failure of this SR provided that accumulated.water is during performance cif this *
• SR 3.8.1.6 This Surveillance demonstrates that required fuel oil transfer pump operates and automatically transfers fuel oil from its assocfated storage tank to its associated day tank. It is required to support continuous operation of standby sources. This Surveillance provides assurance that. continued B 3.8-23 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 2 SR 3.8.1.4 AC Sources -Operating B 3.8.1 This allowance is acceptable provided that the associated unit's breaker control circuitry portion of the Surveillance is performed within the total combined frequency plus SR 3.0.2 allowed grace period or the next scheduled Surveillance after the Technical Specification allowance is no longer applicable. This SR provides verification that the level of fuel oil in the day tank is adequate for a minimum of 1 hour of DG operation at full load., The level, which includes margin to account for the unusable volume of oil, is expressed as an equivalent volume in gallons. The Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil cause fouling, but all must have a water environment in order to survive. Periodic removal of water from the fuel oil day tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any bf sources; condensation, ground water, rain water, contaiTii nated fuel oil , and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and prbvides data regarding the watertight integrity of the fuel oil system .. The Surveillance is Cdntrol.led uhder the SurVeillante Frequency Program. This SR is for .preventive. maintenance. The presence of water does not necessarily represent a of provided that atcumulate.d water is renioved during p*erforniance of this s u' r v e i l 1 Cl n c e . ' ' ,, ' SR 3.8.1.6 This Survei 11 ance demonstrates that each ,required fuel oi 1 pump and automatically transfers fuel oil* from its.'associated storage tank to its associated day tank. It is t6 continu6us of standby power sources. This Surveillance provides assurance that continued B 3 .B-23 Revision No. 86 BASES -_ REQUIREMENTS -PBf\PS UNIT 2 -._ SR (continued) AC Sources -Operating B 3.8.1 the fuel oil transfer pump is OPERABLE, the_ fuel oil piping system is intact, the fuel delivery piping is not: obstructed, andthe controls and control systems for automatic.fuel transfer systems are OPERABLE. This 5R is modified by a Note. The note recognizes that manual actions for manually operating local hand valves and control switches associated with the DG fuel oil transfer system is limited to support transferring fuel between DGs, testing, and sampling These manual actions would *promptly restore the EDG fuel oil system to an automatic status since the actions are simple and straightforward. Credit for manual operator actions for maintaining operability must be controlled procedurally. These actions include a dedicated qualified individual and constant communication with main' control room licensed personnel. The Surveillance is controlled under the Surveillance Frequency Control_ Program. SR 3.8.1.8 Transfer of-each.4 kV emergency bus power supply from the normal offsite.circuit to the alternateoffsite circuit demonstrates the OPERABILITY of the alternate circuit di stri buti on network to power the shutdown 1 oads. The Surveillance Frequency is controlled under.the Surveillante Frequehcy Control Program .. -This SR.is modified by a Note. The reason for the Note is that, during operation with the reactor critical, of SR could cause perturbations to the electrical distribution systems that could challenge' continued steady state operation and, as a .result, plant safety systems .. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in Unii 3 Technical the applicable logic associated with Unit 3. Consequently, a test must be performed within the specified Frequency for _each unit. As the Surveillance represents separate tests, the Note -Cconti nued) B 3. 8-'24 -Revision No. 139 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.8.1.8 (continued) AC Sources -Operating B 3.8.1 specifying the restriction for not performing the test while the unit is in MODE 1 or 2 does not have applicability to Unit 3. The Note only applies to Unit 2, thus the Unit 2 Surveillance shall not be performed with Unit 2 in MODE 1 or 2. Credit may be taken for unplanned events that satisfy this SR. SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. The largest single load for each DG is a residual heat removal pump (2000 bhp). This Surveillance may be accomplished by: 1) tripping the DG output breakers with the DG carrying greater than or equal to its associated single largest load while paralleled to offsite power, or while solely supplying the bus, or 2) tripping its associated single largest post-accident load with the DG solely supplying the bus. Currently, the second option is the method PBAPS. utilizes because the first method will result in steady state operation outside the allowable voltage and frequency limits. Consistent with Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the diesel speed does not exceed the nominal (synchronous) speed plus 75% of the difference between nominal speed and the overspeed trip setpoint, or 115% of nominal speed, whichever is lower. The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 1.8 seconds specified for voltage and.the 2.4 seconds specified for frequency are equal to 60% and 80%, respectively, of the 3 second load sequence interval associated with sequencing the next load following the residual heat removal (RHR) pumps during an undervoltage on the bus concurrent with a LOCA. The voltage and frequency
• specified are conststent*with the design range of the * (continued) B 3.8-25 Revision No. I BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.1.9 (continued) AC Sources-Operating B 3.8.l equipment powered by the OG. SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c provide steady state voltage and frequency values to which the system must recover following load rejection. The surveillance requirement allowance of+/- 2% for the EOG frequency is intended to allow for EOG transient operation? during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by two Notes. Note 1 ensures that the OG is tested under load conditions that are as close to design basis conditions as possible. When synchronized with offsite power, testing should be performed at a power factor of 0.89. This power factor is representative of the actual inductive loading a OG would see under design basis accident conditions. Under certain conditions, however, Note 1 allows the Surveillance to be conducted at a power factor other than 0.89. These conditions occur when grid voltage is high, and the additional field excitation needed to get the power factor to 0.89 results in voltages on the emergency busses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.89 while still maintaining acceptable voltage limits on the emergency busses. In other circumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of 0.89 may not cause unacceptable voltages on the emergency busses, but the excitation levels are in excess of those recommended for the DG. In such cases, the power factor shall be maintained as close as practicable to 0.89 without exceeding the OG excitation limits. To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the OG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. (continued) B 3.8-26 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT2 SR 3.8.1.10 AC Sources-Operating B 3.8.1 Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.8, this Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide DG damage protection. While the DG is not to experience this transient during in event, and continue to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be torrected or isolated. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by two Notes. Note 1 ensures that the
• DG is tested under load conditions that are as close to . . . basis conditions as possible .. When synchronized with offsite. power, testing should be performed at a power factor of s 0,89. This power fact6r is representative of the actua1 inductive ioading a DG would under des1gn basis . accident conditions. Under certain conditions, however, Note 1 allows the t6 be at a power other than s 0.89. These.conditions occur when grid voltage is high; and; the add_itional field excitation needed . fo get. the po*wer factor to s 0.89. results in voltages on the emergency busses that ?re too high. Under these conditions, the power factor should be close as practicable to 0.89 while still maintaining acceptable v61 tage limits* on the emergency buss es.* In other
• circumstances, -_the gr.id voltag_e may _.be suc.h that. the DG excitation l e\/els needed to' obta'i n a power factor of 0 .89 may not cause vo1tages on the emergency busses, continued B 3.8-27 Revision No. 86 BASES SURH I LLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.1.10 (continued) AC Sources-Operating B 3.8.1 but the excitation levels are in excess of those recommended for the DG. In such cases, the power factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation limits. To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be d1rectly related to only one unit. SR 3.8.1.11 Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.4, this Surveillance demonstrates the as designed 6perati6n of the standby power sources during loss of the offsite source. This test verifies all actions from the loss of offsite power, including shedding of all loads and energization of the emergency buses and respective loads from the DG. It.further demonstrates the capability of the DG to !utomatically achieve required voltage ahd within the specified time. The DG auto-start and energiiation of the 4 kV emergency bus time of 10 seconds is derived requirements of the accident analysis for responding to a design basis large break The Surveillance should be continued for a of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved. continued B 3.8-27a Revision No. 57 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.1.11 (continued) AC Sources -Operating B 3.8.1 The requirement to verify the connection and power supply of auto-connected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration 6f the connection and loading of these loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by two Notes. The reason for Note 1 is. to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs shall be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated Unit 2. The comparable test specified in the Unit 3 Technical Specifications tests the applicable logic assciciated with Unit 3. Consequehtly, a test must be performed within the specified Frequency for each unit. The surveillance requirement allowance of+/- 2% for the EOG frequency is intended to allow for EOG transient operations during testing. The 'nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 3. The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MODE l; 2, or 3. Credit may be taken for unplanned events that satisfy this SR. continued B Revisi6n No. 86.

BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UNI'!'. 2 SR 3.8.1.12 AC Sources -Operating B 3.8.l Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.5, this Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates 5 minutes. The minimum voltage and frequency stated in the SR are those necessary to ensure the DG can accept DBA loading while maintaining acceptable voltage and frequency levels. The surveillance requirement allowance of +/- 2% for the EDG frequency is intended to allow for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. Stable operation at the nominal voltage and frequency values is also essential to establishing DG OPERABILITY, but a time constraint is not imposed. This is because a typical DG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by load application. This period may extend beyond the 10 second acceptance criteria and could be a cause for failing the SR. In lieu of a time constraint in the SR, PBAPS will monitor and trend the actual time to reach steady state operation as a means of ensuring there is no voltage regulator or governor degradation which could cause a DG to become inoperable. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d and SR 3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on a LOCA signal without loss of offsite power. The requirement to verify the connection and power supply of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to the loading logic for loading onto offsite power. In certain. circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS *injection valves are not desired to be stroked open, ECCS systems are not capable of being operated at full flow, or RHR systems performing a decay heat function are not desired to be realigned to the ECCS.mode of operation. In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG. system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps *so that the entire connection and loading sequence is verified. (continued) B 3.8-.29 Revision No.* 71 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 AC Sources-Operating B 3.8.1 SR 3.8.1.12 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations. SR 3.8.1.13 Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.12, this Surveillance demonstrates that DG noncritical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiation test signal. Noncritical automatic trips are all automatic trips except: engine overspeed, generator differential overcurrent, generator ground neutral overcurrent, and manual cardox initiation. The noncritical trips are bypassed during DBAs and continue to provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG. DG emergency automatic trips will be tested periodically per the station periodic The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. To minimize testing of the DGs, the Note to this SR allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. continued B 3.8-30 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 2 SR 3.8.1.14 AC Sources-Operating B 3.8.1 Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.9, this Surveillance requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours. However, load values may deviate from the Regulatory Guide such that the DG operates for 22 hours at a load approximately equivalent to 92% to 108% of the continuous duty rating of the DG, and 2 hours of which is at a load approximately equivalent to 108% to 115% of the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this . . This Surveillance verifies, indirectly, that the DGs are capable of synchronizing and accepting loads to post accident loads. The DGs are tested at a load approximately equivalent to their continuous duty rating, even though the post accident loads exceed the continuous rating. This is because regular surveillance testing at post lbads is injurious to the DG, and the same level of assurance in the ability of the. DG to provide post accident loadi can be developed by monitoring engine during The values of the testing parameters can then be

• compared to expected values at post accident e_ngine loads. In making this comparison it is necessary to consider the engine parameters as interrelated indicators of remaining DG capacity;, rather than independent i ndi caters. The important .engine. parameters to be considered in making this iriclude, rack position, scavengirig air pressure, exhaust.temperature and pressure, engine output, jacket water temperature, and oil With the DG at or coniinuous rating and the . values of the parameters less than .PQSt accident values; a qualitative extrapolation which. DG of accepting post loads can be made testing .. (continued) *B 3_.8-31 Revision No. 57 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.1.14 (continued) AC Sources-Operating B 3.8.l A load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This Surveillance has been modified by three Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 2 ensures that the DG is tested under load conditions that are as close to design basis conditions as possible, When synchronized with offsite power, testing should be performed at a power factor 0.89. This power factor is representative of the actual inductive loading a D G w o u l d s e e u n de r d e s i g_n b a s i s a c c i d e n t con d it i on s . Un d e r certain conditions, however, Note 2 allows the Surveillance to be conducted at a power factor other than 0.89. These _conditions occur when grid voltage is high, and the additional field excitation needed to get the power factor to 0.89 results in voltages on the emergency busses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.89 while still maintaining acceptable voltage limits on the emergency busses. In other circumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of 0.89 may not unacceptable voltages on the emergency busses, but the excitation levels are in excess of those recommended for the DG. In such cases, the power factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation To minimize testing of the DGs, Note 3 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these the DG should -be considered inoperable on both units, un_l ess the cause of the failure be directly related to only one unit. -SR -3. 8 .J. 15 This 11 ance demonstrates that the di es el engine can restart from a hot condition, such as subsequent to shutdown from Surveillances, and achieve the required voltage and frequency _within 10 seconds. The mini mum voltage and frequency stated in the SR are those necessary to ensure the DG can accept OBA loading while maintaining acceptable _voltage and frequency levels. Stable opera ti on at the voltage and frequency values is also essential to establ-is*hing _DG OPERABILITY, but a time cohstraint is not This is because a typical DG will experience a (continued) B 3.8c32 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.1.15 (continued) AC Sources-Operating B 3.8.1 period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by load application. The surveillance requirement allowance of+/- 2% for the EOG frequency is intended to allow for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. This period may extend beyond the 10 second acceptance criteria and could be a cause for failing the SR. In lieu of a time constraint in the SR, PBAPS will monitor and trend the actual time to reach steady state operation as a means of ensuring there is no voltage regulator or governor degradation which could cause a DG to become inoperable. The 10 second time is derived from the requirements of the analysis to respond to a basis large break LOCA. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by three Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardo.wn inspections ,in accordance with vendor recommendations in order to maintain DG OPERABILITY. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be by an engine prelube period to minimize wear tear on the diesel during testing. To minimize testing of the DGs, Note 3 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units.* This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. SR 3.8.1.16 Consistent with Regulatory GuidE 1.9 (Ref. 3), paragraph C.2.2.11, this ensures that the manual synchronization and load transfer from the DG to the offsite source can be made and that the DG can be returned continued . . B Revision No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.8.1.16 (continued) AC Sources -Operating B 3.8.1 to ready-to-load status when offsite power is restored. It also ensures that the auto-start logic is reset to allow the DG to reload if a subsequeht loss of offsite power occurs: The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and can receive an auto-close signal on bus undervoltage, and individual load timers are reset. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution* system, and challenge safety systems. This _Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in the Unit 3 Technical Specifications tests the applicable logic associated with Unit 3. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 3. The Note only applies to Unit 2, thus the Unit.2 Surveillances shall not be performed with Unit 2 in MODf 1, 2, or 3: Credit may be taken for unplanned events that satisfy this SR. SR 3.8.1.17 Consistent with Regulatory Guide 1.9 (Ref 3), paragraph C.2.2.13, demonstration of the test mode override ensures that the DG availability under accident conditions is not compromised as the result of testing. Interlocks to the LOCA sensing circuits cause the DG to automatically. reset to ready-to-load operation if a Unit 2 ECCS initiation signal is received during operation in the test mode while synchronized to either Unit 2 or a Unit 3 4 kV emergency bus. Ready-to-load operation is defihed as the DG running at rated speed and voltage with the DG output breaker open. continued B 3.8-34 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS *UNIT 2 SR 3.8.1.17 (continued) AC Sources-Operating B 3.8.1 The requirement to automatically energize the emergency loads with offsite power ensures that the emergency loads will connect to an offsite source. This is performed by ensuring that the affected 4 kV bus remains energized following a simulated LOCA trip of the DG output breaker, and ensuring 4kV and ECCS logic performs as designed to connect all emergency loads to an offsite source. The requirement for 4kV bus loading is covered by overlapping SRs specified in Specification 3.8.1, "AC Sources-Operating" and 3.3.5.1 "ECCS Instrumentation". In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading is verified. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. To minimize testing of the DGs, the Note allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. SR 3.8.1.18 Under acci.dent and loss of offsite power conditions, loads are sequentially connected to the bus by individual load timers (i.e., relays). The sequencing logic controls the permissive and starting signals to motor breakers in timed load blocks as depicted, by example, on Table 8.5.1 of Reference 10 to prevent overloading of the DGs due to high motor starting currents. The design interval for each individual load timer is the time between each load block that is applied onto the associated DG and is listed on the example Table 8.5.1 of Reference 10. The load sequence time interval (including the 10% tolerance) ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next timed load block. This ensures that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 10 provides a summary of the automatic loading of emergency buses. continued B 3.8-35 Revision No. 117 BASES . SU RV EI LLANCE REQUIREMENTS PBAPS UN IT 2 AC Sources -Operating B 3.8.1 SR 3.8.1.18 (continued) The Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in the Unit 3 Technical Specifications tests the applicable logic associated with Unit 3. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 3. The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MODE 1, 2, or 3. Credit may be taken for unplanned events that satisfy this SR. SR *3.8.1.19 ln the event of a OBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design not exceeded. This demonstrates DG operation, as discussed in the Bases fur SR l6ss of offsite power actuation test signal. in conjunction with an ECCS initiation In lieu of actual demonstration of connection and
• of loads, testing.that adequately shows the of the DG system to these is acceptable. This.testing may include any series of sequential, overlapping, or total steps so that the entire is The Surveil]arice Frequency is controlled under the Survei 11 ance Frequer:icy Control Program.* continued B *3.8-36. Revision No. 86
• BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.8.1.19 (continued) AC Sources -Operating B 3.8.1 This SR is modified by two Notes. The reason for Note 1 is to miniinize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations. The surveillance requirement allowance of +/- 2% for the EDG frequency is intended to allow for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. The reason for Note 2 is that performing the *surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in the Unit 3 Technical Specifications tests the applicable logic associated with Unit 3. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 11 2, or 3 does not have applicability to Unit 3. The Note only applies to Unit 2, thus the Unit 2 Surveillances not be performed with Unit 2 in MODE 1, 2, OT 3. Credit may be taken for unplanned events that satisfy this SR. SR 3.8.1.20 This Surveillance demonstrates that the DG starting indepen_dence has not been compromised. Also, this Surveillance demonstrates that engine can achieve proper speed within the specified time when the DGs are started simultaneously.
• The minimum voltage and frequency stated in the SR are those necessary to ensure the DG can accept DBA loading while maintaining a*cceptable *voltage and frequency levels. *The surveillance*requiremeI1t*allowance of+/- 2%-for the EDG frequency is intended to allow for EDG *t:rans*ient operations during testing. The _nominal frequency v_alue of 60 Hz is credited. -in plant analyses for ECCS performance. Stable operatiqn at the nominal voltage and frequency values is also essential to establi*shing DG OPERABILITY, but a time constraint. is not imposed. This is because a typical DG will experience a period of voltage and frequency
• oscill_ations prior to reaching steady state operation if these oscillations are not damped out by load application. *This period may extend beyond.the 10 second acceptance . criteria and could be a cause for failing the SR. In lieu of a time constraint in the SR, PBAPS will monitor and trend* the actual time to reach steady state operation as a means of ensuring there is no voltage or governor degradat_ion which could cause a DG to become inoperable. (continued) B 3.8-:-37 Revision No. 71 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.1.20 (continued) AC Sources-Operating B 3.8.l The Surveillance Frequency is controlled under the Surveillance Frequency.Control Program. This SR is modified by two Notes. The reason for Note 1 is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If a DG fails* one of these Surveillances, a DG should be considered on both units, unless the cause of the failure can be directly related to only one unit. SR 3.8.1.21 With the exception of this Surveillance, all other Surveillances of this Specification (SR 3.8.1.1 through SR 3.8.1.20) are applied only to the Unit 2 AC sources. This Surveillance is provided to direct that the appropriate Surveillances for the required Unit 3 AC sources are governed by the applicable Unit 3 Technical Specifications. Performance of the applicable Unit 3 Surveillances will satisfy Unit 3 requirements, as well as satisfying this Unit 2 Surveillance Requirement. Six exceptions are noted to the Unit 3 SRs of LCO 3.8.1. SR 3.8.1.8 is excepted when only one Unit 3 offsite ctrcuit is required by the Unit 2 Specificat1on, since there is not a second circuit to transfer to. SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, SR 3.8.1.18 CECCS load block requirements only), and SR 3.8.1.19 are excepted sihce these SRs test the Unit 3 ECCS initiation signal, which is not needed for the AC sources to be OPERABLE on Unit 2. The Frequency required by the applicable Unit 3 SR also governs performance of that SR for Unit 2. As Noted, if Unit 3 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note to Unit 3 SR 3.8.2.1 is This ensures that a Unit 2 SR will not require a Unit 3 SR to be performed, when the continued B 3.8-38 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS -UN IT 2 AC Sources-Operating B 3.8.1 SR 3.8.1.21 (continued) Unit 3 Technical Specifications exempts performance of a Unit 3 SR (However, as stated in the Unit 3 SR 3.8.2.1 Note, while performance of an SR is exempted, the SR still must be met). 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. UFSAR, Sections 1.5 and 8.4.2. UFSAR, Sections 8.3 and 8.4. Regulatory Guide 1.9, July 1993. UFSAR, Chapter 14. Generic Letter 84-15. Regulatory Guide 1.93, December 1974. UFSAR, Section 1.5.1. Regulatory Guide 1.108, August 1977. Regulatory Guide 1.137, October 1979. UFSAR, Section 8.5. NEDC-32988-A, Revision 2, Technical Justificatinn to Support Risk-Informed Modification to Selected Required End States for BWR December 2002. Regulatory Guide 1.9 (Safety March 1971. B 3.8-39 Revision No. -95 AC Sources-Shutdown B 3.8.2 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.2 AC Sources-Shutdown BASES BACKGROUND A description of the AC sources is provided in the Bases for LCO 3. 8 .1, n AC Sources-Operating. II APPLICABLE The OPERABILITY of the minimum AC sources during MODES 4 SAFETY ANALYSES and 5 and during movement of irradiated fuel assemblies in secondary containment ensures that: .. ...;* PBAPS UNIT 2 a. The facility can be maintained in the shutdown or refueling condition for extended periods; b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit status; and c. Adequate AC electrical power is provided to mitigate events postulated during shutdown, such as an inadvertent draindown of the vessel or a fuel handling accident. In general, when the unit is shut down the Technical Specifications requirements ensure that the unit has the capability to mitigate the consequences of postulated accidents. However, assuming a single failure and concurrent loss of all offsite or loss of all onsite power is not required. The rationale for this is based on the fact that many Design Basis Accidents (DBAs) are analyzed in MODES I, 2, and 3 have no specific analyses in MODES 4 and 5. Worst case bounding events are deemed not credible in MODES 4 and 5 because the energy contained within the reactor pressure boundary, reactor coolant temperature and pressure, and corresponding stresses result in the probabilities of occurrences significantly reduced or eliminated, and minimal consequences. These deviations from OBA analysis assumptions and design requirements during shutdown conditions are allowed by the LCO for required systems. During MODES 1, 2, and 3, various deviations from the analysis assumptions and design requirements are allowed within the ACTIONS. This allowance is in recognition that (continued) B 3.8-40 Revision No. O BASES APPLICABLE SAFETY ANALYSES (continued) LCD PBAPS UNIT 2 AC Sources-Shutdown B 3.8.2 certain testing and maintenance activities must be conducted, provided an acceptable level of risk is not exceeded. During MODES 4 and 5, performance of a significant number of required testing and maintenance activities is also required. In MODES 4 and 5, the activities are generally planned and administratively controlled. Relaxations from typical MODES I, 2, and 3 LCD requirements are acceptable during shutdown MODES, based on: a. The fact that time in an outage is limited. This is a risk prudent goal as well as a utility economic consideration. b. Requiring appropriate compensatory measures for certain conditions. These may include administrative controls, reliance on systems that do not necessarily meet typical design requirements applied to systems credited in operation MODE analyses, or both. c. Prudent utility consideration of the risk associated with multiple activities that could affect *multiple *systems. *
• d. Maintaining*, to the extent practical, the ability to perform required functions (even if not meeting MODES I, 2, and 3 OPERABILITY requirements) with systems assumed to function during an event. In the event of an accident during shutdown, this *Leo ensures the capability of supporting systems necessary for avoiding innnediate difficulty, assuming either a loss*of all offsite power or a loss of all onsite (diesel generator (DG)) The AC sources. satisfy.* Criterion 3 of the NRC Policy Statement. One offsite circuit supplying.the Unit 2 onsite Class IE power distribution subsystein(s) of LCO 3.8.8, "Distribution Systems-Shutdown," ensures* that all required Unit 2 powered loads are powered from offsite power. Two .OPERABLE DGs, associated with theUnit 2 onsite Class lE power distribution subsystem(s) required OPERABLE by LCO 3.8.8, ensures that a diverse powe.r source is available for providing electrical power support assuming a loss of the -. . . ' . (continued) . B 3.8-41 Revision No: O BASES LCD (continued) PBAPS UN IT 2 AC Sources-Shutdown B 3.8.2 offsite circuit. In addition, some equipment that may be required by Unit 2 is powered from Unit 3 sources (e.g., Standby Gas Treatment (SGT) System). Therefore, one qualified circuit between the offsite transmission network and the Unit 3 onsite Class lE AC electrical power distribution subsystem(s), and one DG (not necessarily a different DG than those being used to meet LCD 3.8.2.b requirements) capable of supplying power to one of the Unit 3 subsystems of each of the required components must also be OPERABLE. Together, OPERABILITY of the required offsite circuit(s) and required DG(s) ensures the availability of sufficient AC sources to operate the plant in a safe manner and to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents and reactor vessel draindown). Automatic initiation of the required DG during shutdown conditions is specified in LCO 3.3.5.1, ECCS Instrumentation, and LCO 3.3.B.1, LOP Instrumentation. The qualified Unit 2 offsite circuit must be capable of maintaining rated frequency and voltage while connected to the respective Unit 2 4 kV emergency bus(es), and of accepting required loads during an accident. Qualified offsite circuits are those that are described in the UFSAR, Technical Specification Bases Section 3.8.1 and are part of the licensing basis for the unit. A Unit 2 offsite circuit consists of the incoming breaker and disconnect to the startup and emergency auxiliary transformer, the respective circuit path to the emergency transformer, and the circuit path to the Unit 2 4 kV -emergency buses required by LCO 3.8.8, including feeder breakers to the required Unit 2 4 kV emergency buses. A qualified Unit 3 offsite circuit's requirements are the same as the Unit 2 circuit's requirements, except that the circuit path, including the. feeder breakers, is to.the.Unit 3 4*kv emergency buses required to be OPERABLE by LCO 3.8.8 ... The reg u 1 red D Gs mu s t be ca p a b l e of s ta rt in g , a cc e 1 e r at i n g to rated speed and voltage, and connecting to their respective Unit 2 emergency bus on detection of bus undervortage. This sequence must be accomplished within 10 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and must continue to operate until offsite power can be. restored the 4 kV emergency buses. These capabi]iiies are required .to be met from a variety of .initial conditions such as DG in standby engine h6t and. DG in* standby with engine at ambient con di ti ans. Addition al continued Revision No. 57 BASES LCO (continued) APPLICABILITY PBAPS UNIT 2 AC B 3.8.2 DG capabilities must be demonstrated to meet required Surveillances, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel *test mode. Proper sequencing of loads is a required function for DG OPERABILITY. The necessary portions of the Emergency Service Water System are also required to provide appropriate cooling to each required DG. The OPERABILITY requirements for the DG capable of supplying power to the Unit 3 powered equipment are the same as described above, except that the required DG must be capable of connecting to its respective Unit 3 4 kV emergency bus. (In addition, the Unit 3 ECCS initiation logic SRs not applicable, as described in SR 3.8.2.2 Bases.) It is acceptable for 4 kV emergency buses to be cross tied during shutdown conditions, permitting a single offsite power circuit to supply all required buses. No automatic transfer capability is required for offsite circuits to be considered OPERABLE. The AC sources are required to be OPERABLE in MODES 4 and 5 and during movement of fuel assemblies in the secondary containment to provide assurance that: a. Systems providing adequate coolant inventory makeup are available for the irradiated fuel assemblies in the core in case of an inadvertent dra1ndown of the reactor vessel; b. Systems needed to mitigate a fuel handling accident are available; c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition. AC power requirements for MODES 1, 2, and 3 are covered in LCO 3.8.L (continued) B 3.8-43 Revision No. O BASES (continued) AC B 3.8.2 ------------, ACTIONS LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE I, 2, or 3, the ACTIONS have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE I, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, i nab il i ty to suspend movement of irradiated fuel assemblies would not be sufficient reason to require a reactor shutdown. PBAPS UNIT 2 A.I and B.l With one or more required offsite circuits inoperable, or with one DG inoperable, the remaining required sources may be capable of supporting sufficient required features (e.g., system, subsystem, division, component, or device) to allow continuation of CORE ALTERATIONS, fuel movement, and operations with a potential for draining the reactor vessel. For example, if two or more 4 kV emergency buses are required per LCO 3.8.8, one 4 kV emergency bus with offsite power available may be capable of supplying sufficient required features. By the allowance of the option to declare required features inoperable that are not powered from offsite power (Required 'Action A.I) or capable of being powered by the required DG (Required Action B.l), appropriate restrictions can be implemented in accordance with the affected feature(s) LCOs' ACTIONS. Required features remaining powered from a qualified offsite power circuit, even if that circuit is considered inoperable because it is not powering other required features, are not declared inoperable by this Required Action. If a single DG is credited with meeting both LCO 3.8.2.d and one of the DG requirements of LCO 3.8.2.b, then the required features remaining capable of being powered by the DG are not declared inoperable by this Required Action, even if the DG .is considered inoperable because it is not capable of powering other required features. A.2.1, A.2.2. A.2.3, B.2.1. B.2.2, B.2.3, B.2.4. C.l, C.2. C.3. and C.4 With an offsite circuit not available to all required 4 kV emergency buses or one required DG inoperable, the option st i 11 ex ls ts to dee l are a 11 required features inoperable (continued) B 3.8-44 Revision No. O BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 AC B 3.8.2 A.2.1, A.2.2, A.2.3, A.2.4, B.2.1, B.2.2. 8.2.3. 8.2.4. C.l. C,2, C.3. and C.4 (continued) -(per Required Actions A.1 and B.l). Since this option may involve undesired administrative efforts, the allowance for sufficiently conservative actions is made. With two or more required DGs inoperable, the minimum required diversity of AC power sources may not be available. It is, therefore, required to suspend CORE ALTERATIONS, movement of irradiated fuel assemblies in the secondary containment, and activities that could result in inadvertent draining of the reactor vessel. Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC and to continue this action until restoration is accomplished in order to provide the necessary AC power to the plant safety systems. The Completion Time of imrnediately is consistent with the required times for actions requiring prompt attention. The restoration of the required AC electrical power sources should be completed as quickly as possible in order to minimize the time during which the plant safety systems may be without sufficient power. Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it are inoperable, resulting in de-energization. Therefore, the Required Actions of Condition A have been modified by a Note to indicate that when Condition A is entered with no AC power to any required 4 kV emergency bus, ACTIONS for LCO 3.8.8 must be immediately entered. This Note allows Condition A to provide requirements for the loss of the offsite circuit whether or not a required bus is de-energized. LCO 3.8.8 provides the appropriate restrictions for the situation involving a de-energized bus. SR 3.8.2.l SR 3.8.2.l requires the SRs from LCO 3.8.l that are necessary for ensuring the OPERABILITY of the Unit 2 AC sources in other than MODES 1, 2, and *3. SR 3.8.1.8 is not (continued} B 3.8-45 Revision No. 0 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.8.2.1 (continued) AC Sources -Shutdown B 3.8.2 required to be met since only one offsite circuit is required to be OPERABLE. SR 3.8.1.17 is not required to be met because the required OPERABLE DG(s) is not required to undergo periods of being synchronized to the offsite circuit. SR 3.8.1.20 is excepted because starting independence is not required with the DG(s) that is not required to be OPERABLE. Refer to the corresponding Bases for LCD 3.8.l for a of each SR. This SR 1s modified by a Note.* The reason for the Note is to preclude requiring the OPERABLE DG(s) from being . paralleled with the offsite power network or otherwise rendered inoperable during the performance of SRs, and to preclude de-energizing a required 4 kV emergency bus or disconnecting a required offsite circuit during performance of SRs. With limited AC sources available, a single event could compromise both the required circuit and the DG. It is the intent that these SRs must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit are required to be OPERABLE. This SR is modified by a second Note. The reason for the Note is to preclude requiring the automatic functions of the DG(s) on an ECCS initiation to be functional during periods when ECCS are not required. Periods in which ECCS are not required are specified in LCD 3 .. 5.2, "ECCS -Shutdown".* SR 3.8.2.2 is provided to direct that the appropriate Surveillances for the required Unit 3 AC sources are governed by the Unit 3 Technical Specifications. Performance of the app l i cable Unit 3 Surve i 11 ances will satisfy Unit 3 requirements, as well as satisfying this .. Unit 2 Surveillance Requirement. Seven exceptions are noted to the Unit 3 SRs of LCD 3.8.1. SR is excepted wheri only one Unit 3. offsite circuit is required by the Unit 2 Specification, there is not a second circuit to transfer to. SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, .. SR 3.8.1.181ECCS load block requirements only), and SR 3.8.1.19 are excepted since these SRs test the Unit 3 ECCS initiation signal, which is not needed for the AC sources to be OPERABLE* on Unit 2. SR 3.8.1.20 is excepted s i nee* starting fodependence is not requ1 red with the DG ( s) that is not required to be OPERABLE.
• B 3.8-46 (continued} Revision No. 16 Amendment No. 221
• BASES SURVEILLANCE REQUIREMENTS sR* 3.8.2.2 (continued)' AC Sources -Shutdown B 3.8.2 The Frequency required by the applicable Unit 3 SR also governs perfonnance that SR for Unit 2. As Noted, if Unit 3 is not in MODE 1, 2, or 3, the Note to Unit 3 SR 3.8.2.l is applicable. This that a Unit 2 SR will not require a Unit 3 SR to be performed, when the Unit 3 Technical Specifications exempts perfonnance of a Unit 3 SR or when Unit 3 is defueled. (However, as stated in the Unit 3 SR 3.8.2.1 Note,.while perfonnance of an SR is exempted, the SR still must be met). REFERENCES None. PBAPS. UNIT 2 B 3.B-47 v Amendment No. 22t Revision No. T6 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air BASES BACKGROUND PBAPS UN IT 2 Each of the four diesel CDGs) is provided with an associated storage which collectively have a fuel oil capacity sufficient to operate all four DGs for a period of 7 days while the DG is supplying maximum post loss of coolant accident CLOCA) load demand discussed in UFSAR, Section 8.5.2 (Ref. 1). The maximum load demand is calculated using the time dependent loading of each DG and the assumption that all four DGs are available. This onsite fuel oil capacity is sufficient to operate the DGs for longer than the time to replenish the onsite supply from outside sources. Post accident electrical loading and fuel consumption is not equally shared among the DGs. Therefore, it may be necessary to transfer post accident loads between DGs or to transfer fuel oil between storage tanks to achieve 7 days of post' accident operation for all four DGs. Each storage tank contains sufficient fuei to support the operation of the DG with the heaviest load (with four DGs available) for greater than 6 days 31,000 gallons initially in each tank. Each DG is equipped with a day tank and an associated fuel transfer pump that will automatically transfer oil from a fuel storage tank to the day tank of the DG when actuated by a float switch in the day tank. Additionally, the capability exists to transfer fuel oil between storage tanks. Redundancy of pumps and piping precludes the failure of one pump, or the rupture of any pipe, valve, or tank to result in the loss of more than one DG. All outside tanks and piping are located underground. For proper operation of the standby DGs, it is necessary to ---ens-Lire -tfle ___ proper qualTty of-The fue1oT1. Regulatory ---------Gui de 1.137 (Ref. 2) addresses the recommended fuel oil practices as supplemented by ANSI Nl95 (Ref. 3). The fuel oil properties governed by these SRs are the water and sediment content, the kinematic viscosity, specific gravity (or API gravity), and impurity.level. continued B 3. 8-48 . No. 105 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES LCD PBAPS UNIT 2 Di es el* Fuel Oil, Lube Oil, and Starting Air B 3.8.3 The DG lubrication system is designed to provide sufficient lubrication to permit proper operation of its associated DG under all loading conditions. The system is required to circulate the lube oil to the di es el engine working surfaces and to remove excess heat generated by friction during operation. Each engine oil sump and associated lube oil storage tank, along with additional inventory which is stored in a seismic Class I structure that is protected against other natural phenomena, are capable of supporting a minimum of 7 days of operation. Each lube oil sump utilizes a mechanical fl oat-type level cont roll er to automatically maintain the sump at the "full level running" level via gravity feed from the associated lube oil storage tank. Each DG has an air start system that includes two air start receivers; each with adequate capacity for five successive normal starts on the DG without recharging the air start receiver. The initial conditions of Design Basis Accident (OBA) and transient analyses in UFSAR, Chapter 8 (Ref. 4), and Chapter 14 (Ref. 5), assume Engineered Safety Feature CESF) systems are OPERABLE. The DGs are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Limits; Section 3.5, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling CRCIC) System; and Section 3.6, Containment Systems. Si nee di es el fuel oil, 1 ube oi 1, and starting air subsystem support the operation of the standby AC power sources, they satisfy Criterion 3 of.the NRC Policy Statement. Stored di es el fliel oi 1 is required to have sufficient supply for 7 days of operation at the worst case post accident
• time-dependent load profile. It is also required to meet standards for quality. Additionally, sufficient lube oil supply must be available to ensure the capability to operate at full load for 7 days. This requirement, in continued B 3.8-49 Revision No. 122 BASES LCD (continued) APPLICABILITY ACTIONS PBAPS UNIT 2 Diesel Fuel Oil, Lube Oil, and Starting .Air B 3.8.3 conjunction with an ability to obtain replacement suppli'es within 7 days, supports the availability of DGs required to shut down both the Unit 2 and Unit 3 reactors and to maintain them in a safe condition 'for an abnormal operational transient or a postulated OBA in one unit with loss of offsite power. DG day tank fuel oil requirements, as well as transfer capability from the storage tank to the day tank, are addressed in LCO 3.8.1, "AC Operating," and LCO 3.8.2, "AC The starting air system is required to have a minimum capacity for five successive DG normal starts without recharging the air start receivers. Only one air start receiver per DG is required, since each air start receiver has the required capacity. The AC sources (LCO 3.8.1 and LCO 3.8.2) are required to ensure the availability of the required power to shut down both the Unit 2 and Unit 3 reactors and*maintain them in a safe shutdown condition after an abnormal operational transient or a postulated OBA in either Unit 2 or Unit 3. Because stored diesel fuel oil, lube oil, and starting air subsystem support LCO 3.8.1 and LCO 3.8.2, stored diesel fuel oil, lube oil, and starting air are required to be within limits when the associated DG is required to be
• OPERABLE. The Actions Table is modified by a Note indicating that. separate Condition entry is allowed for each DG. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem. Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem(s) are governed by separate condition entry and application of associated Required Actions. (continued) B 3.8-50 Revision No. 0

,.. *: BASES Diesel Fuel Oilt Lube Oil, and Starting Air B 3.8.3 ACTIONS A.1 (continued) *, _.. .. * ' .. PBAPS UNIT 2 With fuel oil level < 33,000 gal in a storage tank (which includes margin for the unusable volume of oil), the 7 day fuel oil supply for a DG is not available. However, the Condition is restricted to fuel oil level reductions that maintain at *least a 6 day supply (with fuel oil transfer between storage tanks). These circumstances may be caused by events such as: . a. Full load operation required for an inadvertent start while at minimum required level; or ' ' b. * .Feed and bleed operations that may be necessitated by increasing particulate levels or any number.of other quality degradations. This restriction allows sufficient time for obtaining the requisite rep 1 acement vo 1 ume and pe rfo rmi ng the. analyses prior to addition of the fuel oil to 'the tank. A period of 48 hours is considered sufficient to restoration of t-he required 1eve1 pribr to declaring the. DG inoperable. This period is.acceptable based on the remaining . capacity (> 6 days) , . the fact that procedures wil 1 be i ni ti ated to 'obtain. rep 1 eni sh111ent, and. the 1 ow . ' probabi 1 ity. of an event during* this brief period.

• B;*l In this condition, the 7 day lube oi.l i.e., I suffi ci 1:!'nt l Libe oil t'o support 7 *days of continuous DG op.e.ration at full lo(ld .conditions,,:is not available. I* *-However*, the* Condi ti on
• is . restri c'ted _to 1 ube -ofl vo 1 ume
• reductions that .main'tain. at least a 6 day supply. _The lube oil i n\/eritory equivalent to a* 6 *diiy supply is 300 ga 11 ans; . The lub.e o-11 inventory equivalerit to a 6 day supply* is 300 gallons .. This allows *sufficient firile for . obta,inirjg the.requisite replacement volume. 'A periodof . :48: hours is_: considered suffi ci erit* 'to complete resto.rati on of the requ.ired volume prfor to declaring* the DG* * 'inoperalJle ... This period is. acceptable based on the remaining capacity (> 6 days), the low rate of usage, the fact that-pr:-ocedure.s wi 11 be i niti cited to obtain ' repleriistimerit, and the *fow probability of an event dllring' -this brief perfod. -* * * ** , .. *; (conti -.1,:: _ . B 3:.8-51 Revision No. 138" BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 ACTIONS C.l (continued) PBAPS UNIT 2 This Condition is entered as a result of a failure to meet the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to correct high particulate levels prior to reaching the limit of acceptability. Poor sample procedures (bottom sampling), contaminated sampling equipment, and errors in laboratory analysis can produce failures that do not follow a trend. Since the presence of particulates does not mean failure of the fuel oil to burn properly in the diesel engine, since particulate concentration is unlikely to change significantly between Surveillance Frequency intervals, and since proper engine performance has been recently demonstrated (within 31 days), it is prudent to allow a brief period prior to declaring the associated DG inoperable. The 7 day Completion Time allows for further evaluation, resampling, and re-analysis of the DG fuel oil. D. l With the new fuel oil properties defined in the Bases for SR 3.8.3.3 not within the required limits, a period of 30 days is allowed for restoring the stored fuel oil properties. This period provides sufficient time to test the stored fuel oil to determine that the new fuel oil, when mixed with previously stored fuel oil, remains acceptable, or to restore the stored fuel oil properties. This restoration may involve feed and bleed procedures, filtering, or combination of these procedures. Even if a DG start and load was required during this time interval and the fuel oil properties were outside limits, there is high likelihood that the DG would still be capable of performing its intended function *.. * --With required starting air receiver pressure < 225 psfg, sufficient capacity for five successive DG normal starts
• does not exist.
• However, as long as the receiver pressure is > 150 psig, there is adequate capacity for at least one start attempt, and the DG can be considered OPERABLE.while (continued) .B 3.8-52 Revision No. 0 .

BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 E.1 (continued) Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 the air receiver pressure is restored to the required limit. A period of 48 hours is considered sufficient to complete restoration to the required pressure prior to declaring the . DG inoperable. This is acceptable based on the remaining air start capacity, the fact that most DG starts are accomplished oli the fi.rst attempt, and the low probability 6f an event during this brief With a Required Action and associated Completion Time of* C6ndition A* B, t, D, or E not met, or the stored.diesel fuel oil, lube oil, or starting air subsystem not within limits for reasons other than add.ressed by Conditions A through E, the associated DG may be incapable of performing its intended function and must be immediately declared inoperable .. SR 3.8.3.1 This SR provides verification that there is an adequate useable inventory of fuel oil in the tanks to support each DG.' s operation of all four DGs for 7 days at the worst case post accident load The 7 day period is sufficient time to place both Unit 2 and Unit 3 in a safe shutdown conditi.on and to bring in. replenishment fuel from an offsite location. The Surveiilance Frequency is the Surveillance Frequency Control Program. .

• SR 3.8.3.2 This Surveillance ensures that sufficient lubricating oil inventory (combined inventory in the DG lube oil sump, lube oil storage tank, and in a seismically qualified structure) is availab 1 e to support at 1 east 7 days of fLill 1 oad operation for each DG. The lube oil inventory equivalent to a 7 day supply is 350 gallons and is based.-on the DG manufacturer's consumptfon values. for the run time of the DG. The entire inventory of lube oil *required by Technical Specifications shall be stored in a location which iS seismic*Class I and is protected other natural phenomena. Implicit in this SR is the requirement* to verify the Cconti nued) ** B 3 .. s.::53 Revi si,on No ... 138 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SR 3.8.3.2 (continued) capability to transfer the lube oil from its storage location to the DG to maintain adequate inventory for 7 days of full load operation without the level reaching the manufacturer's recommended minimum level. The Surveillance Frequency is controlled under the *1 Surveillance Frequency Control Program. SR 3.8.3.3 The tests of new fuel oil prior to addition to the storage tanks are a means of determining whether new fuel oil is of the appropriate grade and has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tanks without concern for contaminating the entire volume of fuel oil in the storage tanks. These tests are to be conducted prior to adding the new fuel to the storage tank(s), but in no case is the time between the sample (and corresponding results) of new fuel and addition of new fuel oil to the storage tanks to exceed 31 days. The tests, limits: and applicable ASTM Standards are as follows: a. Sample the new fuel oil in accordance with ASTM 04057-81 (Ref. 6); b. Verify in actordance with the tests specified in ASTM 0975-81 (Ref. 6) as discussed in Reference 7 that the sample has a kinematic viscosity at 40°C 1.9
• centistokes and s 4.1 centistokes (if specific gravity was not determined by comparison with the supplier's certification), and a flash point 125°F; c. Verify in accordance with tests specified in ASTM 01298-80 (Ref. 6) as discussed in Reference 7 that the sample has an absolute specific gravity at 60/60°F of 0.83 ands 0.89, or an absolute specific gravity of within O.OOi6 at 60/60°F when compared to the supplier's certificate, or an API gravity at 60°F of 27° ands 39°, or an API gravity of within 0.3° at 60°F wheri compared. to the supplier's certification; and
• continued B 3.8-54 Revision No: 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 Di es el Fuel Oil, Lube Oil, and Starting Air 'B 3. 8. 3 SR 3.8.3.3 (continued) d. Verify that the new fuel oil has a clear and bright appearance with proper color when tested in accordance with ASTM D4176-82 (Ref. 6) as discussed in Reference 7; or verify, in accordance with ASTM D975-81 (Ref. 6), that the sample has a water and sediment content 0.05 volume percent when dyes have been intentionally added to fuel oil (for example due to sulfur content). Failure to meet any of the above limits is cause for rejecting the new fuel oil, but does not represent a failure to meet the LCD concern since the fuel oil is not added to the storage tanks. Following the initial new fuel oil sample, the fuel oil is analyzed to establish that the other properties are within the required acceptance criteria for new fuel oil specified in Table 1 of ASTM D975-81. The testing methodology must be in accordance with ASTM D975-81 as discussed in Reference 7, except that the testing methodology for sulfur may be in accordance with ASTM D1552-79 (Ref. 6) or ASTM D2622-82 (Ref. 6) or ASTM D5453 (for ultra low sulfur diesel). Even with the use of ultra-1 ow sulfur di es el fuel oil, the Technical Specifications acceptance limit for sulfur weight percent is maintained by Table 1 of ASTM D975-81. In addition to the properties specified in Table 1 of ASTM D975-81, measurement of lubricity is required, in accordance with the testing methodology in ASTM D6079, with acceptance criteria specified in Table 1 of ASTM D975-06. These additional analyses are required by Specification 5.5.9, "Diesel Fuel Oil Testing Program," to be performed within 31 days following sampling and addition. This 31 day requirement is intended to assure that: 1) the new fuel oil sample taken is no more than 31 days old at the time of adding the new fuel oil to the DG storage tank, and 2) the results of the*new fuel oil sample are obtained within 31 days after addition of the new fuel oil to the DG storage tank. The 31 day period is acceptable because the fuel oil properties of interest, even if they were not within stated limits, would not have an immediate effect on DG operation. This Surveillance ensures the availability of high quality fuel oi 1 for the DGs. Fuel oil degradation during long term storage shows up as an increase in particulate, mostly due to oxidation. The presence of particulate does not mean that the fuel oil will not burn properly in a diesel engine. The particulate can cause fouling of filters and fuel oil injection equipment, however, which can engine failure. The fuel oil properties which can affect diesel generator performance (flash point, cetane number, viscosity, cloud point) do not change during storage. If these properties are within specification when the fuel is placed in storage, they will remain within specification unless other non-specification petroleum products are added to the storage tanks. The addition of non-specification petroleum products is precluded by above described surveillance test program. (continued) B 3.8-55 Revision No. 122 I I. BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 Di es el Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SR 3.8.3.3 (continued) Particulate concentrations should be determined.in accordance with ASTM (Ref. 6), Method A, as discussed in Reference 7 except that the filters specified in ASTM 02276-78, (Sections 3.1.6 and 3.1.7) may have a nominal pore size up to three microns. This method involves a gravimetric determination of total particulate concentration in the fuel oil and has a limit of 10 mg/l. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing. For the Peach Bottom Atomic Power Station design in which the total volume of stored fuel oil is contained in four interconnected each tank must be considered and tested separately. Frequency of this test takes into consideration fuel oil degradation trends that indicate that particulate concentration is unlikely to change significantly between Frequency intervals. SR 3.8.3.4 This that, without the aid of the refill compressor, sufficient air start capacity for each DG *is available. The system' design requirements provide for a minimum of five normal engine starts without recharging. The pressure in this SR is intended to reflect the lowest at which the five starts can be accomplished. The Survei 11 ance Frequency is controlled u*nder the Surveillance Frequency Control Program. SR 3.8.3.5 Microbiological .fouling is a major cause of fuel oil degradation. afe bacteria that can grow in fuel oil and cau?e fouling, but all must have .a water in ofder to survive. removal of water from the fuel tanks the necessary environment for bacterial survival. This is the most . effective -means of controlling mi crobi ol ogi cal fouling. In addition, it eliminates the for water entrainment . in. the fu.el oil during DG opera ti on. Water may come from any. of sources, includirig* condensation, water, rain *water;, contaminated fuel oil, and from**
• continued -B 3.8-56 Revision No. 122 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 Di es el Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SR 3.8.3.5 (continued) breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program. This SR is for preventive maintenance. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during performance of the Surveillance. 1. UFSAR, Section 8.5.2. 2. Regulatory Guide 1.lj7, Revision 1.
• 3. ANSI N195, 1976. 4. UFSAR, Chapter 6. 5. UFSAR,* Chapter 14. 6. ASTM Standards: D4057-81; D975-81; D1298-80; D4176-82; D1552-J9; D2622-82; D2276-78; and 0975-06. 7. Letter from G. A. Hunger (PECO Energy) to USNRC Document Control Desk; Peach Bottom Atomic Power Station Units 2 and 3, Supplement 7 to TSCR 93-16, Conversion to Improved Technical Specifications; dated May 24, 1995. B 3.8-57 No: 122 J DC B 3.8.4 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.4 DC BASES BACKGROUND PBAPS UNIT 2 The DC electrical power system provides the AC emergency power system with control power. It also provides a source of reliable, uninterruptible I25/250 voe power and I25 voe control power and instrument power to Class IE and non-Class IE loads during normal operation and for safe shutdown of the plant following any plant design basis event or accident as documented in the UFSAR (Ref. I), independent of AC power availability. The DC Electrical Power System meets the intent of the Proposed IEEE Criteria for Class IE Electrical Systems for Nuclear Power Generating Stations (Ref. 2). The DC electrical power system is designed to have sufficient independence, redundancy, and testability to perform its safety functions, assuming a single failure. The DC power sources provide both motive and control power, and instrument power, to selected safety related equipment, as well as to the nonsafety related equipment. There are two independent divisions per unit, Division I and Division II. Each division consists of two 125 VDC batteries. The two I25 VDC batteries in each division are connected in series. Each I25 VDC battery has two chargers (one normally inservice charger and one spare charger) that are exclusively associated with that battery and cannot be interconnected with any other 125 VDC battery. The chargers are supplied from separate 480 V motor control centers . (MCCs). Each of these MCCs is connected to an independent emergency AC bus. Some of the chargers are capable of being supplied by Unit 3 MCCs, which receive power from a 4 kV emergency bus, via manual transfer switches. However, for a required battery charger to be considered OPERABLE when the unit is in MODE I, 2, or 3, it must receive power from its associated Unit 2 MCC. The safety related loads between the 125/250 voe subsystem are not transferable except for the Automatic Depressurization System (ADS) valves and logic circuits and the main steam safety/relief valves. The ADS logic circuits and valves and the main steam safety/relief valves are normally fed from the Division I DC system. (continued) B 3.8-58 Revision No. 0 BASES BACKGROUND (continued) PBAPS UNIT 2 DC Sources-Operating B 3.8.4 During normal operation, the.DC loads are powered from the battery chargers with the batteries floating on the system. In case of loss of normal power to the battery charger, the DC loads are powered from the batteries. The DC power distribution system is described in more detail in Bases for LCO 3. 8. 7' nDi stri but ion System-Operating, II and LCO 3.8.8, nDistribution System-Shutdown.n Each battery has adequate storage capacity to carry the required load continuously for approximately 2 hours. Each of the unit's two DC electrical power divisions, consisting of two I25 V batteries in series, four battery chargers (two normally inservice chargers and two spare chargers), and the corresponding control equipment and interconnecting cabling, is separately housed in a ventilated room apart from its chargers and distribution centers. Each division is separated electrically from the other division to ensure that a single failure in one division does not cause a failure in a redundant division. There is no sharing between redundant Class IE divisions such as batteries, battery chargers, or distribution panels. The batteries for DC electrical power subsystems are sized to produce required capacity at 80% of nameplate rating, corresponding to warranted capacity at end of life cycles and the IOO% design demand. The minimum design voltage for sizing the battery using the methodology in IEEE 485 (Ref. 3) is based on a traditional I.8I volts per cell at the end of a 2 hour load profile. The battery terminal voltage using I.8I volts per cell is 105 V. Using the LOOP/LOCA load profile, the predicted value of the battery terminals is greater than I05 voe at the end of the profile. Many IE loads operate exclusively at the beginning of the profile and require greater than the design minimum terminal voltage. The analyzed voltage of the distribution panels .and the MCCs is greater than that required during the LOOP/LOCA to support the operation of the IE loads during the time period they are required to operate. Each required battery charger of DC electrical power subsystem has ample power output capacity for the steady state operation of connected loads required during normal operation, while at the same time maintaining its battery (continued} B 3.8-59 Revision No. 0 BASES BACKGROUND {continued) DC Sources-Operating B 3.8.4 bank fully charged. Each battery charger has sufficient capacity to restore the battery from the design minimum charge to its fully charged state within 20 hours while supplying normal steady state loads following a LOCA coincident with a loss of offsite power. A description of the Unit 3 DC power sources is provided in the Bases for Unit 3 LCO 3.8.4, "DC Sources-Operating." APPLICABLE The initial conditions of Design Basis Accident (OBA) and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 14 {Ref. 1), assume . that Engineered Safety Feature (ESF) systems are OPERABLE. LCD PBAPS UNIT 2
• The DC electrical power system provides normal and emergency DC electrical power for the DGs, emergency auxiliaries, and control and switching during all MODES of operation. The OPERABILITY of the DC subsystems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining DC sources OPERABLE during accident conditions in the event of: a. An assumed loss of all offsite AC power or all onsite AC power; and
• b. A worst case single failure. The DC sources satisfy Criterion 3 of the NRC Policy Statement. The Unit 2 Division I and Division II DC electrical power subsystems, with each DC subsystem consisting of two 125 V station batteries in series, two battery chargers (one per battery), and the corresponding control equipment and interconnecting cabling supplying power to the associated bus, are required to be OPERABLE to ensure the availability of the required power to shut down the reactor and maintain it in a safe condition after an abnormal operational transient or a postulated DBA. In addition, DC control power (which provides control power for the 4 kV load circuit breakers and the feeder breakers to the 4 kV emergency bus) for two of the four 4 kV emergency buses, as well as control power for two of the diesel generators, is provided by the Unit 3 DC electrical power subsystems. Therefore, Unit 3 Division I and Division II DC electrical power subsystems are also required to be OPERABLE. A Unit 3 (continued) B 3.8-60 Revision No. 0 BASES LCO (continued) APPLICABILITY . ACTIONS PBAPS UNIT 2 DC Sources-Operating B 3.8.4 DC electrical power subsystem OPERABILITY requirements are the same as those required for a Unit 2 OC electrical power subsystem, except that the Unit 3: 1) Division I DC electrical power subsystem is allowed to consist of only the 125 V battery C, an associated battery charger, and the corresponding control equipment and interconnecting cabling supplying 125 V power to the associated bus; and 2) Division II DC electrical power subsystem is allowed to consist of only the 125 V battery D, an associated battery charger, and the corresponding control equipment and interconnecting cabling supplying 125 V power to the associated bus. This exception is allowed only if all 250 VDC loads are removed from the associated bus. In addition, a Unit 3 battery charger can be powered from a Unit 2 AC source, (as described in the Background section of the Bases for Unit 3 LCO 3.8.4, "DC Sources-Operating"), and be considered OPERABLE for the purposes of meeting-this LCO. Thus, loss of any DC electrical power subsystem does not prevent the minimum safety function from being performed. The DC electrical power sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure safe unit operation and to ensure that: a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of *abnormal operational transients; and b. Adequate core cooling is provided, and containment integrity and other vital functions are maintained in the event of a postulated OBA.
• The. DC electrical power requirements for MODES 4 and 5 are addressed in LCO 3.8.5, "DC Sources...,.. Shutdown." Pursuant to LCO 3.0.6, the Distribution Systems-Operating ACTI.ONS would not be entered even if the DC electrical power subsystem.inoperability resulted in de-energization of an AC or DC bus*., Therefore, the Required Actions of Condition A *.are modified by a Note to indicate that when Condition A *ccoritinued) B 3 .S-_61 Revision No. O BASES ACTIONS PBAPS UNIT 2 A.I (continued) DC Sources-Operating B 3.8.4 results in de-energization of a Unit 2 4 kV emergency bus or a Unit 3 DC bus, Actions for LCO 3.8.7 must be immediately entered. This allows Condition A to provide requirements for the loss of a Unit 3 DC electrical power subsystem (due to performance of SR 3.8.4.7 or SR 3.8.4.8) without regard to whether a bus is de-energized. LCO 3.8.7 provides the appropriate restriction for a de-energized bus. If one Unit 3 DC electrical power subsystem is inoperable due to performance of SR 3.8.4.7 or SR 3.8.4.8, the remaining DC electrical power subsystems have the capacity to support a safe shutdown and to mitigate an accident condition. In the case of an inoperable Unit 3 DC electrical power subsystem, since a subsequent postulated worst case single failure could result in the loss of safety function, continued power operation should not exceed 7 days. The 7 day Completion Time is based upon the Unit 3 DC electrical power subsystem being inoperable due to performance of SR 3.8.4.7 or SR 3.8.4.8. Performance of these two SRs will result in inoperability of the Unit 3 DC divisional batteries since these batteries are needed for Unit 2 operation, more time is provided to restore the batteries, if the batteries are inoperable for performance of required Surveillances, to preclude the need for a dual *unit shutdown to perform thes*e Surveillances. The Unit 3 DC electrical power subsystems also do not provide power to the same type of equipment as the Unit 2 DC sources. The Completion Time also takes into account the capacity and capability of the remaining DC sources. B. l Pursuant to LCO 3.0.6, the Distribution Systems-Operating ACTIONS would not be entered even if the DC electrical power subsystem inoperability resulted in de-energization of an AC bus.. Therefore, the Required .Actions of Condition A are modified by a Note to indicate that when Condition A results in de-energization of a Unit 2 4 kV emergency bus, Actions . for LCO 3.8.7 must be immediately entered. This allows Condition A to provide requirements for the loss of a Unit 3 DC electrical power subsystem without regard to whether a bus is de-energized. LCO 3.8.7 provides the appropriate restriction for a de-energized bus. (continued) B 3.8-62 Revision No. O BASES ACTIONS PBAPS UNIT 2 B.1 (continued) DC Source*s-Operating B 3.8.4 . If one of the Unit 3 DC electrical power subsystems is inoperable for reasons other than Condition A, the remaining DC electrical power subsystems have.the capacity to support a safe shutdown and to mitigate an accident condition. Since a subsequent worst case single failure could, however, result in a loss of minimum necessary DC electrical subsystems to mitigate a worst case accident, continued power operation should not exceed 12 hours. The 12 hour Completion Time reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power subsystem and takes into consideration the importance of the Unit 3 DC electrical power subsystem. c .1 Condition C represents one Unit 2 division with a loss of ability to completely respond to an event, and a potential loss of ability to remain energized during normal operation. It is therefore imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for complete loss of DC power. If one of the Unit 2 DC electrical power subsystems is inoperable (e.g., inoperable battery/batteries, inoperable required battery charger/chargers, or inoperable required battery charger/chargers and associated battery/batteries), the remaining DC electrical power subsystems have the capacity to support a safe shutdown and to mitigate an accident condition. a subsequent worst case single failure could result in the loss of minimum necessary DC electrical subsystems to mitigate a worst case accident, continued power operation should not exceed 2 hours. The. 2 hour Completion Time is consistent with Regulatory Guide 1.93 (Ref. 4) and reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power division and, if the Unit 2 DC electrical power division is not restored to OPERABLE status, to prepare to initiate an orderly and safe unit shutdown. The 2 hour limit is also consistent with the allowed time for an inoperable Unit 2 DC Distribution System division. (continued) B 3.8-63 Revision No. 0.

1. BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2. DC Sources-Operating B 3.8.4 If the DC electrical power subsystem cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCD is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. L..l Condition E corresponds to a level of degradation in the DC electrical power subsystems that causes a required safety function to be lost. When more than one DC source is lost, this results in a loss of a required function, thus the * . plant is in a condition outside the accident analysis. *Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately to commence a controlled shutdown. As Noted at the beginning of the SRs, SR 3.8.4.l through *sR 3.8.4.8 are applicable only to the Unit 2 DC electriCal *power and SR 3.8.4.g is applicable only to the .Unit 3 DC electrical power subsystems. SR 3.8.4.1 Verifying battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of the charging system and the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is 'supplying the continuous charge required .to overcome the internal losses of a battery (or battery cell) and maintain the battery (or a battery cell) in a fully charged state. The voltage requirements are continued B 3.8-64 Revision No. 66 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.4.1 (continued) DC Sources -Operating B 3.8.4 based on the minimum cell voltage that will maintain a charged cell. This is consistent with the assumptions in the battery sizing calculations. The SR must be performed unless the battery is on equalize charge or has been on equalize charge any time during the previous 1 day. This allows the routine Frequency to be extended until such a time that the SR can be properly performed and meaningful results obtained. The surveillance frequency is applicable and continues during the time that the battery is on equalize with the exception that the surveillance does not need to be performed if the battery has been on equalize during the previous 1 day. The additional 1 day allows time for battery voltage to return to normal after the equalize charge and time to perform the test. The intent of the Note is to allow orderly, yet prompt performance of the surveillance that will produce meaningful results once the equalize charge is complete. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.4.2 Visual inspection to detect corrosion of the battery cells and connections or measurement of the resistance of each inter-cell, inter-rack, inter-tier, and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The battery connection resistance limits are established to maintain connection resistance as low as reasonably possible to minimize the overall voltage drop across the battery, and the possibility of battery damage due to heating of connections. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.4.3 Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The presence of physical damage or deterioration does not necessarily represent a failure of continued B 3.8-65 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.8.4.3 (continued) DC Sources -Operating B 3.8.4 this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.4.4 and SR 3.8.4.5 Visual inspection and resistance measurements of inter-cell, inter-rack, inter-tier, and terminal connections provides an indication of physical damage or abnormal deterioration that tould indicate degraded battery condition. The corrosion material is used to help ensure good electrical connections and to reduce terminal deterioration. The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection. The rem6val of visible corrosiDn is a preventive maintenance SR. The presence of visible corrosion does not necessarily represent a failure of this SR, provided visible corrosion is removed during performance of this Surveillance. The battery connection resistance limits are established to maintairi connection as low as reasonably possible to the v6ltage drop across the battery, and the of battery to heating of connections. The Surveillance Frequency is controlled under the Survei i lance Frequency Control Program. SR 3.8.4.6 chargef capability based on the design capacity of the chargers. The minimum charging is on the capacity to maintain* the associated battery in its fully tharged condition, and continued B 3.8-66

• Revision No. 86 BASES SURVEILLANCE REQUIREMtNTS PBAPS UNIT 2 DC Sources-Operating B 3.8.4 SR 3.8.4.6 (continued) to restore the battery to its fully charged condition following the worst case design discharge while supplying normal steady state loads. The minimum required amperes and duration ensures that these requirements can be satisfied. The Surveillance Frequency is controlled under the Frequency Control Program. SR 3.8.4.7 A battery service test is a special test of the battery's capability, as found, to satisfy the design requirements (battery duty cycle) of the DC Electrical Power System. The discharge rate and test length corresponds to the design duty cycle requirements. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Thii SR is modified by two Notes. Note 1 allows performance of. either a modified discharge or a performance discharge test (described in the Bases for SR 3.8.4.8) in lieu of a service test provided the test performed envelops the duty cycle of the battery. This substitution is acceptable because as long as the test current is greater than or to the actual duty cycle of the battery, SR 3.8.4.8 represents a more severe test of battery capacity thari a service test. continued B 3.8-67 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR 3.8.4.7 (continued) DC Sources-Operating B 3.8.4 The reason for Note 2 is performing the Surveillance would remove a required DC electrical power subsystem from service, perturb the Electrical Distribution System, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance. SR 3.8.4.8 A battery performance discharge test is a test of the constant current capacity of a battery, performed between 3 and 30 days after an equalize charge of the battery, to detect any change.in the capacity determined by the acceptance test. The test is intended to determine overall battery degradation due to age and A battery modified performance discharge test is a simulated duty cycle consisting of just two rates; the one minute rate published for the battery or the largest current load of the duty cycle, followed by the test employed for the performance test, both of which envelope the duty cycle of the service test. Since the ampere-hours removed by a rated one minute discharge represents a very small portion of the battery capacity, the test rate can be changed to that for the performance test without compromising the results of the performance discharge test. The battery terminal voltage for the modified performance discharge test should remain greater than or equal to the minimum battery terminal voltage specified in the battery performance discharge test. A modified performance discharge test is a test of the battery capacity and its.ability to provide a high rate, short duration load (usually the highest rate of the duty cycle). This will often confirm the battery's ability to meet the critical period of the load duty cycle, in addition _ to determining its percentage o.f rated capacity. Initial conditions for the modified performance discharge test should be identical to those specified for a performance discharge test. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.8; however, the discharge test may be * ( conti nuedl B 3.*8-68 Revision No. O BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 2
• SR 3.8.4.8 (continued) DC Sources-Operating B 3.8.4 used to satisfy SR 3.8.4.8 while satisfying the requirements of SR 3.8.4.7 at the same time only if the test envelops the duty cycle of the battery. The acceptance criteria for this Surveillance is consistent with IEEE-450 (Ref. 5) and IEEE-485 (Ref. 3). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A capacity of 80% shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. If the battery shows degradation, or if the battery has reached 85% of its expected life and capacity is< 100% of the manufacturers rating, the Surveillance Frequency is reduced to 12 months. However, if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity 100% of the manufacturer's rating. Degradation is indicated, according to IEEE-450 (Ref. 5), when the battery capacity drops by more than 10% relative to its on the previous performance test or when it is 10% below the manufacturer's rating. If the rate of discharge varies . significantly from the previous discharge test, the absolute battery capacity may change significantly, resulting in a capacity drop exceed1ng the criteria specified above. This absolute battery capacity change could be a result of acid concentration in the plate material, which is not an indication of degradation. Therefore, results of tests with significant rate differences should be discussed with the vendor and evaluated t6 determine if degradation has occurred. All these Frequencies, with the exception of the 24 month Frequency, are tonsistent with the recommendations *in IEEE-450 (Ref. 5). The 24 month Frequency is acceptable, given the battery has shown no signs of degradatfon, the
• unit conditions required to perform the test and other tequirements existing to ensure battery performance during these 24 month intervals. In addition, the 24 month Frequency is intended to be consistent with expected fuel cycle lengths. continue . . B 3*.8-69 Revision No. 86
• BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 SR 3.8.4.8 (continued) DC B 3.8.4 This SR is modified by a Note. The reason for the Note is that perfon11ing the Surveillance would remove a required DC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance. The DC batteries of the other unit are exempted from this restriction since they are required to be OPERABLE by both units and the Surveillance cannot be performed in the manner required by the Note
• without resulting in a dual unit shutdown. SR 3.8.4.9 With the exception of this Surveillance, all other Surveillances of this Specification (SR 3.8.4.1 through SR 3.8.4.8) are applied only to the Unit 2 DC electrical power subsystems. This Surveillance is provided to direct that the appropriate Surveillances for the required Unit 3 DC electrical power subsystems are governed by the Unit 3 Technical Specifications. Performance of the applicable Unit 3 Surveillances will satisfy Unit 3 requirements, as well as satisfying this Unit 2 Surveillance Requirement. The Frequency required by the* applicable Unit 3 SR also governs performance of that SR for Unit 2. As Noted, if Unit 3 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note to Unit 3 SR 3.8.5.1 is applicable. This ensures that a Unit 2 SR will not require a Unit 3 SR to be performed, when the Unit 3 Technical Specifications exempts performance of a Unit 3 SR. (However, as stated in the Unit 3 SR 3.8.5.1 Note, while performance of the SR is exempted, the SR still must be ll!et. ) 1. UFSAR, Chapter 14. 2. nProposed IEEE Criteria for Class IE Electrical Systems for Nuclear Power Generating Stations," June 1969. 3. IEEE Standard 485, 1983. (continued) B 3.8-70 Revision No. O BASES REFERENCES (continued) PBAPS UN IT 2 DC Sources-Operating B 3.8.4 4. Regulatory Guide 1.93, December 1974. 5. IEEE Standard 450, 1987. 6. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.8-71 .Revision No. 66 DC B 3.8.5 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.5 DC BASES BACKGROUND A description of the DC sources is provided in the Bases for LCO 3.8.4, "DC APPLICABLE The initial conditions of Design Basis Accident and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 14 (Ref. 1), assume that Engineered Safety Feature systems are The DC electrical power systelil_provjdes normal and emergency DC electrical power for the diesel generators (DGs), emergency auxiliaries, and control and switching during all MODES of operation. LCD PBAPS UNIT 2 The OPERABILITY of the DC subsystems is consistent with the initial assumptions of the accident analyses and the requirements for the supported systems' OPERABILITY. The OPERABILITY of the minimum DC electrical power sources duri'ng MODES 4 and 5 and during movement of irradiated fuel assemblies in secondary containment ensures that: a. The facility can be maintained in the shutdown or refuel i ng condition for *.extended p*eri ods; b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit status;*. and
• c. -Adequate DC electrical power is provided to mitigate events postulated during shutdown, such as an . inadvertent draindown of the vessel or a fuel handling accident. The DC sources satisfy Criterion 3 of the NRC Policy s*tatenient. The Unit 2 DC .electrical power subsystems, with each DC subsystem consisting of two 125 V station batteries in series, two battery chargers (one per battery), and the equipment and cabling . supplying power to the associated bus, are required to be (continued} .B3.8-72 Revision No. 0 BASES LCO (continued) APPLICABILITY PBAPS UNIT 2 DC B 3.8.5 OPERABLE to support Unit 2 DC subsystems required OPERABLE by LCO 3.8.8, 0Distribution When the equipment required OPERABLE: 1) does not require 250 VDC from the DC electrical power subsystem; and 2) does not require 125 VDC from one of the two 125 V batteries of the DC electrical power subsystem, the Unit 2 DC electrical power subsystem requirements can be modified to only include one 125 V battery (the battery needed to provide power to required equipment), an associated battery charger, and the corresponding control equipment and interconnecting cabling supplying 125 V power to the associated*bus. This exception is allowed only if all 250 VDC loads are removed from the associated bus. In addition, DC control power (which provides control power for the 4 kV load circuit breakers and the feeder breakers to the 4 kV emergency bus) for two of the four 4 kV emergency buses, as well as control power for two of the diesel generators, is provided by the Unit 3 DC electrical power subsystems. Therefore, the Unit 3 DC electrical power subsystems needed to support required components are also required to be OPERABLE. The Unit 3 DC electrical power subsystem OPERABILITY requirements are the same as those required for a Unit 2 DC electrical power subsystem. In addition, battery chargers (Unit 2 and Unit 3) can be powered from the opposite unit's AC source (as described in the Background section of the Bases for LCO 3.8.4, 0DC and be considered OPERABLE for the purpose of meeting this LCO. This requirement ensures the availability of sufficient DC electrical power sources to operate the unit in a safe manner and to mitigate the consequences of postulated events during. shutdown (e.g., fuel handling accidents and inadvertent reactor vessel draindown). The DC electrical power sources required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment provide assurance that: a. Required features to provide adequate coolant inventory makeup are available for the irradiated fuel assemblies in the core in case of an inadvertent draindown of the reactor vessel; (continued} 83.8-73 Revision No. 0 BASES APPLICABILITY (continued) ACTIONS PBAPS UNIT 2 DC B 3.8.5 b. Required features needed to mitigate a fuel handling accident are available; c. Required features necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition. The DC electrical power requirements for MODES 1, 2, and 3 are covered in LCO 3.8.4. LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the ACTIONS have been modified by a Note stating . that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be sufficient reason to require a reactor shutdown. A.l, A.2.1. A.2.2. A.2.3. and A.2.4 If more than one DC distribution subsystem* is required according to LCO 3.8.8, the DC electrical power subsystems remaining OPERABLE with one or more DC electrical power subsystems inoperable may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS, fuel movement, and operations with a potential .for draining the reactor vessel. * * . By a 11 owance of the option to dee 1 are required features inoperable with associated DC electrical power subsystems inoperable, appropriate restrictions are implemented in accordance with the affected system LCOs' ACTIONS. However, in many instances, this option may involve undesired administrative efforts. Therefore, the allowance for sufficiently conservative actions is made (i.e., to suspend CORE ALTERATIONS, movement of irradiated fuel assemblies in secondary containment, and any activities that could result in inadvertent draining of the reactor vessel). (continued) B 3.8-74 Revision No. 0 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 DC B 3.8.5 A.I. A.2.1. A.2.2. A.2.3. and A.2.4 (continued) Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required DC electrical power subsystems and to continue this action until restoration is accomplished in order to provide the necessary DC electrical power to the plant safety systems. The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required DC electrical power subsystems should be completed as quickly as possible in order to minimize the time during which the plant safety systems may be without sufficient power. SR 3.8.5.1 SR 3.8.5.1 requires performance of all Surveillances required by SR 3.8.4.l through SR 3.8.4.8. Therefore, see the corresponding Bases for LCO 3.8.4 for a discussion of each SR. This SR is modified by a Note. The reason for the Note is to preclude requiring the OPERABLE DC electrical power subsystems from being discharged below their capability to provide the required power supply or otherwise rendered inoperable during the performance of SRs. It is the intent that these SRs must still be capable of being met, but actual performance is not required. SR 3.8.5.2 This Surveillance is provided to direct that the appropriate Surveillances for the required Unit 3 DC electrical power subsystems are governed by the Unit 3 Technical Specifications. Performance of the applicable Unit 3 Surveillances will satisfy Unit 3 requirements, as well as satisfying this Unit 2 Surveillance Requirement. The Frequency required by the applicable Unit 3 SR also governs performance of that SR for Unit 2. (continued) B 3.8-75 Revision No. 0 BASES SURVEILLANCE
• REQUIREMENTS REFERENCES PBAPS UNIT 2 SR 3.8.5.2 (continued) I DC B 3.8.5 As Noted, if Unit 3 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note to Unit 3 SR 3.8.5.1 is applicable. This ensures that a Unit 2 SR will not require a Unit 3 SR to be performed, when the Unit 3 Technical Specifications exempts performance of a Unit 3 SR. (However, as stated in the Unit 3 SR 3.8.5.l Note, while performance of an SR is exempted, the SR still must be met.) 1. UFSAR, Chapter 14. :*.' . B 3.8-76 Revision o Battery Cell Parameters B 3.8.6 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.6 Battery Cell Parameters BASES BACKGROUND This LCO delineates the limits on electrolyte temperature, level, float voltage, and specific gravity for the DC electrical power subsystems batteries. A of these batteries and their OPERABILITY requirements is provided in the Bases for LCO 3.8.4, 0DC Sources-. Operating,n and LCO 3.8.5, "DC Sources-Shutdown.n APPLICABLE The initial conditions of Design Basis Accident (OBA) and SAFETY ANALYSES transient analyses in UFSAR, Chapter 14 (Ref. 1), assume Engineered Safety Feature systems are OPERABLE. The DC electrical power subsystems provide normal and emergency DC electrical power for the diesel generators (DGs), emergency auxiliaries, and control and switching during all MODES of operation. LCO APPLICABILITY PBAPS UNIT 2 The OPERABILITY of the DC subsystems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit as discussed in the Bases of LCO 3.8.4, "DC Sources-Operating,11 and LCO 3.8.5, nDC Sources-Shutdown. Si nee battery ce 11 parameters support the _operation of the DC electrical power subsystems, they satisfy Criterion 3 of the NRC Policy Statement.
• Battery cell parameters must remain within acceptable limits to ensure.availability-of the required DC power to shut down the reactor and maintain it in a safe condition after an abnormal operational transient or a postulated DBA. Electrolyte 1 i mi ts are conservatively est_ab l i shed, a 11 owing continued DC electrical system function even with Category A and B limits not met. The battery cell parameters are required solely for the support of the associated DC electrical power subsystem. Therefore, these cell parameters are only required when the DC power source is required to be OPERABLE. Refer to the Applicability discussions in Bases for LCO 3.8.4 and LCO 3 .8.5. . .. (cont i n_ued} .B 3.8-77 Revision No. O BASES (continued} ACTIONS PBAPS UNIT 2 A.1. A.2. and A.3 Battery Cell Parameters B 3.8.6 With parameters of one or more cells in one or more batteries not within limits (i.e., Category A limits not met or Category B limits not met, or Category A and B limits not met} but within the Category C limits specified in Table 3.8.6-1, the battery is degraded but there is still sufficient capacity to perform the intended function. Therefore, the affected battery is not required to be considered inoperable solely as a result of Category A or B limits not met, and continued operation is permitted for a limited period. The pilot cell electrolyte level and float voltage are required to be verified to meet the CategQry C limits within 1 hour (Required Action A.I). This check provides a quick indication of the status of the remainder of the battery cells. One hour provides time to inspect the electrolyte level and to confirm the float voltage of the pilot cells. One hour is considered a reasonable amount of time to perform the required veri-f-i-cat ion. Verification that the Category C limits are met (Required Action A.2) provides assurance that during the time needed to restore the parameters to the Category A and B limits, the battery is still capable of performing its intended function. A period of 24 hours is allowed to. complete the initial ver*ification because specific gravity measurements must be obtained for each connected cell. Taking into consideration both the time required to perform the required verification and the assurance that the battery cell parameters are not severely degraded, this time is considered reasonable. The verification is repeated at 7 day intervals until the parameters are restored to -Category A or B limits. This periodic-verification is consistent with the normal Frequency of pilot cell surveillances. Continued operation is only permitted for 31 days before battery cell parameters must be restored to within Category A and B limits. Taking into consideration that, while battery capacity is degraded, sufficient capacity exists to perform the intended function and to allow time to fully restore the battery cell parameters to normal limits, this time is acceptable for operation prior to declaring the DC batteries inoperable. (continued) B Revision No. 0 -

Battery Cell Parameters. B 3.8.6 BASES ACTIONS .8_.._l (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 When any battery parameter is outside the Category C limit for any connected eel l, sufficient capacity to supply the maximum expected load requirement is not ensured and the corresponding DC electrical power subsystem must be declared inoperable. Additionally, other potentially extreme conditions, such as not*completing the Required Actions of Condition A Within the required Completion Time or average electrolyte temperature of representative cells falling below 40°F, also are cause for immediately declaring the associated DC electrical power subsystem inoperable. SR 3.8.6.l This SR verifies that Category A battery cell parameters are consistent with IEEE-450 (Ref. 2), which recommends regular battery inspections including voltage, specific gravity, and electrolyte temperature of pilot cells. The SR must be performed unless the battery is on equalize charge or has on equalize charge any time during the previous 4 This allows the routine Frequency to be extended until such a time that the SR can be properly performed and results obtained. The surveillance frequency is applicable and continues during the time that the battery is on equalize with the exception that the surveillance does not need to be performed if the battery has been on equalize during the previous 4 days. The additional 4 days allows time for battery parameters to return to normal after the equalize charge (nominally 3 days) and time to perform test (nominally 1 day). The intent of the Note is to allow orderly, yet prompt performance of the surveillance that produce meaningful results once the equalize charge is complete. The Surveillance Frequency is controlled under the Surveillance Frequency Control Progfam. SR 3.8.6.2 The Surveillance Frequency is controlled under the I Surveillance Frequency Control Program. In addition, within . 24 hours of a battery discharge < 100 V or within 24 hours of a battery overcharge> 145 V, the battery must be demonstrated to meet Category B limits. Transients, such as motor starting transients which may momentarily cause battery voltage to drop 100 V, do not constitute battery discharge provided the battery terminal voltage and float current return to pre-transient values. This inspectiun is also consistent with IEEE-450 (Ref.* 2), which recomm.ends special inspections following a severe discharge or overcharge, to ensure that no sighificant degradation of the battery occurs as a consequence of such discharge or overcharge. continued B 3.8-79 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UNIT 2 SR 3.8.6.3 Battery Cell Parameters B 3.8.6 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Lower than normal temperatures act to inhibit or reduce battery capacity. This SR ensures that the operating temperatures remain within an acceptable operating range. Table 3.8.6-1 This table delineates the limits on electrolyte level, float voltage, and specific gravity for three different categories. The meaning of each category is discussed below. Category A defines the normal parameter limit for each designated pilot cell in each battery. The cells selected as pilot cells are those whose temperature, voltage, and electrolyte specific gravity approximate the state of charge of the entire battery. The Category A limits specified for electrolyte level are based on manufacturer's recommendations and are consistent with the guidance in IEEE-450 (Ref. 2), with the extra allowance above the high water level indication for operating margin to account for temperature and charge effects. In addition to this allowance, footnote a to Table 3.8.6-1 permits the electrolyte level to be above the specified maximum level during equalizing charge, provided it is not overflowing. These limits ensure that the plates suffer no damage, and that adequate electron transfer capability is maintained in the event of transient conditions. IEEE-450 (Ref. 2) recommends that electrolyte level readings should be made only after the battery has been at float charge for at least 72 hours. The Category A limit specified for float voltage 2.13 V per cell. This value is based on the recommendation of IEEE-450 (Ref. 2), which states that prolonged operation of cells below 2.13 V can reduce the life expectancy of cells. The Category A limit specified for specific for each pilot cell 1.195 (0.020 below the manufacturer's fully continued B 3.8-80 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 Table 3.8.6-1 (continued) Battery Cell Parameters B 3.8.6 charged nominal specific gravity or a battery charging current that had stabilized at a.low value). This value is characteristic of a charged cell with adequate capacity. According to IEEE-450 (Ref. 2), the specific gravity readings are based on a temperature of 77°F (25°C). The specific gravity readings are corrected for actual electrolyte temperature and level. For each 3°F (l.67°C) above 11*F (25.C), 1 point (0.001) is added to the reading; 1 point is subtracted for each 3*F below 11*F. The specific gravity of the electrolyte in a cell increases with a loss of water due to electrolysis or evaporation. Level correction will be in accordance with manufacturer's reconunendations. Category B defines the normal parameter limits for each connected cell. The term "connected cell" excludes any battery cell that may be jumpered out. The Category B limits specified for electrolyte level and float voltage are the same as those specified for Category A and have been discussed above. The Category B limit specified for specific gravity for each connected cell is 1.195 (0.020 below the manufacturer'.s fully charged, nominal spec.ific gravity) with the average of all connected cells 1.205 (0.010 below the fully charged, nominal specific gravity). These values were developed from manufacturer's The minimum specific gravity value required for each cell ensures that the effects of a highly charged or.newly installed cell do not mask overall degradation of the -. . . Category C defines the limit for each connected cell. These values, although pr.-ovide assurance that sufficient capacity exists.to perform the intended function and matntain a margin of safety. *When any battery parameter is outside the Category :C limit, .the assurance of sufficient capacity described above no longer exists, and the battery must be declared inoperable. The Category C limit specified for electrolyte level (above the top of. the p 1 ates .. and not overflowing) ensure that the .plates suffer no physical damage and maintain adequate electron transfer capability. The Category C Allowable Value. for voltage is based on (Ref. 2), which . (continued)

• B 3.8-81 *. Revision 0 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT .2 Table 3.8.6-1 (continued) Battery Cell Parameters B 3.8.6 states that a cell voltage of 2.07 V or below, under float conditions and not caused by elevated temperature of the cell, indicates internal cell problems and may require cell replacement. The Category C limit of average specific gravity i!!:: 1.190, is based on manufacturer's reconwnendations. In addition to that limit, it is required that the specific gravity for each connected cell must be no less than 0.020 below the average of all connected cells. This limit ensures that the effect of a highly charged or new cell does not mask overall degradation of *the battery. The footnotes to Table3.8.6-l that apply to specific gravity are applicable to Category A, 8, and C specific gravity. Footnote b of Table 3.8.6-1 requires the above mentioned correction for electrolyte level and temperature, with the exception that level correction is not required when battery charging current, while on float charge, is < l amp. This current provides, in general,* an indication of overall battery condition. Because of specific gravity gradients that are produced during the recharging process, delays of several days may occur while waiting for the specific gravity to stabilize. A stabilized charger current is an acceptable alternative to specific gravity measurement for determining the state of charge of the designated pilot cell. This phenomenon is discussed in IEEE-450 (Ref. 2). Footnote c to Table 3.8.6-1 allows the float charge current to be used as an alternate to specific gravity for up to 180 days following a battery recharge after a deep discharge. Within 180 days each connected cell's specific gravity must be measured to confirm the state of .charge. Following a minor battery recharge (such as equalizing charge that does not follow a deep discharge) specific gravity gradients are not significant, and confirming measurements must be made within 30 *
• 1. UFSAR, Chapter 14. 2. IEEE Standard 450, 1987.
• B 3.8-82 Revi.sion No. 0 Distribution . B 3.8.7 . B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.7 Distribution BASES BACKGROUND PBAPS UNIT 2 The onsite Class IE AC and DC electrical power distribution system is divided into redundant and independent AC and DC electrical power distribution subsystems. The primary AC distribution system for Unit 2 consists of four 4 kV emergency buses each having two offsite sources of power as well as an onsite diesel generator (DG) source. Each 4 kV emergency bus is connected to its normal source of power via either emergency auxiliary transformer no. 2 or no. 3. During a loss of the normal supply of offsite power to the 4 kV emergency buses, the alternate supply breaker from the alternate supply of offsite power for the 4 kV emergency buses attempts to close. If all offsite.sources are unavailable, the onsite emergency DGs supply power to the 4 kV emergency buses. (However, these supply breakers are not governed by thi.s ten; they are governed by LCO 3.8.1, "AC The secondary plant distribution system for Unit 2 includes 480 VAC load centers El24, E224, E324, and E424. There are two independent 125/250 VDC electrical power distribution subsystems for Unit 2 that support the necessary power for ESF functions. In addition, since some components required by Unit 2 receive power through Unit 3 electrical power distribution subsystems; the Unit 3 AC and DC electrical power
• distribution subsystems needed to support the required equipment are also addressed in LCO 3.8.7 .. A description of the Unit 3 AC and DC Electrical Power Distribution System is provided in the Bases for Unit 3 LCO 3.8.7, "Distribution The list of required Unit 2 distribution buses is presented in Table B 3.8.7-1. (continued) B 3.8-83 Revision No. 0 . .

I BASES {continued) Distribution Systems_..:..Operating B 3.8.7 APPLICABLE The initial conditions of Design Basis Accident (OBA) and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 14* (Ref. 1), assume Engineered Safety Feature {ESF) systems are OPERABLE. The AC and DC electrical power distribution systems are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.5, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling {RCIC) System; and Section 3.6 Containment Systems. LCO PBAPS UNIT 2 The OPERABILITY of the AC and DC electrical power distribution subsystems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining distribution systems OPERABLE during accident . *conditions in the event of: a. An assumed loss of all offsite power or all onsite AC electrical power; and b. A postulated worst case single failure. The AC and DC electrical power distribution satisfies Criterion 3 of the NRC Policy Statement. The Unit 2 AC and DC electrical power distribution subsystems are required to be OPERABLE. The required Unit 2 electrical power distribution subsystems listed in Table B 3.8.7-1 ensure the availability of AC and DC

• electrical power for the systems required to shut down the reactor and maintain it in a safe condition after an abnormal operational transient or a postulated DBA. As stated in the Table, each division of the AC and DC electrical power distribution systems is a subsystem. In addition, since some components required by Unit 2 receive *. power through Unit 3 electrical power distribution subsystems (e.g., Standby Gas Treatment (SGT) System, emergency heat s*i nk components, and DC contra l power for two of the four 4 kV emergency buses, as well as control power for two of the diesel generators), the Unit 3 AC and DC C continued l B 3.8-84 Revision No. 0

-" BASES LCD (continued) PBAPS UNIT 2 Distribution B 3.8.7 electrical power distribution subsystems needed to support the required equipment must also be OPERABLE. The Unit 3 electrical power distribution subsystems that may be required are listed in Unit 3 Table B 3.8.7-1. Maintaining the Unit 2 Division I and II and required*Unit 3 AC and DC electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor. The Unit 2 and Unit 3 AC electrical power distribution subsystems require the associated buses and electrical circuits to be energized to their proper voltages. The Unit 2 and Unit 3 DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated batteries or chargers. However, when a Unit 3 DC electrical power subsystem is only required to have one 125 V battery and *associated battery charger to be considered OPERABLE (as described in the LCO section of the Bases for LCO 3.8.4, "DC the proper voltage to which the associated bus is required to be energized is lowered from 250 V to 125 V (as read from the associated battery charger). Based on the number of safety' significant electrical loads associated with each electrical power distribution component (i.e., bus, load center, or distribution panel) listed in Table B 3.8.7-1, if one or more of the electrical power distribution components within a division (listed in Table 3.8.7-1) becomes inoperable, entry into the appropriate ACTIONS of LCO 3.8.7 is required. Other electrical power distribution components such as motor control centers (MCC) and distribution panels, which help comprise the AC and DC distribution systems are not listed in Table B 3.8.7-1. The loss of electrical loads associated with these electrical power distribution components may not result in a complete loss of a redundant safety function necessary to shut down the reactor and maintain it in a safe condition. Therefore, should one or more of these electrical power distribution components become inoperable due to a failure not affecting the OPERABILITY of an electri.cal power distribution component listed in Table B 3.8.7-1 (e.g., a breaker supplying a single MCC fails open), the individual loads. on the electrical power distribution component would be (continued) B 3.8-85 Revision No. o BASES LCO (continued) APPLICABILITY PBAPS UNIT 2 Distribution B 3.8.7 considered inoperable, and the appropriate Conditions and Required Actions of the LCOs governing the individual loads would be entered. If however, one or more of these electrical power distribution components is inoperable due to a failure also affecting the OPERABILITY of an electrical power distribution component listed in Table B 3.8.7-1 (e.g., loss of a 4 kV emergency bus, which results in energization of all electrical power distribution components powered from the 4 kV emergency bus), while these electrical power distribution components and individual loads are still considered inoperable, the Conditions and Required Actions of the LCO for the individual loads are not to be entered, since LCO 3.0.6 allows this exception (i.e., the loads are inoperable due to the inoperability of a support system governed by a Technical Specification; the 4 kV emergency bus). In addition, transfer switches between redundant safety related Unit 2 and Unit 3 AC and DC power distribution subsystems must be open. This prevents any electrical malfunction in any power distribution subsystem from propagating to the redundant subsystem, which could cause the failure of a redundant subsystem and a loss of essential safety function(s). If any transfer switches are closed, the electrical power distribution subsystem which is not being powered from its normal source (i.e., it is being powered from its redundant electrical power distribution subsystem) 1s considered inoperable. This applies to the onsite, *safety related, redundant electrical power distribution subsystems. It does not, however, preclude redundant Class IE 4 kV emergency buses from being powered from the same offsite circuit. The electrical power distribution subsystems are required to be OPERABLE in MODES 1, 2, and 3. to ens-lire that: a. Acceptable fuel design limits and reactor coolant pressure boundary 1 imit_s are not exceeded as a result of abnormal_ operational transients; and b. Adequate core cooling is provided, and.containment OPERABILITY and other vital functions are maintained in the event of a postulated OBA. (continued) B 3.8-86 Rev1sion No.* 0 BASES APPLICABILITY (continued) ACTIONS PBAPS UNIT 2 Distribution Systems-Operating B 3.8.7 Electrical power distribution subsystem requirements for MODES 4 and 5 and other conditions in which AC and DC electrical power distribution subsystems are required, are covered in LCO 3.8.8, nDistribution Systems-Shutdown." Pursuant to LCO 3.0.6, the DC Sources-Operating ACTIONS would not be entered even if the AC electrical power distribution subsystem inoperability resulted in energization of a required battery charger. Therefore, the Required Actions of Condition A are modified by a Note to indicate that when Condition A results in de-energization of a required Unit 3 battery charger, Actions for LCO 3.8.4 must be immediately entered. This allows Condition A to provide requirements for the loss of a Unit 3 AC electrical power distribution subsystem without regard to whether a battery charger is de-energized. LCO 3.8.4 provides the appropriate restriction for a de-energized battery charger. If one or more of the required Unit 3 AC electrical power distribution subsystems are inoperable, and a loss of function has not occurred as described in Condition F, the remaining AC electrical power distribution subsystems have the capacity to support a safe shutdown and-to mitigate an accident condition. Since a*subsequent worst case single failure could, however, result in the loss of certain safety functions, continued power operation should not exceed 7 days. The 7 day Completion Time takes into account the capacity and capability of the remaining AC electrical power distribution subsystems, and is based on the shortest restoration time allowed for the systems affected by the inoperable AC electrical power distribution subsystem in the respective system Speci fi cation. * . . . . -. If one of the Unit 3 DC electrical power distribution

• subsystems is inoperable, the remaining DC electrical power distribution subsystems have the capacity to support a safe shutdown and to mitigate an accident condition. Since a subsequent worst case single failure could, however, result in the 1 oss of safety function, .continued power operation should not exceed 12 hours. The 12 hour Completion Time (continued) . B-3.8-87 Revision No. O BASES ACTIONS -PBAPS UNIT 2 B.l (continued) Di st ri but i.on Systems -Operating B 3.8.7 reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power distribution subsystem and takes into consideration the importance of the Unit 3 DC electrical power distribution subsystem. With one Unit 2 AC electrical power distribution subsystem inoperable, the remaining AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The over a 11 reliability is reduced, howev.er, because a single failure in the remaining power distribution subsystems could result in the minimum required ESF functions not being supported. Therefore, the Unit 2 AC electrical power distribution subsystem must be restored to OPERABLE status within 8 hours. The Condition C worst scenario is one 4 kV emergency bus without AC power (i.e., no offsite power to the 4 kV emergency bus and the associated DG inoperable). In this Condition, the unit is more vulnerable to a complete loss of Unit _2 AC power. It is, therefore, imperative that the unit operators' attention be focused on minimizing the potential for loss of power to the-remaining buses by stabilizing the unit, and on restoring power to the affected bus(es). The 8 hour time limit before requiring a unit shutdown in this Condition-is acceptable because: a. There is a potential for decreased safety if the unit operators' attention is diverted from the evaluations and actions necessary to restore power to the affected bus(es) to the actions associated with taking the unit to shutdown within this time limit. b. The potential for an event in conjunction with a single failure of a redundant component in the division with AC power. (The redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP).") (continued) B 3.8-88 Revision No.*o BASES ACTIONS (continued) PBAPS l:JN IT 2 Distribution Systems-Operating B 3.8.7 With one Unit 2 DC electrical power distribution subsystem inoperable, the remaining DC electrical power distribution subsystem is capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in the remaining DC electrical power distribution subsystem could result in the minimum required ESF functions not being supported. Therefore, the Unit 2 DC electrical power distribution subsystem must be restored to OPERABLE status within 2 hours. Condition D represents one Unit 2 electrical power dtstribution subsystem without adequate DC power, potentially with both the battery(s) significantly degraded . and the associated charger(s) nonfunctioning. In this situation the is significantly more vulnerable to a complete loss of all Unit 2 DC power. It is, therefore, imperative that the operator's attention focus on continued B 3.8-89 Revision No: 85.

BASES ACTIONS PBAPS UN IT 2 lL..l (continued) Di stri but ion Systems -Operating B 3.8.7 stabilizing the plant, minimizing the potential for loss of power to the remaining electrical power distribution subsystem, and restoring power to the affected electrical distribution subsystem. This 2 hour limit is more conservative than Completion Times allowed for the majority of components that would be without power. Taking exception to LCO 3.0.2 for components without adequate DC power, which would have Required Action Completion Times shorter than 2 hours, is acceptable because of: a. The potential for decreased safety when requ1r1ng a change in plant conditions (i.e., requiring a shutdown) while not allowing stable operations to continue; b. The potential for* decreased safety when requ1r1ng entry into numerous applicable Conditions and Required Actions for components without DC power, while not providing sufficient time for the operators to perform the necessary evaluations and actions for restoring power to the affected subsystem; c. The potential for an event in conjunction with a single failure of a redundant component. The 2 hour Completion Time for DC electrical power distribution subsystems is consistent with Regulatory Gui de 1. 93 CRef. 2). continued B 3.8-90 Revision No. 85 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 .Ll Di st ri but ion Systems -Operating B 3.8.7 If the inoperable electrical power distribution subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCD is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. F corresponds tu a level o( degradation in the electrical power system that causes a required safety function to be lost. When more than one Condition is entered, and this results in the loss of a required function, the plant is in a condition outside the accident analysis. Therefore, no additional time is justified for continued operation. LCD 3.0.3 must be entered immediately to commence a controlled shutdown. SR. 3.8.7.1 ,* this that the AC and DC electrical power distribution sys.terns are functioni.ng properly, with the correct circuit breaker alignment (for the AC electrical power system The correct AC breaker continued . -; B 3.8-91

• Revision No. 85 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 SR 3.8.7.1 (continued) Di st ri but ion Systems -Operating B 3.8.7 alignment ensures the appropriate separation and. independence of the electrical buses are maintained, and power is available to each required bus. The verification of indicated power availability on the AC and DC buses ensures that the required power is readily available for motive as well as control functions for critical system loads connected to these buses. This may be performed by verification of absence of low voltage alarms. The Surveillance Frequency is controlled the Frequency Control Program. 1. UFSAR, Chapter 14. 2. Regulatory Guide 1.93, December 1974. 3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.8-92 Revision No. 86 TYPE AC buses DC buses -----------Distribution B 3.8.7 Table B 3.8.7-1 (page 1 of 1) AC and DC Electrical Power Distribution Systems VOLTAGE 4160 v 480 v 250 v DIVISION I* Emergency Buses E12, E32" Load Centers El24, E324 DIVISION II* Emergency Buses E22, E42 Load Centers E224, E424 Distribution Panel Distribution Panel 2AD18 28018
• Each division of the AC and DC electrical power distribution systems is a subsystem. PBAPS UNIT 2 B Revision No. O Distribution B 3.8.8 8 3.8 ELECTRICAL POWER SYSTEMS B 3.8.8 Distribution BASES BACKGROUND A description of the AC and DC electrical power distribution system is provided in the Bases for LCO 3.8.7, "Distribution APPLICABLE The initial conditions 9f Design Basis Accident and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 14 (Ref. I), assume Engineered Safety Feature (ESF) systems are OPERABLE. The AC and DC electrical power distribution systems are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System, and containment design limits are not exceeded. PBAPS UNIT 2 The OPERABILITY of the AC and DC electrical power distribution system is consistent with the initial assumptions of the accident analyses and the requirements for the supported systems' OPERABILITY. The OPERABILITY of the minimum AC and DC electrical power sources and associated power.distribution subsystems during MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment ensures that: a. The facility can be maintained in the shutdown or refueling condition for extended periods; b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit status; and
• c.
• Adequate power is provided to mitigate events postulated during shutdown, such as an inadvertent draindown of the vessel or a fuel handling accident. The AC and DC electrical power distribution systems satisfy Criterion 3 of the NRC Policy Statement. (continued) B 3.8-94 Revision No. O Distribution B 3.8.8 BASES (continued) LCO Various combinations of subsystems, equipment, and components are required OPERABLE by other LCOs, depending on the specific plant condition. Implicit in those requirements is the required OPERABILITY of necessary support required features. This LCO explicitly requires energization of the portions of the Unit 2 electrical distribution system necessary to support OPERABILITY of Technical Specifications required systems, equipment, and specifically addressed by their own LCO, and implicitly required by the definition of OPERABILITY. APPLICABILITY PBAPS UNIT 2 In addition, some components that may be required by Unit 2 receive power through Unit 3 electrical power distribution subsystems (e.g., Standby Gas Treatment (SGT) System and DC .control power for two of the four 4 kV emergency buses, as well as control power for two of the diesel generators). Therefore, Unit 3 AC and DC electrical power distribution subsystems needed to support the required equipment must also be OPERABLE. In addition, it is acceptable for required buses to be cross-tied during shutdown conditions, permitting a single source to supply multiple redundant buses, provided the source is capable of maintaining proper frequency (if required) and voltage. Maintaining these portions of the distribution system energized ensures the availability of sufficient power to operate the plant in a safe manner to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents and inadvertent reactor vessel draindown) . . The AC and DC electrical power distribution subsystems required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment provide assurance that: a. Systems to provide adequate coolant inventory makeup are available for the irradiated fuel in the core in case of an inadvertent draindown of the reactor vessel; b. Systems needed to mitigate a fuel handling accident are available; (continued) B 3.8-95 *Rev i s ion No . o BASES APPLICABILITY (continued) ACTIONS PBAPS UNIT 2 Distribution B 3.8.8 c. Systems necessary to mitigate the effects of events th.at can lead to core damage during shutdown are available; and d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition. The AC and DC electrical power distribution subsystem requirements for MODES 1, 2, and 3 are covered in LCO 3.8.7. LCD 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the ACTIONS have been modified by a Note stating . that LCD 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be sufficient reason to require a reactor shutdown. A.I. A.2.1, A.2.2. A.2.3. A.2.4. and A.2.5 Although redundant required features may require redundant electrical power distribution subsystems to be OPERABLE, one OPERABLE distribution subsystem may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS, fuel movement, and operations with a potential for draining the reactor vessel *. By allowing the option to declare required features inoperable with associated electrical power distribution subsystems inoperable, appropriate restrictions implemented in accordance with the affected distribution subsystem LCO's Required Actions. However,-in many instances this option may involve undesired administrative efforts. *Therefore, .the allowance for . sufficiently conservative actions is made,-(i.e., to suspend CORE ALTERATIONS, movement of irradiated fuel assemblies in the secondary containment, and any activities that could result ill inadvertent draining of the reactor vessel) . . (continued) B 3.S-96 Revision No.' 0 BASES . ACTIONS SURVEILLANCE REQUIREMENTS *REFERENCES . PBAPS UN IT 2 Dis tri but ion Systems -Shutdown B 3.8.8 A.1. A.2.1. A.2.2. A.2.3. A.2.4. and A.2.5 (continued) Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC and DC electrical power distribution subsystems and to continue this action until restoration is accomplished in order to.provide the necessary power to the plant safety systems. Notwithstanding performance of the above conservative Required Actions, a required residual heat removal -shutdown cooling <RHR-SDC) subsystem may be inoperable. In this case, Required Actions. A:2.l through A.2.4 do not adequately address the concerns relating to coolant circulation and heat removal. Pursuant to LCD 3.0.6, the RHR-SDC ACTIONS .would not be entered. Therefore, Required Action A.2.5 is provided to direct declaring RHR-SDC inoperable, which results in taking the appropriate RHR-SDC ACTIONS. The Completion Time of immediately is consistent with the required times. for actions requiring prompt attention. The restoration of the required electrical power distribution subsystems should be completed as quickly as possible in order to minimize the time the plant safety systems may be with out power. SR 3.8.8.1 This verifies that the AC and DC electrical power distribution subsystem functioning properly, with the buses energiied. of indicated power av all ability on the buses. ensures that the required power is readily for motive as well as functions critical system loads to these buses. This may*be performed by verification of absence of low voltage alarms. The is under .the Frequency Control 1. UFSAR, 14. B 3.8-97
• Revision No. 86 I Refueling Equipment Interlocks B 3.9.1 B 3. 9 REFUELING OPERATIONS B 3.9.1 Refueling Equipment Interlocks BASES BACKGROUND PBAPS UNIT 2 Refueling equipment interlocks restrict the operation of the refueling equipment:or the withdrawal of control rods to reinforce unit procedures that prevent the reactor from* achieving criticality during refueling. The refueling interlock circuitry senses the conditions of the refueling equipment and the control rods. Depending on the sensed conditions, interlocks are actuated to prevent the .of the refueling equipment or the withdrawal of control
• rods.* Design criteria require that one of the two required independent reactivity control systems be capable of holding the reactor core subcritical under cold (Ref. 1). The control rods, when fully inserted, serve as the system capable of maintaining the reactor subcritical in cold
• conditions during all movement activities and accidents. *
• One channel of instrumentation is provided to sense the position of the refueling the loading of the refueling platform fuel grapple and the full insertion of . . all Additionally, inputs are provided for the. loading of the refueling platform franie mounted auxiliary hoist and the loading of th.e refueling platform mo'norail. mouhted hoist. With the reactor mode switch in.the shutdown or refueling positiun, the conditions combined in circuits to determine if all restrictions on equipment operations and coritrol rod insertion are* . satisfied. A control rod not at its full-in position interrupts power to the refueling equipment and prevents operating the equipment over the reactor core when loaded with a fuel assembly. Conversely, the refueling equipment over the core and loaded with fuel inserts a control rod withdrawal black in the Reactor Manual Control System to prevent control rod. (continued) .B 3. 9-l
• Revisiori No .. 29 .. * .1 I I I . -,* *.:. ,.,. BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS.UNIT .2 Refueling Equipment Interlocks B 3.9.l The refueling platform has two mechanical switches that open before the platform or any of its hoists are physically located over the reactor vessel. All refueling h.oists have switches that open when the hoists are loaded with fuel. The refueling interlocks use these indications to prevent operation of the refueling equipment with. fuel loaded over the core whenever any control rod is withdrawn, or to prevent control rod withdrawal whenever fuel loaded refueling equipment is over the core (Ref. 2). The hoist switches open at a load lighter than the weight of a single fuel assembly in water. The refueling interlocks are explicitly assumed in the UFSAR analyses for the control rod removal .error during refueling lRef. 3) and the fuel assembly insertion error during refueling (Ref. 4). These analyses evaluate the consequences of control rod withdrawal during refueling .and also fuel assembly insertion with a control rod withdrawn. A prompt reactivity excursion during refueling could potentially result in fuel failure with subsequent release of radioactive material to the Criticality and, therefore, subsequent prompt reactivity excursions are prevented during the insertion of fuel, . provided all control rods are fully inserted during the fuel insertion. The refueling interlocks accomplish this by
• preventing loading*of fuel.into the core with any control. *rod withdrawn or by preventing withdrawal of a rod from the core during fue,, 1 oadi ng. The refueling platform at *a point ' outside of *the reactor core such that, with a fuel assembly loaded and .a control rod withdrawn, the fuel is not over the . -.. -.* core. Refuel.ing equipment interlocks satisfy Criterion 3 of .the NRC Policy Statement. * (continued)* B 3.9-2. Revision No. O I I . I ',,' '* Refueling Equipment Interlocks B 3.9.1 BASES (continued) LCO APPLICABILITY
• ACTIONS PBAPS UN_IT. 2 To prevent criticality during refueling, the refueling interlocks ensure that fuel assemblies are not loaded with any control rod withdrawn. To prevent these conditions developing, the .all-rods-in, the refueling platform position, the refueling platform fuel grapple fuel loaded, the refueling platform frame mounted auxiliary hoist fuel loaded, and the refueling platform monorail mounted hoist fuel loaded inputs are required to be OPERABLE. These inputs are combined in logic circuits, which provide refueling equipment or control rod blocks to prevent operations that could result in criticality during refueling operations. In MODE 5, a prompt reactivity excursion could cause fuel damage and subsequent release of radioactive material to the environment. The refueling equipment interlocks protect against prompt reactivity excursions during MODE 5. The interlocks are required to be OPERABLE during in-vessel fuel movement with refueling equipment associated with the interlocks. *
• In MODES 1, 2, 3, and 4, the reactor pressure vessel head is on. and fuel movements are not possible. *Therefore, the refueling interlocks are not required to be OPERABLE in these MODES. With one -0r more of the required refueling equipment interlocks inoperable; the unit must be placed in a condition in which the LCO does not apply. In-vessel fuel movement .with the affected refueling equipment must be immediately suspended. This action that operations
• are not performed with equipment that would potentially not be blocked from unacceptable operations (e.g., loading fuel into a cell with a control rod withdrawn). Suspension of in-vessel fuel movement shall not preclude completion of movement of a component to a safe position. (continued) B 3.9-3 Revision No. 29 BASES (continued) SURVEILLANCE REQUIREMENTS RE FERENC ES PBAPS UNIT 2 SR 3.9.1.l Refueling Equipment Interlocks B 3.9.1 Performance of a CHANNEL FUNCTIONAL TEST demonstrates each required refueling equipment interlock will function properly when a simulated or actual signal indicative of a required condition is injected into *the logic. The CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping, or total channel steps so that the entire channel is tested.
• The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. L UFSAR, Sections 1.5.1.1, 1. 5 .1. 8. 1, 1.5.2.2.7, 1.5.2.7.1. 2. UFSAR, Section 7. 6. 3. 3. UFSAR, Section 14.5.3.3. 4. UFSAR, Section 14.5.3.4. and B 3.9-4 Revision No. 86 Refuel Position One-Rod-Out Interlock B 3.9.2 B 3.9 REFUELING OPERATIONS . B 3.9.2 Refuel Position One-Rod-Out Interlock BASES BACKGROUND APPLICABLE SAFETY ANALYSES The refuel position one-rod-out interlock restricts the movement of control rods to reinforce unit procedures that prevent the reactor from becoming critical during refueling operations. During refueling operations, no more than one control rod is permitted to be withdrawn. The UFSAR design criteria require that one of the two required-independent reactivity control systems be capable of the reactor core subcritical under cold conditions (Ref. 1). The control rods serve as the system capable of maintaining the reactor subcritical in cold conditions. * *. ' The refuel position one-rod-out interlock prevents the selection of a. second control rod for movement when any other control rod is not fully inserted (Ref. 2).
• It is a logic circuit that has*redundant channels. It uses the rods-in signal (from_ the control rod full-in position indicators discussed in LCO 3.9.4, "Control.Rod Position Indication") and a rod selection signal (from the Reactor Manual Control System). *
• c ,* '
• This Specification ensures that the perfor:mance of the refuel position one-rod-out *interlock in the event of a Design Basis Accident meets used in the safety analysis of Reference 3. The refUl!ling. position one-rod-,.out interlock is explicitly assumed in theUfSAR analysis for the control rod withdrawal error during refueling (Ref. 3). This analysis evaluates . the consequences of . contro 1 rod wi during refuel i ng. A prompt. reactivity excursion during refueling could **
• p(>tentfally result in fuel failure with subsequent release of rad1o;lctive material to, the *environment. * * ** -' -. *.' . -. The-refuel PO$ition one-rod-out adequate SOM --(LCO 3.1.1, "SHUTDOWN MARGIN (SOM)")_ prevent criticality by preventing wi thdrawa 1 of more than one. -co.ntro 1. rod._ _ With** *
• one controlrod withdrawn, the core_ will remain subcritical, thereb.Y :preventing any prQliipt -critical-excursion. ---' -. . . . . -.' . . . -' -. :-. -I PBAPSlJNIT 2 BASES APPLICABLE SAFETY ANALYSES (continued) LCD APPLICABILITY ACTIONS PBAPS. UNIT 2 Refuel Position One-Rod-Out Interlock B 3.9.2 The refuel position one-rod-out interlock satisfies Criterion 3 of the NRC Policy Statement. To prevent criticality during MODE 5, the refuel position one-rod-out interlock ensures no more than one control rod may be withdrawn. Both channels of the refuel position one-rod-out interlock are required to be OPERABLE, and the reactor mode switch must be locked in the Refuel position to support the OPERABILITY of these channels. In MODE 5, with the reactor mode switch in the refuel position, the OPERABLE refuel position one-rod-out interlock provides protection against prompt reactivity excursions. In MODES 1, 2, 3, and 4, the refuel position one-rod-out interlock is not required to be OPERABLE and is bypassed. In MODES I and 2, the Reactor Protection System (LCO 3.3.1.1) and the control rods (LCO 3.1.3) provide mitigation of potential reactivity excursions. In MODES 3 and 4, with the reactor mode switch in the shutdown position, a control rod block (LCO 3.3.2.1) ensures all control rods are inserted, thereby preventing criticality
• during shutdown conditions. A.I and A.2 With one or both channels of the refueling position one-rod-out interlock inoperable, the refueling interlocks may not be capable of preventing more than one control rod from being withdrawn. This condition may lead to criticality. Control rod withdrawal must be immediately suspended, and action must be immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Action must continue until all such control rods are fully inserted. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and, therefore, do not have to be inserted. (continued) B 3.9-6
• Revision No. O BASES (continued) SURVEILLANCE REQUIREMENTS REFERENCES .. PBAPS UNIT 2 Refuel Position One-Rod-Out Interlock B 3.9.2 SR 3.9.2.1 Proper functioning of the refueling position one-rod-out interlock requires the reactor mode switch to be in Refuel. During control rod withdrawal in MODE 5, improper positioning of the reactor mode switch could, in some instances, allow improper bypassing of required interlocks. this Surveillance imposes an additional level of assurance that the refueling position one-rod-out interlock wi 11 be OPERABLE when required. By "locking" the reactor mode switch in the proper position Ci .e., removing the reactor mode switch key from the console while the reactor mode switch is positioned in refuel), an additional administrative control is in place to preclude operator errors from resulting in unanalyzed operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.9.2.2 Performance of a CHANNEL FUNCTIONAL TEST on each demonstrates the associated refuel position one-rod-out interlock will function properly when a simulated or actual signal indftative of a required condition is injected into the logic. The CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping, or total channel steps so that the entire channel is tested; The Surve1llance Frequency is controlled under the Surveillance Frequency Control Program. To perform the 0equired testing, the condition must be entered Ci .e., a control rod.must be withdrawn from its full-in position). Therefore, SR 3.9.2.2 hai been modified by a Note that states the CHANNEL FUNCTIONAL TEST is not required to be performed until 1 hour after any control rod is withdrawn. 1. UFSAR, Section 1.5: 2. UFSAR, Section 7.6; 3. UFSAR, Section 14.5.3.3. B 3.9-7 Revision No. 86.

I . Control Rod Position B 3.9.3 B 3.9 REFUELING OPERATIONS B 3.9.3 Control Rod Position BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 Control rods provide the capability to maintain the reactor subcritical under all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the Reactor Manual Control System. During refueling, movement of control rods is limited by the refueling interlocks (LCO 3.9.1 and LCO 3.9.2) or the control rod block with the reactor mo<fe switch in the shutdown position (LCO 3.3.2.1). UFSAR design criteria require that one of the two required independent reactivity control systems be capable of holding the reactor core subcritical under cold conditions (Ref. 1). The control rods serve as the system capable of maintaining the reactor subcritical in cold conditions. The refueling interlocks allow a single control rod to be withdrawn at any time unless fuel is being loaded into the core. To preclude loading fuel assemblies into the core with a control rod withdrawn, all control rods must be fully inserted. This prevents the reactor from achieving criticality during refueling operations. Prevention and mitigation of prompt reactivity excursions during refueling are provided by the refueling interlocks (LCO 3.9.1 and Len 3.9.2), the SOM (LCO 3.1.1), the wide range neutron monitor period-short scram (LCO 3.3.1.1), and the control rod block instrumentation (LCO 3.3.2.1). The safety analysis for the control rod withdrawal error during refueling in the UFSAR (Ref. 2) assumes the functioning of the refueling interlocks and adequate The analysis for the fuel assembly insertion error (Ref. 3) assumes all control rods are fully inserted. Thus, prior to fuel reload, all control rods must be fully inserted to minimize the probability of an inadvertent criticality. Control rod position satisfies Criterion 3 of the NRC Policy Statement. (continued) B 3.9-8 Revision No. 24 Control Rod Position B 3.9.3 BASES (continued) LCO All control rods must be fully inserted during applicable refueling conditions to minimize the probability of an inadvertent criticality during refueling. APPLICABILITY ACTIONS S U RV EI L LAN C E _REQUIREMENTS REFERENCES PBAPS UN IT 2 During MODE 5, loading fuel into core cells with control rods withdrawn may result in inadvertent criticality. Therefore, the control rods must be inserted before loading fuel into a core cell. All control rods must be inserted before loading fuel to ensure that a fuel loading error does not result in loading fuel into a core cell with the control rod withdrawn. In MODES 1, 2, 3, and 4, the reactor pressure vessel head is on, and no fuel loading activities are possible. Therefore, . this Specification is not applicable in these MODES. With all control rods not fully inserted during the applicable conditions, an inadvertent criticality could occur that is not analyzed _in the UFSAR. All fuel loading operations must be immediately suspended. Suspension of these activities shall not preclude completion of movemeht bf a to a safe position. SR 3.9.3.1 During to ensure that the remains subcritical, all control rods must be fu-lly inserted prior to* and during.fuel loading. -Periodic checks of the control *rod posit i on ensure th i s con d it i on i s ma i nt a i n e d . The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. ) UFSAR, Section 1.5. 2. UFSAR, Section 14.5,3.3. 3. UFSAR; Section 14.5.3.4. B 3.9-9 *Revision No. 86* Control Rod Position Indication B 3.9.4 B 3.9 REFUELING OPERATIONS B 3.9.4 Control Rod Position Indication BASES BACKGROUND The full-in position indication for each control rod provides necessary information to the refueling interlocks to prevent inadvertent criticalities during refueling operations. During refueling, the refueling interlocks (LCO 3.9.1 and LCO 3.9.2) use the full-in position indication to limit the operation of the refueling equipment and the movement of the control rods. -The absence of the full-in position indication.signal for any control rod removes the all-rods-in permissive for the refueling equipment interlocks and prevents fuel loading. Also, this condition causes the refuel position one-rod-out interlock to not allow the withdrawal of any other control rod. UFSAR design criteria require that one of the two required independent control systems be capable of holding the reactor core subcritical under cold conditions (Ref. 1). The control rods serve as the system capable of maintaining the reactor subcritical in cold conditions. APPLICABLE Prevention and mitigation of prompt reactivity excursions SAFETY ANALYSES during refueling are provided by the refueling interlocks (LCO 3.9.l and LCO 3.9.2), the SOM (LCO 3.1.1), the wide range neutron monitor period-short scram (LCO 3. 3 .1.1) and the control rod block instrumentation (LCO 3.3.2.1). PBAPS UNIT 2 The safety analysis for the control rod withdrawal error during refueling (Ref. 2) assumes the functioning of the refueling interlocks and adequate SOM. The analysis for the fuel assembly *error (Ref. 3).assumes all control rods are fully inserted. The full-in position indication is required to be OPERABLE so that the refueling interlocks can ensure that fuel cannot be loaded with any control rod withdrawn .and that no more than one control rod can be withdrawn at a Control rod position indication satisfies Criterion 3 of the NRC Policy Statement. (continued) B 3.9-10. Revision No. 24 Control Rod Position Indication B 3.9.4 BASES (continued) LCO Each control rod full-in position indication must be OPERABLE to provide the required input to the refueling interlocks. A full-in position indication is OPERABLE if it provides correct position indication to the refueling interlock logic. APPLICABILITY ACTIONS PBAPS UNIT 2 During MODE 5, the control rods must have OPERABLE full-in position indication to ensure the applicable refueling interlocks will be OPERABLE. In MODES I and 2, requirements for control rod are specified in LCO 3.I.3, wcontrol Rod OPERABILITY." In MODES 3 and 4, with the reactor mode switch in the shutdown position, a control rod block (LCO 3.3.2.I) ensures all control rods are inserted, thereby preventing criticality during shutdown conditions. A Note has been provided to modify the ACTIONS related to control rod position indication channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condit.ion. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable control rod position indications provide appropriate compensatory measures for separate inoperable channels.* As such, this Note has been provided, which allows separate Condition entry for each inoperable required control rod position indication. A.I.I, A.I.2. A.I.3. A.2.I and A.2.2 With one or more required full-in position indications inoperable, compensating actions must be taken to protect against potential reactivity excursions from fuel assembly insertions or control rod withdrawals. This may be * -accomplished by invnediately suspending invessel fuel movement and control rod withdrawal, and inanediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. (continued) B 3.9-11 Revision No. 0 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 Control Rod Position Indication B 3.9.4 A.1.1, A.1.2. A.1.3, A.2.1 and A.2.2 (continued) Actions must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. Suspension of invessel fuel movements and control rod withdrawal shall not preclude moving a component to a safe position. Alternatively, actions must be inunediately initiated to fully insert the cont_rol rod(s) associated with the inoperable full-in position indicator(s) and disarm (electrically or hydraulically) the drive(s) to ensure that the control rod is not withdrawn. A control rod can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. A control rod can be electrically disarmed by disconnecting power from all four direction control valve solenoids. Actions must continue until all associated control rods are fully inserted and

• drives are disarmed. Under these conditions (control rod fully inserted and disarmed), an inoperable full-in position indication may be bypassed to allow refueling operations to proceed. An alternate method must be used to ensure the control rod is fully inserted (e.g., use the noon notch position indication). SR 3.9.4.1 The full-in position indications provide input to the one-rod-out interlock and other refueling interlocks that require an all-rods-in permissive. The interlocks are actuated when the full-in position indication for any control rod is not present, since this indicates that all rods are not fully inserted. Therefore, testing of the full-in position indications is performed to ensure that . when a contro.l rod is withdrawn, the full-in position
• indication is not present. The full-in position.indication *is considered inoperable even with the control rod fully inserted, if it would continue to indicate full-in with the control rod withdrawn. Performing the SR each time a control rod is withdrawn is considered adequate because of the procedural controls on control rod withdrawals and the visual and audible indications available in the control room to alert the operator to control rods not fully inserted. (continued) .* B 3.9-12 Revision No. 0 BASES (continued) REFERENCES PBAPS UNIT 2 1. UFSAR, Section 1.5. 2. UFSAR, Section 14.5.3.3. 3. UFSAR, Section 14.5.3.4. B 3.9-13 Control Rod Position Indication B 3.9.4 Revision No. O Control Rod OPERABILITY -Refueling B 3.9.5 B 3.9 REFUELING OPERATIONS B 3. 9. 5 Contra 1 Rod OPERABILITY -Refue 1 i ng BASES BACKGROUND APPLICABLE SAFETY ANALYSES. LCO PBAPS UN IT 2
• Control rods are components of the Control Rod Drive {CRD) System, the primary reactivity control system for the reactor. In conjunction with the Reactor Protection System, the CRD System provides the means for the reliable control of reactivity changes during refueling operation. In addition, the control rods provide the capability to maintain the reactor subcritical under-all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the CRD System. UFSAR design criteria require that one of the two required independent reactivity control systems be capable of holding the reactor core subcritical under cold conditions {Ref. 1). The CRD System is the system capable of maintaining the reactor subcritical in cold conditions. Prevention and mitigation of prompt reactivity excursions during refueling are provided by refueling interlocks {LCO 3.9.1 and LCO the SOM (LCO 3.1.1), the wide range monitor period-short scram {LCO 3.3.1.1), and the control rod block instrumentation (LCO 3.3 .. 2.1). The safety analyses for the control rod withdrawal error during refueling (Ref. 2) and the fuel assembly insertion error {Ref. 3) evaluate the consequences of control rod withdrawal during refueling and also fuel assembly insertion w*ith a control rod withdrawn. A prompt reactivity excursion during refueling could potentially result in fuel *fa1lure with subsequent release of radioactive material to environment. Control rod scram* provides protection should a .prompt reactivity.excursion occur. Control rod OPERABILITY during .refueling satisfies Criterion 3 of the NRC Policy Statement. Each withdrawn control.rod must be OPERABLE. The withdrawn control rod is considered OPERABLE if the scram accumulator . pressure is .940 psig and the control rod is capable of {continued) B 3.9-14.
• Revision No. 24

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BASES LCO (continued) APPLICABILITY ACTIONS SURVEILLANCE REQUIREMENTS. PBAPS UN IT 2 Control Rod OPERABILITY-Refueling B 3.9.5 being automatically inserted upon receipt of a scram signal. Inserted control have already completed their reactivity control function, and therefore, are not required to be OPERABLE. During MODE 5, withdrawn control rods must be OPERABLE to ensure that in a scram the control rods will insert and provide the required negative reactivity to maintain the reactor subcritical. For MODES 1 and 2, control rod requirements are found in LCO 3.1.2, "Reactivity Anomalies," LCO 3.1.3, "Control Rod OPERABILITY," LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators." During MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod OPERABILITY during these conditions. With one or more withdrawn control rods inoperable, action must be immediately initiated to fully insert the inoperable control rod(s). Inserting the control rod(s) ensures the shutdown and scram capabilities are not adversely affected. Actions must continue until the inoperable.control rod(s) is fully inserted. SR 3.9.5.1 and SR 3.9.5.2 During 5i the OPERABILITY of control rods is primarily required to ensure a withdrawn control rod will automatitally insert if a signal a reactor .

• occurs. Because no explicit analysis exists for automatic shutdo0n refueling, the shutdown functibn is if the withdrawn control rod is capable of insertiori and the associated CRD scram accumulator is 940 psig.* The Sufveillance Frequency is controlled under the Surveillance Frequency _Control Program. continued B 3.9-15 Revisfon No. 86 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 Control Rod . B 3.9.5 SR 3.9.5.1 and SR 3.9.5.2 (continued) SR 3.9.5.1 is modified by a Note that allows 7 days after withdrawal of the control rod to perform the Surveillance. This acknowledges that the control rod must first be withdrawn before performance of the Surveillance, and therefore avoids potential conflicts with SR 3.0.3 and SR 3.0.4. 1. UFSAR, Section 1.5. 2. UFSAR, Section 14.5.3.3. 3. UfSAR, Section 14.5.3.4. B 3.9-16 Revision No. 0 RPV Water Level B 3.9.6 B 3.9 REFUELING OPERATIONS B 3.9.6 Reactor Pressure Vessel (RPV) Water Level BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 The movement of fuel assemblies or handling of control rods within the RPV requires a minimum water level of 458 inches above RPV instrument zero. During refueling, this maintains a sufficient water level in the reactor vessel cavity and spent fuel pool. Sufficient water is necessary to retain iodine fission product activity in the water in the event of a fuel handling accident (Refs. 1 and 2). Sufficient iodine activity would be retained to limit offsite doses from the accident to below the guidelines set forth in 10 CFR 50.67 (Ref. 3) as modified by Regulatory Guide 1 .183, Table 6. During movement of fuel assemblies or handling of control rods, the water level in the RPV and the spent fuel pool is an implicit initial condition design parameter in the analysis of a fuel handling accident in containment postulated in Reference 1. A minimum water level of 20 ft 11 inches above the top of the RPV flange allows a partition factor of 200 to be used in the accident analysis for halogens (Ref. 1). Analysis of the fuel handling accident inside containment is described in Reference 1. With a minimum water level of 458 inches above RPV instrument zero (20 ft 11 inches above the tdp of the RPV flange) and a minimum decay time of 24 hours prior to fuel handling, the analysis and test programs demonstrate that the iodine release due to a postulated fuel handling .accident is adequately captured by the water and that offsite doses are maintained within allowable limits (Ref. 3). While the worst case assumptions include the dropping of an *irradiated fuel. assembly onto the reactor core, the possibility exists of the dropped assembly striking the RPV flange and fission products. Therefore, the minimum depth for water toverage to ensure acceptable radiological consequences is specified from the RPV flange. Since the worst case event results in failed fuel assemblies seated in the core, as well as the dropped assembly, (continued) B 3.9-1.7 Revision No. 75 BASES APPLICABLE SAFETY ANALYSES {continued) LCO APPLICABILITY ACTIONS PBAPS UNIT 2 RPV Water Level B 3.9.6 dropping an assembly on the RPV flange will result in reduced releases of fission gases. Based on this judgement, and the physical dimensions which preclude normal operation with water level 23 feet above the flange, a slight reduction in this water level (to 20 ft 11 inches above the flange) is acceptable (Ref. 3). RPV water level satisfies Criterion 2 of the NRC Policy Statement. A minimum water level of 458 inches above RPV instrument zero (20 ft 11 inches above the top of the RPV flange) is required to ensure that the radiological consequences of a postulated fuel handling accident are within acceptable limits. LCD 3.9.6 is applicable when moving fuel assemblies or handling control rods (i.e., movement with other than the normal control rod drive) within the RPV. The LCD minimizes the possibility of a fuel handling accident in containment that is beyond the assumptions of the safety analysis. If irradiated fuel is not present within the RPV, there can be no *significant radioactivity release as a result of a postulated fuel handling accident. Requirements for fuel handling accidents in the spent fuel storage pool are covered by LCD 3.7.7, "Spent Fuel Storage Pool Water Level." If the water level is < 458 inches above RPV instrument zero, all operations involving movement of fuel assemblies and handling of control rods within the RPV shall be suspended *inunediately to ensure that a fuel handling accident cannot occur. The suspension of fuel movement and control rod handling shall not preclude completion of movement of a component to a safe position. (continued) B 3.9-18 Revision No. 0 BASES (continued) SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 SR 3.9.6.1 RPV Water Level B 3.9.6 Verification of a m1n1mum water level of 458 inches above RPV instrument zero ensures that the design basis for the postulated fuel handling accident analysis during refueling operations is met. Water at the required level limits the consequences of damaged fuel rods, which are postulated to result from a fuel handling accident in containment (Ref. 1). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 14.6.4. 2. UFSAR, Section 10.3. 3. 10 CFR 50.67. B 3.9-19 Revision No. 86 Water Level B 3.9.7 B-3.9 REFUELING OPERATIONS B 3.9.7 Residual Heat Removal Water Level BASES BACKGROUND APPLICABLE SAFETY ANALYSES LCO PBAPS UNIT 2 The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required in UFSAR, Section 1.5. The RHR System has two loops with each loop consisting of two motor driven pumps, two heat exchangers, and associated piping and valves. There are two RHR shutdown cooling subsystems per RHR System loop. The four RHR shutdown cooling subsystems have a conunon suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchangers, to the reactor via the associated recirculation loop. The RHR heat exchangers transfer heat to the High Pressure Service Water System. The RHR shutdown cooling mode is manually controlled. Any one of the four RHR shutdown cooling subsystems can provide the required decay heat removal function. In addition to the RHR subsystems, the volume of water above the reactor pressure v'essel (RPV) flange provides a heat sink for decay heat removal. With the unit in MODE 5, the *RHR System is not required to mitigate any events or accidents evaluated in the safety analyses. The RHR System is required for removing decay heat to maintain the temperature of the coolant. The RHR System satisfies Criterion 4 of the NRC Policy Statement. Only one RHR shutdown cooling subsystem is required to be OPERABLE and in operation in MODE 5 with irradiated fuel in the RPV*and the water 458 inches above RPV instrument zero. Only one subsystem is required because the vo 1 ume *of water above the RPV flange provides backup decay heat removal capability. An OPERABLE RHR shutdown cooling subsystem consists of an RHR pump, a heat exchanger, a High Pressure Service Water System pump capable of providing cooling to the heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path. In MODE 5, the RHR cross-tie (continued) B 3.9-20* Revision No. O BASES LCO (continued) APPLICABILITY ACTIONS . PBAPS UN IT 2 RHR-High Water Level B 3.9.7 valve is not required to be closed; thus the valve may be opened to allow an RHR pump in one loop to discharge through the opposite recirculation loop to make a complete subsystem. In addition, the HPSW cross-tie valve may be open to allow a HPSW pump in one loop to provide cooling to a heat exchanger in the opposite loop to make a complete subsystem. Management of gas voids is important to RHR Shutdown Coolihg System Additionally, each RHR shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. Operation (either continuous or intermittent) of one subsystem can maintain and reduce the reactor coolant as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. A *is provided to allow a 2 hour exception to shut down the operating subsystem every 8 hours. One RHR shutdown cooling subsystem must be OPERABLE and in operation in MODE 5, with irradiated fuel in the RPV and the water level 458 inches RPV instrument zero (20 ft 11 inches above the top of the RPV flange), to provide decay heat removal. RHR shutdown cooling subsystem requirements in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS); Section 3.5, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) System; and Section 3.6, Containment RHR Shutdown Cooling System requirements in MODE 5 with irradiated fuel in the RPV and the water < 458 inches above RPV instrument zero are given in LCO 3.9.8. With no RHR shutdown cooling subsystem OPERABLE, an alternate method of decay heat removal must be established within 1 hour. In this condition, the volume of water above the RPV flange provides adequate capability to remove decay heat from the reactor core. However, the overall reliability is reduced because loss of water level could result in reduced decay heat removal capability. The 1 hour Completion Time is based on decay heat removal function and continued B 3.9-21 Revision No. 126 BASES ACTIONS PBAPS UNIT 2 A.I (continued) Water Level B 3.9.7 the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours thereafter. This will ensure continued heat removal capability. Alternate decay heat removal methods are available to the operators for review and preplanning in the unit's Operating Procedures. For example, this may include the use of the Reactor Water Cleanup System, operating with the regenerative heat exchanger bypassed. The method used to remove the decay heat should be the most prudent choice based on unit conditions. B.l, B.2. B.3. and B.4 If no RHR shutdown cooling subsystem is OPERABLE and an alternate method of decay heat removal is not available in accordance with Required Action A.I, actions shall be taken immediately to suspend operations involving an increase in reactor decay heat load by suspending loading of irradiated fuel assemblies into the RPV. Additional actions are required to minimize any potential fission product release to the environment. This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem for Unit 2 is OPERABLE; and secondary containment isolation capability (i.e., one secondary containment isolation valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability) in each associated penetration .. not isolated that is assumed to be isolated to mitigate radioactive releases. This may be performed as an . administrative check, by examining logs or other information to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status *. In this case, a surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE. (continued)
• B 3.9-22 Revision No. 0 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS PBAPS -uN IT 2 C.l and C.2 RHR-High Water Level B 3.9.7 If no RHR shutdown cooling subsystem is in operation, an alternate method of coolant circulation is required to be established within 1 hour. This alternate method may utilize forced or natural circulation cooling. The Completion Time is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant circulation. During the period when the reactor coolant is being circulated by an alternate method Cother than by the required RHR shutdown cooling subsystem), the reactor coolant temperature must be periodically monitored to ensure proper functioning of the alternate method. The once per hour Completion Time is deemed appropriate. SR 3.9.7.l This Surveillance demonstrates that the .RHR shutdown cooling subsystem is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.9.7.2 RHR Shutdown Cooling (SOC) System p1p1ng and components have the potential to develop and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the required RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel. Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of . system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, calculations, and operational procedures. The design review is supplemented by system walk downs to validate the system high points and to confirm (continued) B 3.9-23 Revision No. 126 BASES SURVEILLANCE REQUIREMENTS PBAPS *UN IT 2 SR 3.9.7.2 (continued) RHR-High Water Level B 3.9.7 the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. For the RHR SOC piping on the discharge side of the RHR pump, acceptance criteria are for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume bf accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume in the RHR SOC piping on the discharge side of a pump), the Surveillance is not met. if the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is*not rendered inoperable by the gas (i.e., the system is sufficiently filled 0ith water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits. Since the RHR SOC .piping on the discharge side of the pump is the same as the Low Pressure Coolant Injection piping, performances of surveillances for ECCS TS may satisfy the requirements of *this surveillance. For the RHR SOC piping on the suction side of the RHR pump, the* survei 11 ance is. met by virtue of the of operating protedures that ensure that the RHR SOC *suction piping is adequately filled and vented. The performance of these manual actions ensGres that the is met: * ** RHR SOC System locations dn discharge side of the RHR pump. susceptible. to gas accumulation a re monitored and, if is found, the gas is to the acceptance criteria for the location. Susceptible locations in the same system flciw path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of locations. Monitoring may not be *pr.actical for locations that are dGe.to or envirrinmental *conditions, the plant configuration, or personnel safety. For locations alternative methods (e,g., operating (continued) B 3.9-23a Revision No. 127 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 SR 3.9.7.2 (continued) RHR-High Water Level B 3.9.7 parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval. The SR can be met by virtue of having an RHR SOC subsystem inservice in accordance with operating procedures. The SR is modified by a Note. The Note recognizes that the scope of the surveillance is limited to the RHR system components. The HPSW system components have been determined to not be required to be in the scope of this surveillance due to operating experience and the design of the system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation. None. B 3.9-23b Revisioh No. 126 I Water Level B 3.9.8 B 3.9 REFUELING OPERATIONS .B 3.9.8 Residual Heat Removal Water Level BASES BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required in UFSAR Section 1.5. The RHR System has two loops with each loop consisting of two motor driven pumps, two heat exchangers, and associated piping and valves. There are two RHR shutdown cooling subsystems per RHR System loop. The four RHR shutdown cooling subsystems have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchangers, to the reactor via the associated recirculation loop. The RHR heat exchangers transfer heat to the High Pressure Service Water System. The RHR shutdown cooling mode is manually controlled. Any one of the four RHR shutdown cooling subsystems can provide the required decay heat removal function. APPLICABLE With the unit in MODE 5, the.RHR System is not required to SAFETY ANALYSES mitigate any events or accidents evaluated in the safety analyses. The RHR System is required for removing decay heat to maintain the temperature of the reactor coolant. LCO PBAPS UNIT 2 The RHR System satisfies Criterion 4 of the NRC Policy Statement. In MODE 5 with irradiated fuel in the RPV and the water level < 458 inches above reactor pressure vessel (RPV) instrument zero both RHR shutdown cooling subsystems must be OPERABLE. *-An OPERABLE RHR shutdown cooling subsystem consists of an RHR pump, a heat exchanger, a High Pressure Service Water System pump capable of providing cooling to the heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path. The two subsystems have a common suction source and are allowed to have common discharge piping. Since piping is a passive component that is assumed not to fail, it is allowed to be common to both subsystems. In MODE 5, the RHR cross-tie valve is not required to be closed, thus the valve may be opened to allow (continued) B 3.9-24 Revision No. O ------------------------------------------------

BASES LCD (continued) APP LI CAB i LI TY ACTIONS PBAPS UN IT 2 RHR-Low Water Level B 3.9.8 an RHR pump in one loop to discharge through the opposite recirculation loop to make a complete subsystem. In addition, the HPSW cross-tie valve may be open to allow a HPSW pump in one loop to provide cooling to a heat exchanger in the opposite loop to make a complete subsystem. Management of gas voids is important to RHR SOC System OPERABILITY. Additionally, each RHR shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. Operation (either continuous or intermittent) of one subsystem can maintain and reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. A Note is provided to allow a 2 hour exception to *shut down the operating subsystem every 8 hours. Two RHR shutdown cooling subsystems are required to be OPERABLE, and one must be in operation in MODE 5, with irradiated fuel in the RPV and the water level < 458 inches above RPV instrument zero (20 ft 11 inches above.the top of the RPV flange), to provide decay heat removal. RHR shutdown cooling subsystem requirements in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS); Section 3.5, Emergency Core Cooling Systems CECCS) and Reactor Core Isolation *cooling CRCIC) System; and Section 3.6, Containment Systems. RHR Shutdown Cooling System requirements in MODE 5 with irradiated fuel in the RPV and the water le0el 458 inches above RPV instrument zero are given in LCD 3.9.7, "Residual Heat Removal C RHR)-Hi gh Water Level.". With one of the two required RHR shutdown cooling subsystems the.remaining subsystem is capable of the required decay heat removal. However, the overall reliabilitj is reduced. Therefore an alternate method of decay heat removal must be provided. With both required RHR cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem This re-establishes backup decay heat removal capabilities, similar to the requirements of the continued B 3.9-25 Revision No. 126 BASES ACTIONS PBAPS UNIT 2 A.I (continued) Water Level B 3.9.8 LCO. The I hour Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of this alternate method(s) must be reconfirmed every 24 hours thereafter. This will ensure continued heat removal capability. Alternate decay heat removal methods are available to the operators for review and preplanning in the unit's .Operating Procedures. For example, this may include the use *of the Reactor Water Cleanup System, operating with the regenerative heat exchanger bypassed. The method used to .remove decay heat should be the most prudent choice based on unit conditions. B.l. B.2. and 8.3 With the required decay heat removal subsystem(s) inoperable and the required alternate method(s) of decay heat removal not available in accordance with Required Action A.I, additional actions are required to minimize any potential fission product release to the environment. This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem for Unit 2 is OPERABLE; and secondary containment isolation capability (i.e., one secondary containment isolation valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability) in each associated penetration that is assumed to be isolated to mitigate radioactive releases. This may be performed as an administrative check, by examining logs or other information to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perforni the Surveillances needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, the surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE. (continued} B.3.9-26 Revision No. 0 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 C.1 and C.2 RHR-Low Water Level B 3.9.8 If no RHR shutdown cooling subsystem is in operation, an alternate method of coolant circulation is required to be established within 1 hour. This alternate method may utilize forced or natural circulation cooling. The Completion Time is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant circulation. During the period when the reactor coolant is being circulated by an alternate method Cother than by the required RHR shutdown cooling subsystem), the reactor coolant temperature must be periodically monitored to ensure proper functioning of the alternate method. The once per hour Completion Time is deemed appropriate. SR 3.9.8.1 This demonstrates that one RHR shutdown cooling subsystem is in and circulating reactor coolant. The required flow rate is by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.9.8.2 RHR Shutdown Cooling (SOC) System p1p1ng and components have

• the potential to develop voids and pockets of entrained. gases. Preventing gas and . is.necessary for proper of the required RHR shutdowri co61ing subsystems and may also prevent wc:iter hammer, .pump ca vita ti on, and pumpi rig of 'ndncondensible gas inio the vessel ..
• Selectioh of RHR Shutdown Cooling locations susceptible to gas accumulation is based on a review of system information;. including piping and .. instrumentation draw-ings, isometric drawings, plan and *elevation drawings, calculations, and
• The design teview is by system walk downs to validate high points and to confirm (continued) B 3.9-27 Revision No. 126 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 SR (continued) RHR-Low Water Level B 3.9.8 the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. The RHR Shutdown Cooling System is OPERABLE when it is *sufficiently filled with water. For the RHR SOC piping on the discharge side of the RHR pump, acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible *location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume in the RHR SOC piping on the discharge side of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas Ci .e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought w-ithi n the a ccepta nee criteria l i mits. Si nee the RHR SOC piping on the discharge side of the pump is the same as the Low Pressure Coolant piping, performances of for ECCS TS may *satisfy the of this surveillance. For the RHR SOC piping on the suction side of the RHR pump, the surveillance is met by virtue of the of operating procedures that ensure that the RHR SOC suction piping is adequately filled and vented. The performance of these manual actions ensures that the surveillance is met. RHR SOC System locations on the discharge of the RHR pump to gas accumulation are and, if gas is found, the gas volume is compared to_ the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to.the gas intrusion be verified bj monitoring a representative sub-set of susceptible locations. Monitbring may not be for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating remote monitbring) may be used to monitor the* (continued) B 3.9-28 .No. 127 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 2 SR 3.9.8.2 (continued) RHR-Low Water Level B 3.9.8 susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval. The SR can be met by virtue of having an RHR SDC subsystem inservice in accordance with operating procedures. The SR is modified by a Note. The Note recognizes that the scope of the surveillance is limited to RHR system components. The HPSW system components have been determined to not be required to be in the scope 'of this survei 11 ance due to operating experience and the design of the system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation. None. B 3.9-29 Revision No. -126 I Inservice Leak and Hydrostatic Testing Operation B 3.10.1 B 3.10 SPECIAL OPERATIONS B 3.10.1 Inservice Leak and Hydrostatic Testing Operation BASES BACKGROUND PBAPS UN IT 2. The purpose of this Special Operations LCO is to allow certain reactor coolant pressure tests to be performed in MODE 4 when the metallurgical characteristics of the reactor pressure vessel (RPV) or plant temperature control capabilities during these tests require the pressure testing at temperatures > 212°F (normally corresponding to MODE 3) or to*allow completing these reactor coolant pressure tests when the initial conditions do not require temperatures> 212°F. Furthermore, the purpose is to allow continued performance of control rod scram time testing required by SR 3.1.4.1 or SR 3.1.4.4 if reactor coolant temperatures exceed 212°F when the control rod scram time testing is initiated in conjunction with an inservice leak or hydrostatic test. These control rod scram time tests would be performed in accordance with LCO 3.10.4, "Single Control Rod Withdrawal -Crild Shutdown," during MODE 4 operation. Inservice hydrostatic testing and system leakage pressure tests required by Section XI of the American Society of . Mechanical Engineers (ASME) Boil er and Pressure Vessel Code (Ref. 1) are performed prior to the reactor going critical after a refueling outage. Recirculation pump operation and a water solid RPV (except for an air bubble for pressure control) are used to achieve the necessary temperatures and pressures required for these tests. The minimum temperatures (at the required pressures) allowed for these tests are determined the RPV pressure and temperature . (P/T) limits required by LCO 3.4.9, "Reactor Coolant System (RCS) Pressure and Temperature (P/T) Limits." These limits
• are conservatively based. on the fracture toughness of the reactor vessel, taking into account anticipated vessel neutron fl uence. With increased reactor vessel fluence over time, the m1n1mum allowable vessel temperature increases at a given pressure. Periodic updates to the RCS P/T limit curves are performed *as necessary, based upon the results of analyses of irradiated surveillance specimens removed from the vessel. Hydrostatic and. leak testing may eventually be required with minimum reactor coolant temperatures> 212°F. However, even with required minimum reactor coolant temperatures< 212°F, maintaining RCS temperatures within a small band during the continued B 3.10-1 Revision No. 129:

BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UN IT 2 Inservice Leak and Hydrostatic Testing Operation B 3.10.1 test can be impractical. Removal of heat addition from recirculation pump operation and reactor core decay heat can be coarsely controlled by control rod drive hydraulic system flow and reactor water cleanup system non-regenerative heat exchanger operation. Test conditions are focused on maintaining a steady state pressure, and tightly limited temperature control poses an unnecessary burden on the operator and may not be achievable in certain instances. The hydrostatic and RCS system leakage tests require increasing pressure to approximately 1000 psig. Scram time testing required by SR 3.1.4.1 and SR 3.1.4.4 requires reactor pressures 800 psig. Other testing may be performed in conjunction with the allowances for inservice leak or hydrostatic tests and control rod scram time tests. Allowing the reactor to be considered in MODE 4 when the reactor coolant temperature is> 212°F during, or as a consequence of, hydrostatic or leak testing, or as a consequence of control road scram time testing initiated in conjunction with an inservice leak or hydrostatic test, effectively provides an exception to MODE 3 requirements, including OPERABILITY of primary containment and the full complement of redundant Emergency Core Cooling Systems. Since the tests are performed nearly water solid (except for an air bubble for pressure control), at low decay heat values, and near MODE 4 conditions, the stored energy in the reactor core will be very low. Under these conditions, the potential for failed fuel and a subsequent increase in coolant activity above the LCO 3.4.6, "RCS Specific Activity," limits are minimized. In addition, the secondary containment will be OPERABLE, in accordance with this Special Operations LCO, and will be capable of handling any airborne radioactivity or steam leaks that could occur during the performance of hydrostatic or leak testing. The required pressure testing conditions provide adequate assurance that the consequences of a steam leak will be conservatively bounded by the consequences of the postulated main steam line break outside of primary containment. described in Reference 2. Therefore, these requirements will conservatively limit radiation releases to the environment. continued B 3.10-2 Revision No. 129 l BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UN IT 2 Inservice Leak and Hydrostatic Testing Operation B 3.10.1 In the event of a large primary system leak, the reactor vessel would rapidly depressurize, allowing the low pressure core cooling systems to operate. The capability of the low preisure coolant injection and core spray subsystems, as required in MODE 4 by LCO 3.5.2, "ECCS-Shutdown," would be more than adequate to keep the core flooded under this low decay heat load condition. Small system leaks would be detected by leakage inspections before significant inventory loss occurred. For the purposes of this test, the protection provided by normally required MODE 4 applicable LCOs, in addition to the secondary containment requirements required to be met by this Special Operations LCO, will ensure acceptable during normal hydrostatic test conditions and during postulated accident conditions. As described in LCO 3.0.7, compliance with Special Operations LCOs is option al, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria for the other LCOs is provided in their respective Bases. As described in LCO 3.0.7, compliance with this Special* Operatiohs LCO is optional. Operation at reactor coolant temperatures> 212°F can be in accordance with Table 1.1-1 for MODE 3 operation without meeting this* Special Operations LCO or its ACTIONS. This option may be required due to P/T limits, howe.ver,

• whi c:h require testing at temperatures > 212°F, while the ASME inservice test itse]f requires the safety/relief valves to be gagged, preventing their OPERABILITY. Additionally, even with re1uired minimum reactor-coolant temperatuTes < 212°F, RCS temperatures may drift above 212°F during the performance of inservice leak and hydrostatic testing or during subsequent control rod : scfam time testing; which_ is typically performed in conjunction with inservice leak and hydrostatic testing. While this Special Operations LCO is provided for inservice leak and hydrostatic testing, and for scram time testing initiated-1n conjunction with an inservice leak or test, parallel performance o1 others tests and inspections is not precluded. cont i nu'ed B 3.10-2a Revision No. 129 I-BASES LCO (continued) APPLICABILITY ACTIONS PBAPS UN IT 2 Inservice Leak and Hydrostatic Testing Operation B 3.10.1 If it is desired to perform these tests while complying with this Special Operations LCO, then the MODE 4 applicable LCOs and specified MODE 3 LCOs must be met. This Special Operations LCO allows changing Table 1.1-1 temperature limits for MODE 4 to "NA" and suspending the requirements of LCO 3.4.8, "Residual Heat Removal CRHR) Shutdown Cooling System-Cold Shutdown." The addition al requirements for secondary containment LCOs to be met will provide sufficient protection for operations at reactor coolant temperatures > 212°F for the purpose of performing an inservice leak or hydrostatic test, and for control rod scram time testing initiated in conjunction with an inservice leak or hydrostatic test. This LCO allows primary containment to be open for frequent unobstructed access to perform inspections, and for outage activities on various systems to continue consistent with the MODE 4 applicable requirements. I The MODE 4 requirements may only be modified for the performance of, or as a consequence of, inservice leak or hydrostatic tests, or as a consequence of control rod scram time testing initiated in conjunction with an inservice leak or hydrostatic test, so that these operations can be considered as in MODE 4, even though the reactor coolarit temperature is > 212°F. The additional requirement for secondary containment OPERABILITY according to the imposed MODE 3 provides conservatism in the response of the unit to any event that may occur. Operations in all other MODES are unaffected by this [CO. A Note has provided to modify the ACTIONS related to inservice leak and hydr6static testing operation. Settion Completion Times; specifies that.once a .Condition has been entered, divisions, supsystems, components, or. variables expressed in the Condition discovered to be br not within limits, wi 11 not result in separate entry into the .C.ondi ti on. Sectioh-1,3 also specifies that Required .Actions of the Condition to apply for each additional failure, with Completion Times 6ased on initial entry into the Condition. However, the Required Actions. for each requirement of the LCO not met provide appropriate for that are hot met. As such, a Note has been provided that allows separate Condition entry.for each of the LCO. continued B 3.10-3 Revisibn No. 129 BASES Inservice Leak and Hydrostatic Testing Operation B 3.10.1 ACTIONS A.l (continued) SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 If an LCO specified in LCO 3.10.1 is not met, the ACTIONS applicable to the stated requirements are entered immediately and complied with. Required Action A.1 has been modified by a Note that clarifies the intent of another LCO's Required Action to be in MODE 4 includes reducing the average reactor coolant temperature 212°F. A.2.1 and A.2.2 Required Action A.2.1 and Required Action A.2.2 are alternate Required Actions that can be taken instead of . Required Action A.l to restore compliance with the normal MODE 4 requirements, and thereby exit this Special Operation LCO's.Applicability. Activities that could further increase *reactor coolant or pressure are suspended immediately, in accordance with Required Action A.2.1, and the reactor coolant is reduced to establish normal MODE 4 requirements. The allowed Completion Time of 24 hours for Required Action A.2.2 is based on engineering judgment and provides sufficient time to reduce the average reactor coolant temperature from the highest expected value 212°F with normal cool down procedures. The Completion Time is also consistent with the time provided in LCO 3.0.3 to reach MODE 4 from MODE 3. SR 3.10.1.1 The LCOs made applicable are required to have their . Surveillances met to establish that this LCD is being met. A discussion of the applicable SRs is provided in their respective Bases. 1. American Society of Mechanical Engineers, Boiler and Pressure Vessel Code, Section XI. 2. UFSAR, Section 14.6.5. B 3.i'0-4 *Revision No. 129 .*

i ! ! .. . I ***:, ..... -* Reactor Mode Switch Interlock Testing B 3.10.2 B 3.10 SPECIAL OPERATIONS B 3.10.2 Reactor Mode Switch Interlock Testing BASES BACKGROUND

• APPLICABLE . SAFETY ANALYSES. PBAPS UNIT 2 The purpose of this Special Operations LCO is to permit operation of the reactor mode switch from one position to another to confirm certain aspects of associated interlocks
• during periodic tests and calibrations in MODES 3, 4, and 5. The reactor mode switch is a conveniently located,
• multiposition, keylock switch providectto select the necessary scram functions for various plant conditions .(Ref. 1). The reactor mode switch selects the appropriate trip relays for scram functions and provides appropriate bypasses. The mode switch positions and related scram interlock functions are summarized as follows: a. Shutdown-Initiates a reactor scram; bypasses main steam line isolation and main condenser low vacuum scrams; b. . Refuel -Selects Neutron Monitoring System (NMS) scram
• function for low neutron flux level operation (wide range neutron monitors and. average power range monitor setdown scram); bypasses main steam line isolation and main condenser low vacuum scrams; c. Startup /Hot Standby"'."' Selects NMS scram function for low . neutron flux _level operation (wide range neutron
• monitors and average power range monitors); bypasses
• main steam l i ne i so lat ion and main condenser low . vacuum scrams; and .
• d.
• Run .-Selects NMS *scram fun'c:t ion for power range . .. * . , /"
• The reactor mode switch also provides interlocks for such . . 'functions as control rod blocks, .scram discharge volume trip bypass, refueling .interlocks, and main steam isolation valve isolations. *
• Th, reactor mode switch interlock* testing is to prevent fUe l failure by precluding reacti vitY .* excursions or core criticality .. The interlock functions of. (continued)_ B 3.10-'"S
• Rev.ision No. 24.
• BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNIT 2 Reactor Mode Switch Interlock Testing B 3.10.2 the shutdown and refuel positions normally maintained for the reactor mode switch in MODES 3, 4, and 5 are provided to preclude reactivity excursions that could potentially result in fuel failure. Interlock testing that requires moving the reactor mode switch to other positions {run, startup/hot standby, or refuel) while in MODE 3, 4, or 5, requires administratively maintaining all control rods inserted and no other CORE ALTERATIONS in progress. With all control rods inserted in core cells containing one or more fuel assemblies, and no CORE ALTERATIONS in progress, there are no credible mechanisms for unacceptable reactivity excursions during the planned interlock testing. For postulated accidents, such as control rod removal error during refueling or loading of fuel with a control rod withdrawn, the accident analysis demonstrates that fuel failure will not occur {Refs. 2 and 3). The withdrawal of a single control rod will not result in criticality when adequate SOM is maintained. Also, loading fuel assemblies into the core with a single control rod withdrawn will not result in criticality, thereby preventing fuel failure. As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases. As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. MODES 3, 4, and 5 operations not specified in Table 1.1-1 can be performed in accordance with other Special Operations LCOs (i.e., LCO 3.10.1, "Inservice Leak and Hydrostatic Testing Operation," LCO 3.10.3, "Single Control Rod Withdrawal-Hot Shutdown, 11 LCO 3.10.4, "Sing.le Control Rod Withdrawal-Cold Shutdown," and LCO 3.10.8, "SDM Test-Refueling") without meeting this LCO or its ACTIONS. If any testing is performed that involves the reactor mode switch interlocks and requires repositioning beyond that specified in Table 1.1-1 for the current MODE of operation, the testing can be performed, provided all interlock functions potentially defeated are administratively controlled. In MODES 3, 4, and 5 with the reactor mode switch in shutdown as specified in Table 1.1-1, all control rods are fully inserted and a control rod block (continued) B 3.10-6 Revision No. O BASES LCD (continued) APPLICABILITY PBAPS UNIT 2 Reactor Mode Switch Interlock Testing B 3.10.2 is initiated. Therefore, all control rods in core cells that contain one or more fuel assemblies must be verified fully inserted while in MODES 3, 4, and 5, with the reactor mode switch in other than the shutdown position. The additional LCO requirement to preclude CORE ALTERATIONS is appropriate for MODE 5 operations, as discussed below, and is inherently met in MODES 3 and 4 by the definition of CORE ALTERATIONS,-which cannot be performed with the vessel head in-place. In MODE 5, with the reactor mode switch in the refuel position, only one control rod can be withdrawn under the refuel position one-rod-out interlock (LCO 3.9.2, "Refuel Position One-Rod-Out Interlock"). The refueling equipment interlocks (LCO 3.9.1, "Refueling Equipment Interlocks") appropriately control other CORE ALTERATIONS. Due to the increased potential for error in controlling these multiple interlocks, and the limited duration of tests involving the reactor mode switch position, conservative controls are required, consistent with MODES 3 and 4. The additional controls of administratively not permitting other CORE ALTERATIONS will adequately ensure that the reactor does not become critical during these tests. Any required periodic interlock testing involving the reactor mode switch, while in MODES l and 2, can be performed without the need for Special Operations exceptions. Mode switch manipulations in these MODES would likely result in unit trips. In MODES 3, 4, and 5, this Special Operations LCO is only permitted to be used to allow reactor mode switch interlock testing that cannot conveniently performed without this allowance or testing which must be performed prior to entering another MODE. Such interlock testing may consist of required Surveillances, or may be the result of maintenance, repair, or troubleshooting activities. In MODES 3, 4, and 5, the interlock functions provided by the reactor mode switch iri shutdown (i.e.,-all control rods inserted and incapable of withdrawal ) and refueling (i.e. , refuel i ng interlocks to prevent inadvertent criticality during CORE ALTERATIONS) positions can be administratively controlled adequately during performance of certain tests. (continued) B 3.10-7 Revision No. O BASES (continued) Reactor Mode Switch Interlock Testing B 3.10.2 ACTIONS A.1. A.2. A.3.1. and A.3.2 SURVEILLANCE REQUIREMENTS PBAPS UNIT .2 These Required Actions are provided to restore compliance with the Technical Specifications overridden by this Special Operations LCD. Restoring compliance will also result in exiting the Applicability of this Special Operations LCO. A 11 C 0 RE A L TE RA TI 0 N S ex c e pt cont r o l rod i n s e rt i o n , i f i n progress, are immediately suspended in accordance with Required Action A.l, and all insertable control rods in core cells that contain one or more fuel assemblies are fully inserted within 1 hour, in accordance with Required Action A.2. This will preclude potential mechanisms that could lead to criticality: Suspension of CORE ALTERATIONS shall not preclude the completion of movement of a component to a condition. Placing the reactor mode switch in the shutdown position will ensure that all inserted control rods remain inserted and result in operating in accordance with Table 1.1-1. if in MODE 5, the reactor mode switch may be placed in the refuel position, which will also result in operating in accordance with Table 1.1-1. A Note is added to Required Action A.3.2 to indicate that this Required A.ction is only applicable in MODE 5, since only the shutdown position is allowed in MODES 3 and 4. The allowed Completion Time of 1 hour for Required Action A.2, Required Action A.3.1, and Required Action A.3.2 provides sufficient time to normally insert the control rods and place the reactor mode switch in the required position, based on operating experience, and is acceptable given that all operations that could increase core reactivity have been suspended. SR 3.10.2.1 and SR 3:10.2.2 Meeting the requirements of this Operations LCO maintains operation consAstent with or conservative to operatirig with the reactor mode in .the shutdown p o s 1t i On
• Co r t he re f u el p o s it i on f o r MOD E 5 ) . Th e fun ct i on s of the reactor mode switch interlocks that not in effect , due to the testing i n progress , are adequate l y for by the Special Operations LCD requirements. The controls are to be verified to ensure that the operational r.equi rements conUnue to be met. The is controlled under the I* Survei.l lance Frequency Control Program. (continued) B Revision No. 86 BASES (continued) REFERENCES PBAPS UN IT 2 Reactor Mode Switch Interlock Testing B 3.10.2 1. UFSAR, Section 7.2.3.7. 2. UFSAR, Section 14.5.3.3. 3. UFSAR, Section 14.5.3.4. B 3.10-9 Revision No. 86 Single Control Rod Shutdown B 3.10.3 B 3.10 SPECIAL OPERATIONS B 3.10.3 . Single Control Rod Shutdown BASES BACKGROUND The purpose of this MODE 3 Special Operations LCO is to permit the withdrawal of a single control rod for testing while in hot shutdown, by imposing certain restrictions. In MODE 3, the reactor mode switch is in the shutdown position, and all control rods are inserted and blocked from withdrawal. Many systems and functions are not required in these conditions, due to the other installed interlocks that . are actuated when the reactor mode switch is in the* shutdown position. However, circumstances may arise while in MODE 3 that present the need to withdraw a single control rod for various tests (e.g., friction tests, scram timing, and coupling integrity checks). These single control rod withdrawals are normally accomplished by selecting the refuel position for the reactor mode switch. This Special
• Operations LCO provides the appropriate additional controls to allow a single control rod withdrawal in MODE 3. APPLICABLE With the reactor mode switch in the refuel position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these analyses are satisfied in MODE 3, these analyses will bound the consequences of an accident. Explicit safety analyses in the UFSAR (Refs. 1 and 2) demonstrate that the functioning of the refueling interlocks and adequate SOM will preclude PBAPS UNIT 2 *unacceptable reactivity excursions. Refuel1ng interlocks restrict the movement of control rods to reinforce operational procedures that prevent the reactor *from becoming critical .. These interlocks prevent the .. wi thdrawa 1 of more than one control rod. Under these conditions, since only one control rod can be withdrawn, the core will always be shut down even with the highest worth control rod withdrawn if adequate SOM exists. The control rod scram function provides backup protection to normal refueling procedures and the refueling interlocks, which prevent inadvertent criticalities during refueling. (continued) B 3.10-10 Revision No. o BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNIT 2 Single Control Rod Shutdown B 3.10.3 Alternate backup protection can be obtained by ensuring that five by five array of control rods, centered on the withdrawn control rod, are inserted and incapable of withdrawal. As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases. As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 3 with the reactor mode switch in the refuel position can be performed in accordance with other Special Operations LCOs (i.e., LCO 3.10.2, "Reactor Mode Switch Interlock Testing") without meeting this Special Operations LCO or its ACTIONS. However, if a single control rod withdrawal is desired in MODE 3, controls consistent with those required during refueling must be implemented and this Special Operations LCO applied. "Withdrawal," in this application, includes the actual withdrawal of the control rod, as well as maintaining the control rod in a position other than the *full-in position, and reinserting the control rod. The refueling interlocks of LCO 3.9.2, "Refuel Position One-Rod-Out Interlock," required by this Special Operations LCO, will ensure that only one control rod can be withdrawn. To back up the refueling interlocks (LCO 3.9.2), the ability to scram the withdrawn control rod in the event of an inadvertent criticality is provided by this Special Operations LCO's requirements in Item d.l. Alternately, provided a sufficient number of control rods in the vicinity of the withdrawn control rod are known to be inserted and incapable of withdrawal, Item d.2, the possibility of criticality on withdrawal of this control rod is sufficiently precluded, so as not to require the scram capability of the withdrawn control rod. Also, once this alternate (d.2) is completed, the SDM requirement to account for both the withdrawn untrippable (inoperable) control rod, and the highest worth control rod may be changed to allow the withdrawn untrippable (inoperable) control rod to be the single highest worth control (continued) B 3.10-11 Revision No. O Single Control Rod Withd.rawal-Hot Shutdown B 3.10.3 BASES (continued) APPLICABILITY ACTIONS
• PBAPS UNIT* 2 Control rod withdrawals are adequately controlled in MODES 1, 2, and 5 by existing LCOs. In MODES 3 and 4, control rod withdrawal is only allowed if performed in accordance with this Special Operations LCO or Special Operations LCO 3.10.4, and if limited to one control rod. This allowance is only provided with the reactor mode switch in the refuel position. For these conditions, the one-rod-out interlock (LCO 3.9.2), control rod position indication (LCO 3.9.4, wcontrol Rod Position Indication°), full insertion requirements for all other control rods and scram functions (LCO 3.3.1.1, wReactor Protection System (RPS) Instrumentation,w and LCO 3.9.5, Control OPERABILITY-Refuelingw), or the added administrative controls in Item d.2 of this Special Operations LCO, minimize potential reactivity excursi.ons. A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE 3. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition discoveredto be inoperable or not within limits, will not result in separate entry into the Condition. *section 1.3 also specifies Required Actions of-the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for each requirement of the LCO not met provide appropriate compensatory measures for separate requirements that are not met. As such, a Note .has been provided that allows separate Condition entry -for each requirement of *the *Leo. If one or more of the requirements specified in this Special Operations LCO are not met, the ACTIONS applicable to the stated requirements of the affected LCOs are immediately
• entered, as directed by Required Action A.I. Required .. Action A.l*has been modified.by*a Note that clarifies the intent of any -other LCO's Required Action to insert all control rods *. This Required *Action includes exiting this Special Operations Applicability by returning the reactor mode switch to position. _A second Note has been added, which clarifies that this Required Action is only applicable if the requirements not met are for an affected LCO. * * * * *(continued) B 3.10-12 . Revision No. o
• BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS. REFERENCES PBAPS UN IT 2 Single Control Rod Withdrawal -Hot Shutdown B 3.10.3 A.2.1 and A.2.2 Required Actions and A.2.2 are alternate Required Actions that can be taken instead of Required Action A.l to restore compliance with the normal MODE 3 requirements, thereby exiting this Special Operations LCO's Applicability. Actions must be initiated immediately to insert all insertable control rods. Actions must continue until all such control rods are fully inserted. Placing the reactor mode switch in the shutdown position will ensure all inserted rods remain inserted and restore operation in accordance with Table 1.1-1. The allowed Completion Time of 1 hour to place the reactor. mode switch in the shutdown position provides sufficient time to normally insert the control rods. SR 3.10.3.1. SR 3.10.3.2. and SR 3.10.3.3 The other LCOs made applicable in this Special Operations LCO are required to have their Surveillances met to establish that this Special Operations LCO is being met. If the local array of control rods is inserted and disarmed while the scram function for the withdrawn rod is not available, periodic verification in accordance with SR 3.lD.3.2 is required to preclude the possibility criticality. SR 3.10.3.2 has been modified by a Note, which clarifies that this SR is not required to be met if SR 3;10.3.l is satisfied for LCO 3.10.3.d.l requirements, since SR 3.10.3.2 demonstrates that the alternative LCO 3.10.3.d.2 requirements are satisfied. Also, SR 3.10.3.3 verifies that all control rods other than the control rod being.withdrawn are fully inserted. The . Surveillance Frequency is .controlled under the Surveillance Frequency Control UFSAR, Section 1:6.4; . *.-... -2. UFSAR; Section 14.5.3,3. B.3.10-13 Revision No. 86 Single Control Rod Shutdown B 3.10.4 B 3.10 SPECIAL OPERATIONS B 3.10.4 Single Control Rod Shutdown BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 The purpose of this MODE 4 Special Operations LCO is to permit the withdrawal of a single control rod for testing or maintenance, while in cold shutdown, by imposing certain restrictions. In MODE 4, the reactor mode switch is in the shutdown position, and all control rods are inserted and blocked from withdrawal. Many systems and functions are not required in these conditions, due to the installed interlocks associated with 'the reactor mode switch in the shutdown position. Circumstances may arise while in MODE 4, however, that present the need to withdraw a single control rod for various tests (e.g., friction tests, scram time* testing, and coupling integrity checks). Certain situations may also require the removal of the associated control rod drive (CRD). These single control rod withdrawals and possible subsequent removals are normally accomplished by selecting the refuel position for the reactor mode switch. With the reactor mode switch in the refuel position, the analyses for control rod refueling are applicable and, provided the assumptions of these analyses are satisfied in MODE 4, these analyses will bound the consequences of an accident. Explicit safety analyses in the UFSAR (Refs. 1 and 2) demonstrate that the functioning of *the refueling interlocks and-adequate SOM will preclude unacceptable reactivity excursions. Refueling -interlocks restrict the movement Qf control rods to reinforce operational procedures that prevent the reactor from becoming critical. These interlocks prevent the withdrawal of more than*one control rod. Under these conditions, since only one control rod can be withdrawn, the core will always be shut down even with the highest worth control rod withdrawn if adequate SOM exists. The control rod scram function provides backup protection in the event of normal refueling procedures and the refueling interlocks fail to prevent inadvertent criticalities during refueling. Alternate backup protection can be obtained by ensuring that a five by five array of control rods, centered on the withdrawn control rod, are inserted and incapable of (continued) B 3.10-14. Revision No. o.

BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNIT 2 Single Control Rod Shutdown B 3.10.4 withdrawal. This alternate backup protection is required when removing a CRD because this removal renders the withdrawn control rod incapable of being scranuned. As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases.

• As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 4 with the reactor mode switch in the refuel position can be performed in accordance.with other LCOs (i.e., Special Operations LCO 3.10.2, "Reactor Mode Switch Interlock Testing") without meeting this Special Operations LCO or its ACTIONS. If a single control rod withdrawal is desired in MODE 4, controls consistent with those required during refueling must be implemented and this Special Operations LCD applied. "Withdrawal," in this application, includes the actual withdrawal of the control rod, as well as maintaining the control rod in a position other than the full-in position, and reinserting the control rod.
• The refueling interlocks of LCO 3.9.2, "Refuel Position One-Rod-Out Interlock," required by this Special Operations LCO will ensure that only one control rod can be withdrawn. At the time CRD removal begins, the disconnection of the position indication probe will cause LCO 3.9.4, "Control Rod* Position Indication," and therefore, LCO 3.9.2 to fail to be . met *. Therefore, prior to commencing CRD removal, a control rod withdrawal block is required to be inserted to ensure *that no additio*nal control rods can be withdrawn and that *compliance with this Special Operations LCO is maintained. To back up the refueling interlocks (LCO 3.9.2) or the control rod withdrawal block, the ability to scram the. withdrawn control rod in the e.vent of an inadvertent criticality is provided by the Special Operations LCO requirements in Item c.l. Alternatively, when the scram* (continued) B 3.10-15 Revision 0 BASES LCO (continued) APPLICABILITY ACT' IONS
• PBAPS UNIT 2 Single Control Rod Shutdown B 3.10.4 function is not OPERABLE, or when the CRD is to be removed, a sufficient number of rods in the vicinity of the withdrawn control rod are required to be inserted and made incapable of withdrawal (Item c.2). This precludes the possibility of criticality upon withdrawal of this control rod. Also, once this alternate (Item c.2) is completed, the SOM requirement to account for both the withdrawn untrippable (inoperable) control rod, and the highest worth control rod may be changed to allow the withdrawn untrippable (inoperable) control rod to be the single highest worth control rod. Control rod withdrawals are adequately controlled in MODES 1, 2, and 5 by existing LCOs. In MODES 3 and 4, control rod withdrawal is only allowed if performed in accordance with Special Operations LCO 3.10.3, or this Special Operations LCO, and if limited to one control rod. This allowance is only provided with the reactor mode switch in the refuel position. During these conditions, the full insertion requirements for all other control rods, the one-rod-out interlock (LCO 3.9.2), control rod position indication (LCO 3.9.4), and scram functions (LCO 3.3.1.1, nReactor Protection System (RPS) Instrumentation,n and LCO 3.9.5, ncontrol Rod or the added administrative controls in Item b.2 and Item c.2 of this Special Operations LCO, provide mitigation of potential reactivity excursions. A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE 4. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for each requirement of the LCO not met provide appropriate compensatory measures for separate requirements that are not met. As such, a Note has been provided that allows separate Condition entry for each requirement of the LCO. (continued) 8 3.10-16 Revision No. O BASES ACTIONS (continued) . PBAPS UNIT 2 Single Control Rod Shutdown B 3.I0.4 A.I. and A.2.2 If one or more of the requirements of this Special Operations LCO are not met with the affected control rod insertable, these Required Actions restore operation consistent with normal MODE 4 conditions (i.e., all rods inserted) or with the exceptions allowed in this Special Operations LCO. Required Action A.I has been modified by a Note that clarifies that the intent of any other LCO's Required Action is to insert all control rods. This Required Action includes exiting this Special Operations Applicability by returning the reactor mode switch to the shutdown position. A second Note has been added to Required Action A.I to clarify that this Required Act;on is only applicable if the requirements not met are for an affected LCO.
• Required Actions A.2.I and A.2.2 are specified, based on the assumption that the control rod is being withdrawn. If the control rod is still insertable, actions must be inunediately initiated to fully insert all insertable control rods and . within 1 hour place the reactor mode switch in the shutdown *position. Actions must continue until all such control rods are fully inserted. The allowed Completion Time of I hour for placing the reactor mode switch in the shutdown position provides sufficient time to normally insert the control rods.
• B. I. B. 2 . I. and B. 2. 2 . If one or more of the requirements of this Special Operations.Leo are not met with the affected control rod not insertable, withdrawal of the control rod and removal of the associated CRD must be immediately suspended. If the CRD has been removed, such that the control rod is not insertable, the.Required Actions require the most expeditious action be taken. to either initiate action.to restore the CRD. and insert its control rod, or initiate . action to restore compliance with this Special Operations . (continued) *B 3.10-17 Revision No. O BASES (continued) SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT_ 2 Single Control Rod Withdrawal-Cold Shutdown B 3.10.4 SR 3.10.4.1. SR 3.10.4.2. SR 3.10.4.3. and SR 3.10.4.4 The other LCOs made applicable by this Special Operations LCO are required to have their associated surveillances met to establish that this Special Operations LCO is being met. If the local array of control rods is inserted and disarmed while the scram function for the withdrawn rod is not available, periodic verification is required to ensure that the possibility of criticality remains precluded. Verification that all the other control rods are fully inserted is required to meet the SOM requirements. Verification that a control rod withdrawal block has been inserted ensures that no other rods can be inadvertently withdrawn under conditions when position indication instrumentation is inoperable the affected control rod. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.10.4.2 and SR 3.10.4.4 have been modified by Notes, which clarify that these SRs are not required to be met if the alternative requirements demonstrated by SR 3.10.4.1 are satisfied. 1. UFSAR, Section 7.6.4. 2. UFSAR, Section 14.5.3.3. B 3.10-18 Revi s-i_on No. 86 Single CRD Removal-Refueling B 3.10.5 B 3.10 SPECIAL OPERATIONS B 3.10.5 *Single .Control Rod Drive (CRD) Removal-Refueling BASES BACKGROUND . PBAPS UNIT 2 The purpose of this MODE 5 Special Operations LCO is to permit the removal of a single CRD during refueling operations by imposing certain administrative controls. Refueling interlocks restrict the movement of control rods and the operation of the refueling equipment to reinforce operational procedures that prevent the reactor from becoming critical during refueling operations. During refueling operations, no more than one control rod.is permitted to be withdrawn from a core cell containing one or more fuel assemblies. The refueling interlocks use the "full-in" position indicators to determine the position of all control rods. If the "full-inn position signal is not present for every control rod, then the all rods in permissive for the refueling equipment interlocks is not present and fuel loading is prevented. Also, the refuel position one-rod-out interlock will not allow the withdrawal of a second control rod. The control rod scram function provides backup protection in the event normal refueling procedures, and the refueling interlocks described above fail to prevent inadvertent criticalities during refueling. The requirement for this function to be OPERABLE precludes the possibility of removing the CRD once a control rod is withdrawn from a core cell containing one or more fuel assemblies. This Special Operations lCO provides controls sufficient to ensure the possibility of an inadvertent criticality is precluded, while allowing a single CRD to be removed from a core cell containing one or more fuel assemblies. The removal of the CRD involves disconnecting the position indication probe, which causes noncompliance with LCO 3.9.4, "Control Rod Position Indication," and, therefore, LCO 3.9.1, "Refueling Equipment Interlocks,n and LCO 3.9.2, nRefueling Position One-Rod-Out Interlock.n The CRD removal also requires isolation of the CRD from the CRD Hydraulic thereby causing inoperability of the control rod (LCO 3.9.5, "Control Rod OPERABILITY-Refueling"). (continued) B 3.10-19 Revision No. O .

BASES (continued) Single CRD l B 3.10.5 APPLICABLE With the reactor mode switch in the refuel position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these analyses are satisfied, these analyses will bound the consequences of accidents. Explicit safety analyses in the UFSAR (Refs. 1 and 2) demonstrate that proper operation of the refueling interlocks and adequate SDM will preclude unacceptable PBAPS UNIT 2 reactivity excursions.

• Refueling interlocks restrict the movement of control rods and the operation of the refueling equipment to reinforce operational procedures that prevent the reactor from .becoming critical. These interlocks prevent the withdrawal of more than one control rod. Under these conditions, since only one control rod can be withdrawn, the core will always be shut down even with the highest worth control rod withdrawn if adequate SDM exists. By requiring all other control rods to be inserted and a control rod withdrawal block initiated, the function of the inoperable one-rod-out interlock (LCO 3.9.2) is adequately maintained. This Special Operations LCO requirement to suspend all CORE ALTERATIONS adequately compensates for the inoperable all rods in permissive for the refueling equipment interlocks (LCO 3.9.1). The control rod scram function provides backup protection to normal refueling procedures and the refueling interlocks, which prevent inadvertent criticalities during refueling. Since the scram function and refueling interlocks may be suspended, alternate backup protection required by this Special Operations LCO is obtained by ensuring that a five by five array .of control rods, centered on the withdrawn control rod, are inserted and are incapable of be.ing withdrawn, and all other control rods are inserted and incapable of being withdrawn (by insertion of a control rod block). As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion. of the criteria satisfied for the other LCOs is provided in their respective Bases. "{continued) B 3.10*20 Revision No. O Single CRD B 3.10.5 BASES (continued) APPLICABLE With the reactor mode switch in the refuel position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these analyses are satisfied, these analyses will bound the consequences of ac.cidents. ExpHcit safety analyses in the UFSAR (Refs. 1 and 2) demonstrate.that proper operation of the refueling interlocks and adequate SOM will preclude unacceptable . PBAPS. UNIT 2 reactivity excursions. ** Refueling interlocks restrict the movement of control rods and the operation of the refueling equipment to reinforce operational procedures that prevent the reactor from becoming critical. These interlocks prevent the withdrawal of more than one control rod. Under these conditions, since only one control rod can be withdrawn, the core will always be shut down even with the highest worth control rod withdrawn if adequate SDM exists. By requiring all other control rods to be inserted and a control rod withdrawal block initiated, the function of the inoperable one-rod-out interlock (LCO 3.9.2) is adequately maintained. This Special Operations LCO requirement to suspend all CORE ALTERATIONS adequately compensates for the inoperable all rods in permissive for the refueling equipment interlocks (LCO 3.9.1). .
• The. control rod s.cram function provides backup protection to normal refueling procedures and the refueling interlocks, which prevent inadvertent criticalities during refueling. *Since the scram function and refueling interlo.cks may be suspended, *alternate backup protection required by this Special Operations LCO is obtained by ensuring that a five by five array of control rods, centered on the withdrawn control rod, are* inserted and are incapable of being *.*withdrawn, and all other control rods are inserted and incapable of befog withdrawn, {by. insertion of a control rod * * * * . . . *-As described in LCO 3.0.7, compliance with Special.* Operations LCOs is optional, and therefore, rio criteria of ,: the NRC Poficy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is prov_1ded 1n their respective Bases. "(continued) 8 3. l0-2<t Revision*No. 0 Single CRD
• B 3.10.5 BASES (continued) LCO APPLICABILITY' PBAPS UNIT.2 As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 5 with any of the following LCOs, LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," LCO 3.3.8.2, "Reactor Protection System (RPS) Electric Power Monitoring," LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, or LCO 3.9.5 not met, can be performed in accordance with the Required Actions of these LCOs without meeting this Special Operations LCO or its ACTIONS. However, if a single CRD removal from a core cell containing one or more fuel assemblies is desired in MODE 5, controls consistent with those required by LCO 3.3.1.1, LCO 3.3.8.2, LCO LCO 3.9.2, LCO 3.9.4, and LCD 3.9.5 must be implemented, and this Special Operations LCO applied. By requiring all other control rods to be inserted and a contro.l rod withdrawal block initiated, the function of the
• inoperable one-rod-out interlock (LCD 3.9.2) is adequately maintained. This Special Operations LCD requirement to suspend all CORE ALTERATIONS adequately compensates for the inoperable all rods in permissive for the refueling equipment interlocks (LCD 3.9.1). Ensuring that the five by five array of control rods, centered on the withdrawn control rod, are inserted and incapable of withdrawal adequately satisfies the backup protection that LCD 3.3. I. I and LCO 3.9.2 would have otherwise provided. Also, once these requirements (Items a, b, and c) are completed, the SOM requirement to account for both the withdrawn untrippable (inoperable) control rod and the highest worth control rod may be changed to allow the withdrawn untrippable (inoperable) control. rod to be the single highest worth control rod. . . in MODE 5 is controlled by existing LCOs. The allowance to comply wit_h :this Special Operations LCO in l feu of the ACTIONS of LCO LCO LCD 3.9.1, LCO 3.9.2, LCD 3.9.4, and LCD 3.9.5 is appropriately controlled with the additional administrative controls .. requiredby this Special Opera:tions lCO, which reduce the potential.for reactiyity excursions. (continued) B 3.J0.;.21 RevisiOn No.* 0 BASES (continued) Single CRD Removal-Refueling B 3.10.5 ACTIONS A.l. A.2.1. and A.2.2 SURVEILLANCE REQUIREMENTS PBAJJS UNIT 2 If one or more of the requirements of Special Operations LCO are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements for failure to meet LCO 3.3.l.l, LCO 3. 9. 1, LCO. 3. 9. 2, LCO 3. 9. 4, and LCO 3. 9. 5 ( i . e. , a 11 control rods inserted) or with the allowances of this Special Operations LCO. The Completion Times for Required Action. A.l, Required Action A.2.1, and Required Action A.2.2 are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious manner to either initiate action to restore the CRD and insert its control rod, or initiate action to restore compliance with this Special Operations LCO. Actions must continue until either Action A.2.1 or Required Action A.2.2 is satisfied. SR 3.10.5.1. SR 3.10.5.2. SR 3.10.5.3. SR 3.10.5.4. and SR 3.10.5.5 Verification that the control rods, other the control rod withdrawn for the removal of the associated CRD, are fully inserted is to ensure the SOM is within limits. Veri fi cation that the local five by five array of control rods, other than the control rod withdrawn for removal of the associated CRD, is inserted and disarmed, while the scram function for the withdrawn rod is not ava1lable, is required to ensure that the possibility of criticality remains precluded. Verification that a control rod withdrawal block has been inserted .ensures that no .other contrdl rods can be inadvertently conditions when position indication instrumentation is for the withdrawn rod. The Surveillance for LCO 3.1.1, which is made applicable by.this Special Operations LCO, is required in order to establish that this Special Operations LCO is being met. Verification that no other CORE ALTERATIONS are being made is required to ensure the assumptions of the safety analysis are satisfied. Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. The Surveillance Frequency is controlled under the Surveillance Frequency Contra l Program. (continued) B 3.10-22 Revision No. 86 BASES (continued) REFERENCES PBAPS UNIT 2 1. UFSAR, Section 7.6.4. 2. UFSAR, Section 14.5.3.3. B 3.10-23 Single CRD B 3.10.5 Revision No. 0 Multiple Control Rod Withdrawal-Refueling B 3.10.6 B 3 .10 SPECIAL OPERATIONS B 3.10.6 .Multiple Control Rod Withdrawal-Refueling BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 2 The purpose of this MODE 5 Special Operations LCO is to pennit multiple control rod withdrawal during refueling by imposing *certain administrative controls. Refueling interlocks restrict the movement of control rods and the operation of the refueling equipment. to reinforce operational procedures that prevent the reactor from becoming critical during refueling operations. During refueling operations, no more than one control rod is permitted to be withdrawn from a core cell containing one or more fuel assemblies. When all four fuel assemblies are removed from a cell, the control rod may be withdrawn with no restrictions. Any number of control rods may be withdrawn and removed from the reactor vessel if their cells contain no fuel. The refueling interlocks use the "full-in" position indicators to detennine the position of all control rods. If the "full-in" position signal is not present for every control rod, then the all rods in pennissive for the refueling equipment interlocks is not present and fuel loading is prevented. Also, **the refuel position one-rod-out interlock will not allow the withdrawal of a second control rod. To allow more than* one control rod to be withdrawn during refueling, these interlocks must be defeated. This Special Operations LCO establishes the necessary administrative controls to allow bypassing the "full-in" position indicators. Explicit safety analyses in the UFSAR (Refs. 1, 2, and 3) demonstrate that the functioning of the refueling interlocks and adequate SOM will prevent unacceptable reactivity excursions during refueling. To allow multiple control rod withdrawals, control rod removals, associated control rod drive (CRD) removal, or any combination of these, the "full in" position indication is allowed to be bypassed for each withdrawn control rod if all fuel has been removed from the cell. With no fuel assemblies in the core cell, the (continued) B 3.10-24 Revision No. 0

-I BASES APPLICABLE SAFETY ANALYSES (continued) LCO . PBAPS UNIT

• 2 Multiple Control Rod Withdrawal-Refueling B 3.10.6 associated control rod has no reactivity control function and is not required to remain inserted. Prior to reloading fuel into the cell, however, the associated control rod must be inserted to ensure that an inadvertent criticality does not occur, as evaluated in the Reference 3 analysis. As described in LCO 3.0.7, compliance with Special* Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases. As described.in LCO 3.0.7, compliancewith this Special Operations LCO is optional. Operation in MODE 5 with either LCO 3.9.3, "Control Rod Position,11 LCO 3.9.4, "Control Rod Position Indication," or LCO 3.9.5, "Control Rod OPERABILITY-Refueling," not met, can be performed in accordance with the Required Actions of these lCOs without meeting this Special Operations LCO or its ACTIONS. If multiple control rod withdrawal or removal, or CRD removal is desired, all four fuel assemblies are required to be
• removed from the associated cells. Prior to entering this LCO, any fuel remaining in a cell whose .CRD was previously removed. under the provisions *of another LCO must be removed. "Withdrawal," in this application, includes the actual withdrawal of the control rod, as well as maintaining the control rod in a position other than the full-in position, and.re1nserting the control rod. Wh.en fuel is loaded into the multiple control rods. withdti,twn, special* modified quadrant spiral reload sequences are used to ensure that reactivity additions are minimized. Spiral reloading encompasses. reloading a cell (four fuel . locations inmedtately adjacent to* a control rod) on the edge of a continuous fueled region (the cell can be loaded .in any sequence) *. all control rods must be.fully *
• inserted before loading fuel. * * * * * (continued) *B 3.10-25 Revision No. o
• BASES (continued) APPUCABI LITY ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 2 Multiple Control Rod Withdrawal-Refueling B 3.10.6 Operation in MODE 5 is controlled by existing LCOs. The exceptions from other LCO requirements (e.g., the ACTIONS of LCO 3.9:3, LCO 3.9.4, or LCO 3.9.5) allowed by this Special Operations LCO are appropriately controlled by requiring all fuel to be removed from cells whose "full-in" indicators are allowed to be bypassed. A.1. A.2. A.3.1. and A.3.2 If one or more of the requirements of this Special Operations LCO are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements.for refueling (i.e., all control rods inserted in core cells containing one or more fuel assemblies) or with the exceptions granted by this Special Operationi LCO. The Completion Times for Required Action A.l, Action A.2, Required Action A.3.1, and Required Action A.3.2 are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious manner to sither initiate to restore the affected CRDs and insert their control rods, or initiate action to restore compliance with this Special Operations LCO. SR 3.10.6.1. SR 3.10.6.2. and SR 3.10.6.3 Periodic verification of the controls* established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. The -Surveillance Frequency is contrblled under the Surveillance Frequency Control_ Program. 1.. Section 7;6.4. Section .14.5.3.3. 3. Section -14.5.3:4. B 3.J0-26. Revis-ion No. 86 Control Rod B 3.10.7 B 3 .10 SPECIAL OPERATIONS B 3.10.7 Control Rod BASES BACKGROUND . . APPLICABLE SAFETY ANALYSES . PBAPS UNIT 2 The purpose of this Special Operations LCO is to perm;t control rod testing, while in MODES 1 and 2, by imposing certain administrative controls. Control rod patterns during startup conditions are controlled by the operator and the rod worth minimizer (RWM) (LCO 3.3.2.1, "Control Rod Block Instrumentation"), such that only the specified control rod sequences and relative positions required by LCO 3.1.6, wRod Pattern Control," are allowed over.the operating range from all control rods inserted to the low power setpoint (LPSP) of the RWM. The sequences effectively limit the potential amount and rate of reactivity increase that could occur during a control rod drop accident (CRDA). During these conditions, control rod testing is sometimes required that may result in control rod patterns not in compliance with the prescribed sequences of LCO 3.1.6. These tests include SOM demonstrations, control rod scram time testing, control rod friction testing, and testing performed during the Startup Test Program. This Special Operations LCO provides the ne.cessary exemption to the requirements of LCO 3.1.6 and provides additional administrative controls to allow the deviations in such tests from the prescribed sequences in LCO 3.1.6
• The analytical methods and assumptions used in evaluating the CRDA .are sununarized in References 1 and 2. *CRDA ana 1 yses assume the reactor operator fo 11 ows prescribed
• withdrawal sequences. These sequences define the potential initial conditions for the CRDA analyses. The RWM provides backup to operator control of the withdrawal sequences to ensure the initial conditions of the CRDA analyses are not violated. For special sequences developed for control rod testing, the initial control rod patterns assumed in the safety analysis of References 1 and 2 may not be preserved. Therefore special CRDA analyses are required to demonstrate that these special sequences will not result in unacceptable consequences, should a CRDA occur during the testing. These analyses, performed in accordance with an NRC approved methodology, are dependent on the specific test being perf o .. rmed. (continued) B 3.10-27 Revision No. o
• BASES Control Rod Testing-Operating B 3.10.7 APPLICABLE SAFETY ANALYSES (continued) As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases. LCO As described in LCO 3.0.7, compliance with this Special Operations LCD is optional. Control rod testing may be performed in compliance with the prescribed sequences of LCD 3.1.6, and during these tests, no exceptions to the requirements of LCO 3.1.6 are necessary. For testing performed with a sequence not in compliance with LCD 3.1.6, the requirements of LCO 3.1.6 may be suspended, provided additional administrative controls are placed on the test to ensure that the assumptions of the special safety analysis for the test sequence are satisfied. Assurances that the test sequence is followed can be provided by either progrananing the test sequence into the RWM, with conformance verified as specified in SR 3.3.2.1.8 and allowing the RWM to monitor control rod withdrawal and provide appropriate control rod blocks if necessary, or by verifying conformance to the approved test sequence by a second licensed operator or other qualified member of the technical staff. These controls are consistent with those normally applied to operation in the startup range as defined in the SRs and ACTIONS of LCO 3.3.2.1, "Control Rod Block Instrumentation." APPLICABILITY Control rod testing, while in MODES 1 and* 2, with THERMAL POWER greater than 10% RTP, is adequately controlled by the PBAPS UNIT 2
• existing LCOson power distribution limits and control rod block instrumentation .. Control rod movement during these conditions is not restricted to prescr1bed sequences and can be performed within the constraints of LCD 3.2.1, "AVERAGE .PLANAR LINEAR HEAT GENERATION RATE (APLHGR), 11 LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO. (MCPR), 11 LCO 3.2.3, "LINEAR GENERATION RATE (LHGR)," and LCO 3 .3 .2.1. With THERMAL POWER less than or equal to 10%* RTP, the provisions of this Special Operations*LCO are necessary to perform special tests that are not in conformance with the prescribed sequences of LCO 3 .1. 6. While in MODES 3 and 4, contra 1 rod
• withdrawal is only allowed if performed in accordance with (continued} B 3.10-28 Revision No. 0 BASES APPLICABILITY (continued) ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 2 Control Rod Testing-Operating B 3.10.7 Special Operations LCO 3.10.3, "Single Control Rod Withdrawal-Hot Shutdown," or Special Operations LCO 3.10.4, "Single Control Rod Withdrawal-Cold Shutdown," which provide adequate controls to ensure that the assumptions of the safety analyses of Reference 1 and 2 are satisfied. During these Special Operations and while in MODE 5, the one-rod-out interlock {LCO 3.9.2, "Refuel Position One-Rod-Out Interlock,") and scram functions {LCO 3.3.1.1, "Reactor Protection System {RPS) Instrumentation," and LCO 3.9.5, "Control Rod OPERABILITY-Refueling"), or the added administrative controls prescribed in the applicable Special Operations LCOs, provide mitigation of potential reactivity excursions. With the requirements of the LCO not met {e.g., the control rod pattern is not in compliance with the special test sequence, the sequence is improperly loaded in the RWM) the testing is required to be immediately suspended. Upon suspension of the special test, the provisions of LCO 3.1.6 are no longer excepted, and appropriate actions are to be taken to restore the control rod sequence to the prescribed sequence of LCO 3.1.6, or to shut down the reactor, if required by LCO 3.1.6. SR 3.10.7.1 With the special test sequence not programmed into the RWM, a second licensed operator or other qualified member of the technical .staff {i.e., personnel trained in accordance with an approved training program for this test) is required to verify conformance with the approved sequence for the test. This verification must be performed during control rod movement to prevent deviations from the specified sequence. A Note is added to indicate that this Surveillance does not need to be met if SR 3.10.7.2 is satisfied. (continued) B 3.10-29 Revision No. 0 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UNIT 2 Control Rod Testing-Operating B 3.10.7 SR 3.10.7.2 When the RWM provides conformance to the special test sequence, the test sequence must be verified to be correctly loaded into the RWM prior to control rod movement. This Surveillance demonstrates compliance with SR 3.3.2.1.B, thereby demonstrating that the RWM is OPERABLE. A Note has been added to indicate that this Surveillance does not need to be met if SR 3.10.7.1 is satisfied. 1. NEDE:-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision. 2. Letter from T. Pickehs (BWROG) to G.C. Lainas (NRC) "Amendment 17 to.General Electric Licensing Topical Report NEDE-24011-P-A," August 15, 1986. *--, .. . --'. B 3.10-30 Revision No. 72 I SDM Test -Refueling B 3.10.8 B 3.10 SPECIAL OPERATIONS B 3.10.8 SHUTDOWN MARGIN (SDM) Test-Refueling BASES BACKGROUND APPLICABLE SAFETY*ANALYSES PBAPS UNIT 2 The purpose of this MODE 5 Special Operations LCO is to permit SDM testing to be performed for those plant configurations in which the reactor pressure vessel (RPV) head is either not in place or the head bolts are not fully *tensioned. LCO 3. I. I, 11 SHUTDOWN MARG IN ( SDM) , 11 re11u ires that adequate SDM be demonstrated following fuel movements or control rod replacement within the RPV. The demonstration must be performed prior to or within 4 hours after criticality is reached. This SDM test may be performed prior to or during the first startup following the refueling. Performing the SDM test prior to startup requires the test to be performed while in MODE 5, with the vessel head bolts less than fully tensioned (and possibly with the vessel head removed). While in MODE 5, the reactor mode switch is required to be in the shutdown or refuel position, where the applicable contrbl rod blocks ensure that the reactor will not become critical. The SDM test requires the reactor switch to *be in the startup/hot standby position, since more than one control rod will be withdrawn for the purpose of demonstrating adequate SDM .. This Special Operations LCO provides the appropriate additional controls to allow withdrawing more than one control rod from a core cell containing one or more fuel assemblies when the reactor vessel head bolts are less than fully tensioned. . --, . Prevention atid mitigation of unacceptable reactivity
• excursions during control rod.withdrawal, with the reactor mode switch in the startup/hot standby pas it ion while i.n MODE 5, is provided by the wide range neutron monitor (WRNM) period-short scram (LCO 3.3.l.l, "Reactor Protection System .(RPS) .fostrumentatjon"), and control rod block (LCO "Control Rod Block The limiting reactivity excursion during cbnditi6ns while in MODE 5 the control rod drop .accident (CRDA) .* (continued) B 3 .10-:31 Revision No. 24 SDM Test -Refueling B 3.10.8 B 3.10 SPECIAL OPERATIONS B 3.10.8 SHUTDOWN MARGIN (SDM) Test-Refueling BASES BACKGROUND The purpose of this MODE 5 Special Operations LCD is to permit SDM testing to be performed for those plant configurations in which the reactor pressure vessel (RPV) head is either not in place or the head bolts are not fully tensioned.
• LCO 3.1.1:, "SHUTDOWN MARGIN (SDM)," that adequate SDM be demonstrated following fuel movements or control rod replacement within the RPV. The demonstration must be performed prior to or within 4 hours after criticality is reached. This SDM test may be performed prior to or during the first startup following the refueling. Performing the SDM test prior to startup requires the test to be performed while in MODE 5, with the vessel head bolts less than fully tensioned (and possibly with the vessel head removed). in MODE 5, the reactor mode switch is required to be in the shutdown or refuel position, where the applicable control rod blocks ensure that the reactor will not become critical. The SDM test requires .the reactor mode switch to be in*the startup/hot standby position, since more than one control rod will be withdrawn for the.purpose of demonstratin*g adequate SDM. This Special Operations LCO the appropriate additional controls to allow withdrawing more than one control-rod from a core cell containing one or more assemblies when the reactor vessel head bolts are less than fully tensioned. APPLICABLE . Prevention of reactivity SAFETY.ANALYSES excursions during *control. rod withdrawal, with the reactor. niode* switch in the startup/hot' standby position while in MODE 5*, is provided by the wide range neutron monitor (WRNM) peri od.:..:short 'scram {LCO 3. 3 .. 1.1, II Reactor Protection system PBAPS UNIT 2 *{RPS) JnstrumentatiOn), *and control rod block
• instrumentation: (LCD ",Control' Rod Block Instrumenta:ticm"). The limiting reactivity excursion during startup in MODE 5 is the control rod drop accident (CRDA) .. . > . . * (continued) .B 3.10-31 __ .. ** Revision No. 24 BASES. APPLICABLE SAFETY. ANALYSES -(continued) [CO_._* , :* .. ; . *:, SOM Test -Refueling . B 3.10.8 CRDA analyses assume that the reactor operator follows . prescribed withdrawal sequences. For SOM tests performed within-these defined sequences, the analyses of References-I and 2 applicable. However, for some sequences developed for the SOM testing, the control rod.patterns assumed in the safety analyses of References 1 and 2 may not be met. Therefore, special CRDA performed in accordance with an NRC approved methodology, are required to demonstrate the SOM test -sequence will not result in *unacceptable consequences should a CRDA occur during the testing. *For-the of this test, the protection *provided by the normally required MODE 5 applicable LCOs, in addition to the requirements of this LCO, will maintain normal test operations as well as postulated accidents within the bounds of the appropriate safety analyses (Refs._l*and In addition to the added requirements for the RWM, WRNM, APRM, and control rod coupling, the notch out _mode. is* specified for out_ of sequence withdrawals. Requiring.the notch out Diode .limits withdrawal steps to a single notch, .which inserted reactivity, and allows adequate monitoring of changes in neutron flux, whi.ch may As in LCO 3.0;7, compliance with Special*. _ -Operations LCOs is optional, and no :criteria of -the NRC Pol icy S_tatement apply. Special Operations LCOs .
• prov-ide flexi.bil ity to perform certain operations by appropriately modifying reqti irements of other LCOs. A discuss.ion of the .criteria* satisfied for. the other LCOs is i>tovi de,d in their ve Ba.ses. ---*Ai in *LCO 3.0.7, compl ianc.e this Special
• Operations Leo is optional. SDM tests may* be performed while* in MODE* 2, *in. accordance Ll-1, without* *_ . meetH1g thiS Sped al .Operations. LCO or** i_ts< ACTIONS. Jor SOM __ tests-performed. while in MODE 5, additional. requirements _
• must be'met to-ensure that adequate* protection against** .... * .' *:: . -*:, _:** . PBAJS. UN.It 2 .* potenti:al* .. reactivity excursions is avai Table.* To provi.de . .. additional beyond*-the norma-1 ly required WRNMs, the APRMs' *are. also requi:red .to be OPERABLE (LCO . __ . 3 /3. Junct tons 2a, .2 .d and* 2e) though the reactqr * . *
• were <in* MODE 2:
• Because multiple control rods will be . . _ wi thdr_awn and the reactor \'lil l potent i _ally. become .. cri ti ca_l ' *. * . the approved *control rod_ withdrawal sequ*ence -must be _... * '.enforced by theiRWM Function* 2, MODE. 2r, . *mus_t be:verified by a ----* * * * * * ***** .* . " .. '* ...... -*:.:' . * * * -(contH1ued) ' .. * .. : *; . .. ' .. , : .* . *-. *
• a ' '. .. *.. . Revi sion*:No. *as*--* "-.> ... . ... *.*.

BASES LCO (continued) APPLICABILITY ACTIONS PBAPS UN IT 2 SOM Test-Refueling B 3.10.8 second licensed operator or other qualified member of the technical staff. To provide additional protection against an inadvertent criticality, control rod withdrawals that do not conform to the analyzed rod position sequence specified in LCO 3.1.6, "Rod Pattern Control," (i.e., out of sequence control rod withdrawals) must be made in the individual notched withdrawal mode to minimize the potential reactivity insertion associated with each movement. Coupling integrity of control rods is required to minimize the probability of a CRDA and ensure proper functioning of the withdrawn control* rods, if they are required to scram. Because the reactor vessel head may be removed during these tests, no other CORE ALTERATIONS may be in progress. Furthermore, since the control rod scram function with. the RCS at atmospheric pressure relies solely on the CRD accumulator, it essential that the CRD charging water header remain pressurized. This Special LCO then a1lows changing the Table 1.1-1 reactor mode switch position requirements to include the startup/hot standby position, such that the SOM tests may be performed while in MODE 5. These SOM test Special Operations requirements are only applicable if the SOM tests are to be performed while in MODE 5 with the reactor vessel head rem6ved or the head bolts not fully tens.ioned. Additional* requirements during these* to enforce contro1 rod sequences and restrict other CORE ALTERATIONS provide protection against potential reactivity excursions. Operations in all other MODES are unaffected by this LCO. A.l andA.2 With one or more control rods discovered uncoupled during this Special Operation, a controlled insertion of each uncoupled control rod is either to attempt recoupling, or to preclude a control rod drop. This controlled insertion is preferred since, if the control rod fails to* follow the drive as it is withdrawn Ci .e., is "stuck" in an inserted position), placing the reactor mode switch in the shutdown position per Required Action B.l could cause substantial secondary damage. If recoupling is not accomplished, operation may continue, provided the. control rods are fully inserted within 3 hours and disarmed {electrically or hydraulically) within. 4 hours. Inserting a continued B Revision No. 63 BASES ACTIONS I 1, . PBAPS UNIT 2 A.I and A.2 (continued) SOM B 3.10.8 control rod ensures the shutdown and scram capabilities are not adversely affected. The control rod is disarmed to prevent inadvertent withdrawal during subsequent operations. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve solenoids. Required Action A.I is modified by a Note that allows the RWM to be bypassed if required to allow insertion of the inoperable control rods and continued operation. LCO 3.3.2.I, ncontrol Rod Block Instrumentation," ACTIONS provide additional requirements when the RWM is bypassed to ensure compliance with the CRDA analysis.

• The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control rods in an orderly manner and without challenging plant systems. Condition A is modified by a Note allowing separate Condition entry for each uncoupled control rod. This is acceptable since the Required Actions for this Condition provide appropriate compensatory actions for each uncoupled
• control rod. Complying with the Required Actions may allow for continued operation. Subsequent uncoupled control rods are governed by subsequent entry into the Condition and application of the Required Actions. B. I With one. or more of the requirements of this LCO not 'met for. reasons other than an uncoupled control rod, the testing .. should be inmediately stopped by placing the reactor mode switch in the shutdown or refuel position. This results in a condition that is consistent with the requirements for MODE 5 where the provisions of this Special Operations LCO
• are no longer required. (continued) B 3.10-34 Revision No. O SOM Test-Refueling B 3.10.8 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 2 SR 3.10.8.1. SR 3.10.8.2. and SR 3.10.8.3 LCO 3.3.1.1, Functions 2a, 2.d and 2e, made applicable in this Special Operations LCD, are required to have their Surveillances met to establish that this Special O'perations LCO is being met. However, the control rod withdrawal sequences during the SOM tests may be enforced by the RWM CLCO 3.3.2.1, Function 2, MODE 2 requirements) or by a second licensed operator or other qualified member of the technical staff. As noted, either the applicable SRs for the RWM CLCO 3.3:2.1) must be satisfied according to the appltcable Frequencies CSR 3.10.8.2), or the proper movement of control rods must be verified CSR 3.10.8.3). This latter verification Ci .e., SR 3.10.8.3) must be performed during control rod movement to prevent deviations from the specified sequence. These surveillances provide adequate assurance that the spectfied test sequence is being foll owed . . SR 3.10.8.4 Periodic verification of the administrative controls by this LCO will ensure that the reactor is operated within the bounds of the safety analysis. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.10.8.5 Coupling verification is to ensure the control rod is connected to the control rod drive mechanism and will perform its intended function when necessary. The verification is required to be performed any time a control rod is withdrawn to the "full out" notch position, or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This Frequency is considering the low probability that a control rod will become uncoupled when it is not being moved as well as operating experience related to uncoupling events. continued B 3.10-35 Revision No. 86 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES .. **, .. PBAPS UN IT 2 .. SOM Test-Refueling B 3.10.8 SR 3.10.8.6 CRD charging water header pressure verification is performed to ensure the motive force is to scram the control rods in the event of a scram signal. Since the reactor is depressurized in MODE 5, there is insufficient reactor pressure to scram the control rods. Verification of charging water header pressure ensures that if a scram were required,.capability for rapid control rod insertion would exist. The minimum pressure of 940 psig is well below the expected pressure of approximately 1450 psig while still ensuring sufficient pressure for rapid control rod irisertion. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," la test approved revi !;ii on. 2. Letter from T. Pickens (BWROG) to G.C. Lainas, NRC, "Amendment 17 to General Electric Licensing Topical Repbrt NEDE-24011-P-A," August 15, 1986 . ' .. .! -.. * --* .* . B 3.10-36 Revision No. 86 I . ------* -PECO ENERGY . Peach Bottom Atomic Power Station *IMPROVED TECHNICAL . SPECIFICATIONS .{UNIT#3 BASES) * ' *' . .. *_, ' .. **... ,_* . . . . ' . . . -.*. -*: -. . * .. -. ' . -I . ' .*.:.

.,,. ' **t PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B TABLE OF CONTENTS page(s)

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I I I I PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.1 REACTIVITY CONTROL SYSTEMS (continued) page(s) 3.1-25 **.....*...*.**...***. : **......*..*......*.*....*.*...*..**..*..***..*.*..*..*..*.....**...***.*.....*.*.*. Rev 58

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• 3.3-83 .****** : .*.*****.**************.*.**. : .* ; ************ ; .............................................. : ****** Rev 134 89 (inch.isive)' .............. : ........ : ....... .' *.*.* *: ......... .' *** : ............... ; .............. ;. Rev 3 3.3-90 *** , ..... ;.; **... .... * **** ; *.*.*.****.** : *. :* ** * *.*** : .*.* ; *.**...**.**. ; ********.***.** :: **** ; ** _ ** :;.; *** **** Rev 87 . 3,3-9t ............. :*:; .. *: ** : .... .* ;;; *. ;* **. .':.; .............. *.; .......................... ; *.*** : **.*.*.*****. , Rev 87 _3,3.;92 ..... : .. : *.** .' *.*. , ** :; *.** :* ***.*.*. ; *.* ;.,',;; .. ;,; .....* .*. ; .*.**.*. : ....*. : .*..*.***.**.*. :.' **.****.***..** Rev *97
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PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING 8 3.3 INSTRUMENTATION (continued) . page(s) 3.3-112 *.*.*....****..**.*********.***...**.**..**.**.....*......***..**.*.*.*...**..**....*.*.*...*..***.*....* Rev 79 3.3-113 -124 (inclusive) .......*.*...*.*.*.....*..*.....**.**.. , *..*......**....*.*.*.................. Rev 3 3.3-125 .........*...*..*........*....*....*.......*....*......*.....*..**...*..*.....**..........*......*......* Rev 59 3.3-126 .*.*.........*.**..........*............ .-..*...*.*..*.......*......**.***....*....**....*.*....*......... Rev 84 3.3-127 .............*..*...*..*........*.....*....*...*.*.....***.*.**..******.**........*............*.........*. Rev 3 3.3-128 *****........*..*........*....*.......*....*.....*.....**..*..*...**..*..*.........*...*.....*.*.....*... Rev 87 3.3-129 .***...**..*........***.*.*...*.*...*.*.*..*..**.***.*...****.***...*......*..*....*...*.*.*.**..*....... 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Rev 58 3.3-161 ..*...*.*.......*..................**...*..* , .***..*...*.**.**........*.*....*.*..*.*.....*.*......*.*.*.* Rev 58 3.3-162 **.*..*.*....** .-.................................... : *..*......*.....*.*..*.**.*.* .-*..... .' *..*.........*.... Rev 3 3.3-163 *...*..*.... : .***..*...**....*..*.*.*.*.*..*.* : *.***.**.....*....*.*.**........*.**.... .*.*..*..*.*...*. Rev 45--3.3-164 ... : **...* :._ .*.***...*.*.* :.*; .....*..... :*; ** : ..*** : .... .' ..*.**.***.*. .-***..** .............................. Rev 3 3.3-165 ...** : *......*.......*.. ;: ..*.*....... .-...... , **** **.......***.*.*...................*..***... _ ........*. Rev 3 3.3-166 *......**....*....*...*.*. :., ......* : *...... ; .. :: .**. : ..**..*......*.**...*....*. .*.............*...*... Rev 87 3.3-167 *.*..**. _ ...... .-*..*..*.*..*...*...*.*......**... .-..*... ; ............................ .-....**.*...*..*..... 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• 3.3-175 ..*** :: ** : .*. ; ..*.*.. ; *... **.*...*.....***.*..******.**..*.*..***** , ..*.**.*...*..*****.*.*..*...****.*. Rev*3 3.3-176 : .*...*..*...*..*....*.**.******.*.....*.*.*.**..*...*..*..*..*...*..*. : .............. , .*.*.*.*..*.*.**.*.... Rev 3 3.3-177 ; .*.*. .-..*.*.***..** , *.*.**.*..*...*...** :.: *.**** ; .. : *.*.. ; ..*........*.......*......*.** , ....*.. : ..*.** Rev 97* 3.3*178 .: .. : .*.*..* : .*.**..*.*..*.............*.*....**.**.***..*.***..***..*.***..*.*.*.** : **..*.*.*.....**..*. Rev 87 .
• 3.3-'179 ...*. :: ****.***.***.*........* :, *..........*...***.. ,: **.**..***..*...* .-.**.*****. :, .*. ...*..*..**....*.. Rev 3 *3.3-180-**.*.****...*.**.*.*.*..* ,. ...*.*...*.****.********.*. , *.**.......*.*.*..**.***..*. .-.*......**.*.*.*..*..** Rev 3 3.3-181 *. : ** _ .***...*..**.****.****... , *.*...* -.*..*.**. .-.**.**....*..*...*...**.*..... ;* ..*. , .*.........*...*...... _. Rev'.3 3.3-182 .** ; ..*..***..*.......*..*.......... , ..*.*.....*.. ; *...* ; .*.. .' ****......*.**..*...*.....*...* : *..*.**.*.*. :. Rev. 3_ 3.3-183 ..*.... ;.: .*.. : .....*...................*.**.......... ; .......*.....*.*...*......*.............*...*...*... R*ev 3. 3.3-184 ... :.,.: ......**...... ; ..... .........*.**..... ; ............................. ; ........ :' *.....*.....*...... Rev 87 v Revision No. 137

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PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.3 INSTRUMENTATION (continued) page(s) 3.3-185 *.**......*.....*.*..*........*.*..............*.********.**.*..*...**...***......*.*...****...***.****** Rev 87 3.3-186 ...*.*.....*.*..*....*.*..........**..*..*.*.......**...*........*.......*....*........*...*........**... Rev 87 3.3-187 ..**..*.*.................*.......*......*..*....****...*................*.....*.*.........*.*......**...*. Rev 5 3.3-188 *.*****.*...*.....*..****....**....*.....**..**....**...*.**.***..*...**.**..**..*..*..*...*.*..*...*.... Rev 88 3.3-189 ..*****..............*....**...................*.*.**...*.*.*..*......**.**..*...*.*..*.*.*....*....*..*. Rev 88 3.3-190 ..**....*.*.....*........*...............*.*.....*.......................**......*.............*..*...*.. Rev 88 3.3-191 -194 (inclusive) .*...***...**.*..**.....***.........*.................*.....**.*...*...**...... 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Rev 3 3.3-200 .*.*....*.............**..*.*......*.........**.*.****.*....................**..*..*...***.*.*.**.*.*....** Rev 3 3.3-201 .***.**.*....*.*...*..*.*.***.*....*...*..*.*...*.****.*...*...*.*......*..*..*.*.......*....*.*.**...*.*.* Rev 3 3.3-202 .**..*...*.........*....*...*.....*.*...........*.***.*....**......*..*.....*.*.........*..*...******....** Rev 3 3.3-203 .**.....*......*.*.*..* , ....*.......*..*.**.......*....*.....*...*.....*...**.*.*..*......*....*.*.. ; .... Rev 67 3.3-204 ******.**...*.*.**.*..*......*......*.....*.....*******....*...*.*.**......**.*.**.*..*.*.***....*......* Rev 87 3.3-205 .***..........*....**.**.....*.*..*..........*.*..***.*.......*.*..*.*..*...*.*.*..*.*.***.......*.**...* Rev 87 B 3.4 REACTOR COOLANT SYSTEM (RCS) page(s) 3.4-1 **.*....*.*.*.*.............**....*.*.*..*....**....*.*........*.*.*... , .*..*...*.....*.*..*.....*..*.*..*. Rev 118 3.4-2 **.**.....*.*........*.*..**..........*.*..*..*..*.**.........**..*.......*.*...*..........**.*.*...*.****. Rev 11.8 3.4-3 ***...**.******.*.*....*.*.*...*............***.**..*....***.***.**..*.*.*.**.....*.....**...*.*.*.*.*..*.*. Rev 125 3.4-4 ..*.*......*...*....*.*.**...........*.*.*...*................*............*..*......**.*....*.***.*.**.*.*** Rev 51 3.4-5 *.*..*..*..*.*.*.*....*.***......**...*.....*...*.*...*..*....*..*.*........*.**........*....*.*.***..*.*** Rev 125 3.4-6 *.*..*.**.................*.......*...*.*.....*.......*..*.............*..*.*..**..........*......**..*..*... Rev 51 3.4-7 *...............*............**................*.*.....**....**...................................*........ Rev 125 3.4-8 *..*..**.*...*...* , *.....*..*.*.**.........*....* * *..*...***.....*....*......*.....*.*.**.*... ; **.*.*..* ; .*.. Rev 125 3.4-9 **.....*...*.***.*....*..**..*..***..*.....**.*****..*****..***..***..**.*.**.*...*.*.**..*....*...*.*....* Rev 125 3.4-10 ....**......* : ..........*.... ..............*.*... .**.........*.*.....*......*.....**..**.....*.*......* Rev 125 3.4-1.4 ..****.....***..*.......**.*...*.*..*.*.....*..*. * **.***..*....*.........*.*..*......**.*....*....*.**.... Rev 119 3.4-15 *..******. .-...*...*...*.....*......*.*.*...*...*** **.**....**.*.*............*.... ; ..*.*.*.*.......**.** Rev 119 3.4-16 *.*********.........*****...*.*.*.****..**...*..*...**..**.*.*.*.......*..*..*..*.*.*...........*.*.*.*.. Rev 119 3.4-17 ...***.. ; ....*...*..*.......*.*.*...*....**...**..*******............*.**.*..***..*..*.......*........**. Rev 110 3.4-18 .*.*.***.....*.*.....*..*.... .*......*.**..*.**.********..*..*..*.............*.*.*.*.........*...*....* Rev 119 3.4-23 ...*...*...*...*....**...**.*.*.....*.*....**..**....***..*.*.**....*....*.*....*.....*..........*..**.*.*. Rev 87 3.4-24 .*.*.*.*...........*.*.....*.......*.*.**..*.*.**..***.*....**...*........*..... : ...........*.......**.*... Rev 93 PBAPS UNIT 3 3.4-25 ************.*********************************************************************************************** Rev 93 3.4-26 *.*.***.***.....**.*******..*.*****....*.*..***.*.*.******.....*..*..*.**.*..*..*.*...*.*...*.*.*....**.*** Rev 93 3.4-26a ...****.......*...*..**.*.........*....*....*...*.** : ..*...*.*....*......*.*..*...*....*....*.*.*..**.*** Rev 93 3.4-27 ....****..*........**...**.....**.*.*.*..*..*.*...*****......*.**............*..*...*.*..*..*.*.*.*..**..** Rev 87 3.4-28 ..*****....***.*...*.***.*.*......*.*********.**. ; ..*****..**...*...*******..**.**.**.*.*****..**.**....*.* Rev 93 3.4-29 ....***.*..*...***.*.*...*..*...*....*......************....*..........**..*.**............*....*.*..**...* Rev 76 3.4-30 ***.***..******...*...**.*..*.*........*.....*..*.****.*....**.*.*..*............*.. *.............*..*.... 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• vi Revision No. 137 1' *:-*_ PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued) page(s) 3.4-37 ................................................................... , ...................................... Rev 128 3.4-37a ......... : ..................................................................... : ....................... Rev 129 3.4-37b ....................................................................................................... Rev 128 3.4-39 ........................................................... * .............................................. Rev 128 3.4-42 ......................................................................................................... Rev 129 3.4-42a ....................................................................................................... Rev 128 3.4-43 ...................................................... ...................... * ............................. Rev 102 3.4-44 ................................................. : ......................................................... Rev 102
• 3.4-45 ......................................................................... : ............................... Rev 102 3.4-46 ....................................................................... , .*.***.*.*** : ..................... Rev 1.02. 3.4-47 **.* ........................................... : ............................ : ........................... Rev 102 3.4-48 ................... .*..*..**.***.* ...................................................................... Rev 102* . 3.4-49 .......... : .............................................................................................. Rev 102* . 3.4-50 ..................................................................... ................................... Rev 102 3.4-51 ......................................................................................................... Rev 102
• 3.4-52 .****.** , ...................... : ..*.**.*** ; ............................................................ *** Rev 50 3.4-53 ............................................ ..... : .............. ; .... : .................... : .............. Rev 119 *
• B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE. ISOLATION COOLING. (RCIC) SYSTEM page(s). 3.5-3 ........................................................................................................... Rev 11 o. 3.5.:4 ................................................... * ........................................................ Rev 127 3.5-5 ............................................................................... ................. ; ......... Rev 128 .. 3.5-6 ......................... ......... : .................................... ; ............ : ...................... ;.Rev 112*
• 3.5-6a ........................ ; ..................... : .............. ; ...................................... * *.*. : .* Rev 96 *
• 3;5:.7 *.*..***** * ........ ; ............ * .. : **..*. : .. : .... * .......................................... : ..................... Rev *89 . 3.5-8 ................................ ;* ............................. : ....... ;." .................................... Rev 101 . 3.5 .. 9 * ............................................... ::.-............. ;: ***.*.** :.* ............ '.., ................. Rev 128 . _3.5-10 .......................... : ........ : ............ ; .............. .-.. , .. :,.: ... : ....................... *._.: .. Rev .129
• 3.5 .. 1 Oa * ................................................... ; ............ .-.......... : ............................. Rev 128 . 3.5-11 ..* :.* ... , ................ *: ..... : ................................................... ........................ R.,,v 87 . 3.5-12 .-.......................... : ................................................ ; ...... ; ........... : ......... Rev-133 3.5 .. 13 ........ ; ............................. * ............ ; .................... :: .... ; ......... *: ...................... Rev 99 .. . ...... ; ......... : ................... *;.; .... * ........... ; ....... '. .. : .... .-............ ;; .. : ... :: ...... : *** : ...... Rev 132** .* * .3.5-1*5 .. : .............................. ; .*.*.* : ........................... .-.* ........................... ;; *****. , .*.** Rev 81
• 3.5-1.6 ..... : ....... : .. -.... ............. : ....... :.;.* .. :, ... ::; .............. _ ..... ; .. ...... : ..... ... :.: ............ R,ev 87: 3.5-17 ........................ ; .... .-................... ;*.:; .. ; ..... , ....... .... ; .... ; .... ; .................... Rev 101. 3.5-18* ........................ ;: ...................... '. ......................................................... Rev."135* 3.5-.19 ................... : ....... :; .............. : ..... ; ........... : ... : ............. .-..... .-..................... Rev .96 .. . 3.5-19a ...... : ......................... * ......... :, .......... ; ........................ , ........................... Rev 95* 3.5-19b .......................................... .:., ... : ................................ , ......................... Rev 96
• 3.5-22 *******. .-................... ; ****..*..***** ; ............................................................. Rev 128 . 3.5-23 ......... : ..................... : .......... : .**. : ............................. , ..................... , *.* , *.* :Rev 58 3 .... 5-24 ........................ .......... , .......... .... : ................ ; .......... ; ......... ................... Rev 11 O . 3.5-25* .. ........... ; .. , .. ..... .-.................. ................. ; ................... : ....................... Rev_128 -'._ .* 3.5-26 ........... : ............ ; .... .-; ........ .-.... ; .. :.:; ........... , ............. , ........... : ...... ; ............ Rev_ 67.* ** * .. 3.5-27 ... : ............ ; ............... : ........ *.* : ............ : ........................... .... -.; ............... Rev 129 .. 3 *. 5-.?7a .: ......... : .. , ........... : ........... : ........ _ .... ; .. : ................................. , ... ; ............. Rev 128 ... '_ 3.5-28 _ ..................... :., ........ : ...................... * .............. _ ................. ;;: ............... , .Rev 132 '. .. . . 3.5-29_ .. .............. ........... ; .. ; .................... , ........... ;, ................ ; ....... .-............... , ** Rev 87 .. 3.5-30 ............................. ................ :.* *****.*..**.* , *.***..*.*..**. ;; ........ .-*****..*.*.*...* *.fle.v 67 PBAPS UNITS vii Revision No: 137 * ,**-... .*.

PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.6 CONTAINMENT SYSTEMS page(s) 3.6-1 ....*.*.*..*..*............*...........*...*...........*.*....**.*.*..**......*......*.***..........*........ Rev 27 PBAPS UNIT 3 3.6-2 ...*..........**......**.*..*.....*......*....*.*.*....*....*..* , ...*......*..........**............*...*.. Rev 119 3.6-3 ...*..........*..........*.**........*.*.*....*........*....*..***..*..........*....*..**.....*.*.........*.. Rev 67 3.6-4 ......*..*.*...*.*...*...*......*..*...........*.*......*....*...**..*..........*.**......*...*......*....*.. Rev 87 3.6-5 ............................*..........................**....*.****............**......**....*............. Rev 119 3.6-7 .....*.....*..****.............*........*..*****........*......****....*...*....*.****........*....**..*... Rev 119 3.6-11 .........**..*......*...*......................*..*...........**..*....*.*.*.**.**.......*..*.....*..**.*.... 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• 3.9-8 ............................................................................................................. Rev 17 3.9-9 **..**.*.......*...*....*.....*.*.**..*.*.**.*..**.***..*..*........****.....**.*.**.*..*........*.*....*...* Rev 87 3.9-10 ............................................................................................................ Rev 17 3.9-14 ........................................................................................................... Rev 17 3.9-15 ................................................................................ ; *..**..*.....*..*..*.*.*.. Rev 87 3.9-17 ........................................................................................................... Rev 76 3.9-19 ........................................................................................................... Rev 87 3.9-21 ......................................................................................................... Rev 128 3.9-23 .**...... ; ............................................................................................... Rev 128 3.9-23a .................................................................................. Rev 129 3.9-23b *..*...*..**......*.*..*.*..*...*..*........*.*..***.*..*.*...***** ......**....*....***.*..*.....*...* Rev 128 3.9-25 ..................................................................................................... ; *.. Rev 128 3.9-27 ***..* : ** : ............................................................................................... Rev 128
• 3.9-28 .......... * ......................................... ; ..................................................... Rev 129 .. . 3.9-29 ... * ... ...***.....*..****.......**..*....*.......... ***************************************************:*Rev 128 . xi Revision No. 137

.. -. ' l,' . ,,_ 'i*** B 3.10 PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING SPECIAL OPERATIONS page(s) 3.10-1 *.***.*.*.***.*.**************.*****************************.****.*************.***** ******************* Rev 131 -..***.*.*****.************************..**.*****************.****.**..*.********** : ******..*.*..**.****** Rev 131 3.10-2a .*******..*******************.*****..** .****************** * *****.**.**.*******.*.**.*****..*****.****** Rev 131 3.10-3 **.** , *****.*******.**.*.*.********.********** , ****..*.**..***************.**** , ***..**.******.*.*.*.*.*. Rev 131 3.10-4 ***** : ***********.*.**.* : *.***.*******.**.******.*..*.*.***.***..*...***..******.*******..***.*********** Rev 131 3.10-5 ***.**..****.******.*..*.*.*.*.**************.***...***.***.****.**..**.*.*.**** -*******....**.*.**.****.**. Rev 17 3._10-8 ******* ; *** .. ***************************************************** Rev 87 3.10-9 ******.*...****..**..**.*..**..***.**.***..*.***.**..**********.**.*******.*..*..***.******.******...*.**** Rev 87 3.10-13 **************.**...*.**.*.******.*.*...******..**** **.****..**.******..*****.***.*****..*.*.****.** : *** Rev 87 3.10-18 .*******.*****.***.*..******.****.*.**.*******.**************.**.****.****.** ; ****.**.***** ; * .-.***.**** 87 3.10-22 *.***.*.***********************.*******.*.***.***********************...*.*..**.. ***...*.*..*...***.*** Rev 81 3.10-26 *.*****.**.*..***.*..****.*.*.*..*.*.***..*...*..***.*****.****.**.***.**.****.....*.**..*.*.*...*.*****. Rev 87 3.10-30 ......................................................................................................... Rev 73 3.10-31 *******..**.*.*******.*.**..**.**.******.*.*.*.***.****.**.***********.*.*.**.***..*..******.*..******.** Rev 17 3.10-32 ******.*******.***.***.*.*.*.**.**.*******.*...**..**.*******.**.***..*..*.**..******..**.******..*..**** Rev 30 3.10-33 .............................. ................................................................ : .*.* .-**. Rev 64 . 3.10-35 *.* ; ............................................. *.*..*..****** ; ****.*.*.*..***..*****...*.*.*..*.****** Rev 87 --3.10-36_ .** :. *.*.***.***.*.*.***.*. .................................. .**..**.* ; ................................ Rev 81 All remaining pages are Rev O dated -* xii Revision No. 137 TABLE OF CONTENTS B 2.0 SAFETY LIMITS (SLs) . . . . . . . . . . . B 2.1.1 B 2.1.2 Reactor Core SLs . . . . . . . . . Reactor Coolant System (RCS) Pressure SL B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY SURVEILLANCE REQUIREMENT (SR) APPLICABILITY B 3.1 B 3.1.1 B 3.1.2 B 3.1.3 B 3.1.4 B 3.1.5 B 3.1.6 B 3.1.7 B 3 .1.8 B 3.2 B 3.2.1 B 3.2.2 B 3.2.3 B 3.3 B 3.3.1.1 B 3.3.1.2 B 3.3.2.1 B 3 .3 .2. 2 B 3.3.3.1 B 3.3.3.2 B 3.3.4.1

• B 3 . .3.4.2 B 3.3.5.l B 3.3.5.2 B 3.3.6.l B 3.3.6.2 B 3.3.7.1 B 3.3.8.1 B 3.3.8.2 REACTIVITY CONTROL SYSTEMS . SHUTDOWN MARGIN (SDM) Reactivity Anomalies .. Control Rod OPERABILITY Control Rod Scram Times .. Control Rod Scram Accumulators Rod Pattern Control . Standby Liquid Control (SLC) System . . . Scram Discharge Volume (SDV) Vent and Drain Valves POWER DISTRIBUTION LIMITS . . . . . . . . . . AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) . . . . . . . . . . . . MINIMUM CRITICAL POWER RATIO (MCPR) LINEAR HEAT GENERATION RATE (LHGR) INSTRUMENTATION . . . . . . . . . . . Reactor Protection System (RPS) Instrumentation Wide Range Neutron Monitor (WRNM) Instrumentation Control Rod Block Instrumentation ...... . Feedwater and Main Turbine High Water Level Trip
• Instrumentation ............... . Post Accident Monitoring (PAM) Instrumentation .. Remote Shutdown System . . . . . . . . . . . . . . Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation ..... End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation . . . B 3.3-92a thru Emergency Core Cooling System (ECCS) Instrumentation ...... , ...... . Reactor Core Isolation Cooling (RCIC) System Instrumentation ............. . Primary Containment Isolation Instrumentation Secondary Containment Isolation Instrumentation Main Control Room Emergency Ventilation (MCREV) System Instrumentation . . . . . .. Loss bf Power (LOP) Instrumentation Reactor Protection System (RPS) Electric Power Monitoring ............ . B 2.0-1 B 2.0-1 B 2.0-7 B 3.0-1 B 3.0-10 B 3.1-1 B 3.r-1 B 3. l-8 B 3.1-13 B 3.1-22 B 3.1-29 B 3.1-34 B 3.1-39 B 3.1-48 B 3.2-1 B 3.2-1 B 3.2-6 B 3.2-11 B 3.3-1 B 3.3-1 B 3.3-37 B 3.3-46 B 3.3-59 B 3.3-66 B 3.3-77 B 3.3-84 B 3.3-92j B 3.3-93 B 3.3-131 B 3.3-142 B 3.3-169 B 3.3-180 B 3.3-187 B 3.3-199 (continued) PBAPS UNI.T 3 Revision No. 28 TABLE OF CONTENTS (continued) B 3.4 B 3.4.1 B 3.4.2 B 3.4.3 B 3.4.4 B 3.4.5 B 3.4.6 B 3.4.7 B 3.4.8 B 3.4.9 B 3.4.10 B 3.5 B 3.5.l B 3.5.2 B 3.5.3 B 3.6 B .. 1.l B 3.6.1.2 B 3.6.1.3 B 3. 6 .1. 4. B 3.6.1.5 B 3.6.1.6 B;3.6.2.l B 3.6.2.2 B 3.6.2.3 *B 3.6.2.4 B 3.6.?.5. B 3;6.3.l B 3. 6. 3. 2. B *3.6.4.l'. B 3. 6. 4 .. 2 B .3. 6. 4. 3 ' ' ' B 3. 7
• B .3. 7 .1 B 3.7.2 B 3.7.3 B 3.7.4 B 3.7:5* PBAPS UN IT 3 REACTOR COOLANT SYSTEM (RCS) ............................ B 3.4-1 Reci rcul at ion Loops Operating ....................... B 3. 4-1 Jet Pumps ........................................... B 3.4-lf Safety Relief Valves (SRVs) and Safety Valves (SVs). B 3.4-15 RCS Operational LEAKAGE ............................. B 3.4-19 RCS Leakage Detection Instrumentation ............... B 3.4-24 RCS Specific Activity ............................... B 3.4-29 Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown ............................. B 3.4-33 Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown ............................ B 3. 4-38 RCS Pressure and Temperature (P/T) Limits ........... B 3.4-43 Reactor Steam Dome Pressure ......................... B 3.4-52 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING CRCIC) SYSTEM ......................... B 3.5-1 ECCS-Operating ..................................... B 3.5-1 ECCS-Shutdown ...................................... B 3.5-18 RCIC System ............................ ............ B 3.5-24 CONTAINMENT SY.STEMS ..................................... B 3.6-1 Primary Containment ..................................... B 3.6-1 Primary Containment Air Lock ............................ B 3.6-6 P r i ma ry Cont a i nm en t I s o 1 at i *on V a 1 v e s ( PC I V s ) . .. .. .. .. .. . B 3 . 6 -14 Drywell Air Temperature ................................. B 3.6-31 Reactor Chamber Vacuum Breakers ........... , ............................. B 3.6-34 Suppression Chamber-to-Drywell Vacuum .Breakers .......... B 3.6-42 Suppression Pool Aye rage Temperature .................... B 3. 6-48 S up p res s i on P.o o 1 W a t e r Lev e 1 . . . . . . . . . . . . . . . . . . . . . . . * . . . ; B 3 . 6 -5 3 Residual Heat.Removal (RHR) Suppression Pool
• Cool1ng*.: ... : ................... : ................ B 3.6-56 Residual. Heat (RHR) *suppression Pool Spray ...... B 3.6-60 Res.idual Heat Removal .rnHR) Drywell Spray ............... B 3.6-63a Deleted.: ................. *.: ....... .' ..... :.* ....... * .......... B 3.6-64 Primary' Containment* Oxygen Concentration ..... , ........... B 3.6-70 Secondary Containment ... : ............. : ................. B 3.6-73 Secondary Containment Isolation* Valves (SClVs) .......... B 3.6-78. Standby Treatment (SGT) System ......... ....... :, ... B 3.6-85
• PLANT SYSTEMS ................................. ; ... : ..... B 3.'l-1 . High Pressure Service 'water _( HPSW) System .. ...... B 3. 7-1 Emergency CESW) System and Heat Sink .. :: .................................... B 3.7-6 Emergency Heat Sink ..... : ............. : ............. B 3. 7-11 Main Contra] Room Ventilation (MCREV) : System*.: ......... .... :.* ... *, ..*.............. * ... B 3.7-15 Main Condenser *offgas ....... : ... : ................... B 3. 7-22 -' --. . (continued). i i Revisinn No. 106 TABLE OF CONTENTS (continued) B 3.7 B 3.7.6 B 3.7.7 B 3.8 B 3 .8 .1 B 3.8.2 B 3.8.3 B 3.8.4 B 3.8.5 B 3.8.6 B 3.8.7 B 3.8.8 B 3.9 B 3. 9.1 B 3.9.2 B 3.9.3 B 3.9.4 B 3.9.5 B 3.9.6 B 3.9.7 B 3.9.8 . B 3.10 B 3.10.1 B 3.10.2 B 3.10.3 B 3.10.4 B 3.10.5 B 3.10.6 B 3.10.7 B 3.10.8 PBAPS UNIT 3 . PLANT SYSTEMS (continued) Main Turbine Bypass System .......................... B 3.7-25 Spent Fuel Storage Pool Water Level ................. B 3.7-29 ELECTRICAL POWER SYSTEMS ................................ B 3.8-1 AC Sources-Operating ............................... B 3.8-1 AC Sources-Shutdown ................................ B 3.8-40 Diesel Fuel Oil, Lube Oil, and Starting Air ......... B 3.8-48 DC Sources-Operating ............................... B 3.8-58 DC Sources-Shutdown ................................ B 3.8-72 Battery Cell Parameters ............................. B 3.8-77 Distr1bution Systems-Operating ..................... B 3.8-83 Distribution Systems-Shutdown ...................... B REFUELING OPERATIONS .................................... B 3.9-1 Refueling Equipment Interlocks ...................... B 3.9-1 Refuel Position One-Rod-Out Interlock ............... B 3.9-5 Control Rod Position ................................ B 3.9-8 Control Rod Position Indication ..................... B 3.9-10 Control Rod OPERABILITY-Refueling .................. B 3.9-14 Reactor Pressure Vessel (RPV) Water Level ........... B 3.9-17 Residual Heat Removal (RHR)-High Water Level ....... B 3.9-20 Residual Heat Removal (RHR) -Low Water Level ........ B 3. 9-24 SPECIAL OPERATIONS ...................................... B 3 .10-1 Inservice Leak and Hydrostatic Testing Operation .... B 3.10-1 Reactor Mode Switch Interlock Testing ........ ...... B 3.10-5 Single Control Rod Withdrawal-Hot Shutdown ......... B 3.10-10 Single Control Rod Withdrawal-Cold Shutdown ........ B 3.10-14 Single Control Rod Drive (CRD) Removal-Refueling ................................ B 3.10-19 Multiple Control Rod Withdrawal-Refueling ..... : ..... B 3.10-24 Control Rod Testing-Operating ...................... B 3.10-27 SHUTDOWN MARGIN (SDM) Test-Refueling ............... B 3.10-31 *Revision No. 3 iii

': .. Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS CSLs) B 2.1.1 Reactor Core SLs BASES BACKGROUND PBAPS UNIT 3 SLs ensure that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and abnormal operational transients. The fuel cladding integrity SL is set such that no fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback apgroach is used to establish an SL, such that 99.9% of the fuel rods avoid transition boiling. Meeting the SL can be demonstrated by analysis that confirms no more than 0.1% of rods in the core are susceptible to transition boiling or by demonstrating that the MCPR not less than the limit specified in Specification 2.1.1.2 for General Electric (GE) Company fuel. MCPR greater than the specified limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity. The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The. integrity of this cladding barrier is related to its relative freedom from perforations or cracking. Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, how.ever, can result from thermal stresses, which occur from reactor operation significantly above design conditions. fission product migration from claddifig perforation is just measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross, rather than cladding deterioration. Therefore, the fuel cladding SL is defined with a margin to the conditiDns that would produce onset of transition boiling Ci .e., MCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. The MCPR fuel cladding integrity SL ensures that during normal operation and during abnormal operational transients, at least 99.9% of the fuel rods in the core do not experience transition boiling.

• continued B 2.0-1 Revision No. 96 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 Reactor Core SLs B 2.1.1 Operation above the boundary of the nucleate boiling regime could result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding water (zirconium water) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant. The reactor vessel water level SL ensures that adequate core cooling capability is maintained during all MODES of reactor operation. Establishment of Emergency Core Cooling System initiation setpoints higher than this safety limit provides margin such that the safety limit will not be reached or exceeded. The fuel cladding must not sustain damage as a result of normal operation and abnormal operational transients. The reactor core SLs are established to preclude violation 6f the fuel design criterion that a MCPR limit is to be established, such that at least 99.9% of the fuel rods in the core would not be expected to experience the onset of transition boiling. The Reactor Protection System setpoints (LCD 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), in combination with other LCOs; are designed to prevent any anticipated combination of transient conditions for Reactor Cool ant System water level, pressure, and THERMAL POWER level that would result in* reaching MCPR limit. 2.1.l.1 Fuel Cl adding Integrity GE critical power correlations are applicable for all critical power calculations at 700 psia and core flows 10% of rated flow, For operation at low pressures or low flows, another basis is used, follows: The pressure drop in the bypass region is essentially all elevation head with a value> 4.5 psi; therefore, the core drop at low power and flows will always be> 4.5 psi. At power, the static head inside continued B 2.0-2 *Revision No. 130 BASES APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 Reactor Core SLs B 2.1.1 2.1.1.1 Fuel Cladding Integrity (continued) the bundle is less than the static head in the bypass region because the addition of heat reduces the density of the water. At the same time, dynamic head loss in the bundle will be greater than in the bypass region because of two phase flow effects. Analyses show that this combination of effects causes bundle pressure to be nearly independent of bundle power when bundle flow is 28 X 103 lb/hr and bundle pressure drop is 3.5 psi. Because core pressure drop at low power and flows will always be> 4.5 psi, the bundle flow will be> 28 X 10 3 lb/hr. Full scale ATLAS test data taken at pressures from 14.7 psia (0 psig) to 800 psia (785 psig) indicate that the fuel assembly critical power with bundle fl ow at 28 X 103 lb/hr is approximately 3.35 MWt. This is equivalent to a THERMAL. POWER> 50% RTP even when design peaking factors are considered. Therefore, a THERMAL POWER limit of 23% RTP for reactor pressure < 700 psia is conservative. Additional information on low flow conditions is available in Reference 5. 2.1.1.2 MCPR The fuel cladding integrity SL is set such that no fuel damage is calculated to occur if the limit is not violated. Since the parameters that result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur. Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power. Therefore, continued B 2.0-3 Revision No. 130 BASES APP LI CAB LE SAFETY ANALYSES PBAPS UNIT 3 2.1.1.2 MCPR (continued) Reactor Core SLs B 2.1.1 the fuel cladding integrity SL is defined as the critical power ratio in the limiting fuel assembly for which more thari 99.9% of the fuel rods in the core are expected to avoid boiling *transition, considering the power distribution within the core and all uncertainties. The MCPR SL is determined using a statistical model that combines all the uncertainties in and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the approved General Electric Critical Power correlations. Details of the fuel cladding integrity SL calculation are given in Reference 2. Reference 2 also includes a tabulation of the uncertainties used in the determination of the MCPR SL and of the nominal values of the parameters used in the MCPR SL statistical analysis. 2 .1..1. 3 Reactor Vessel Water Level During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active fuel to provide core cooling capability. With fuel in the reactor vessel during when {he reactor is shut down, must be water level requirements due to the effect of decay_ heat. If the water level should drop below the top of the irradiated fuel during this period, the ability to remove* decay heat is reduced. This reduction in cooling coul*d lead to elevated cladding temperatures and clad perforation. The core can be adequately cabled as long as level above 2/3 of the core hei.ght. The reactor vessel .water level SL has been at the top of the active fuel tb a that be m6nitored and to also provide margin for action. (continued) B 2.0-4. Re v i s i on . N o . 4 8 .

Reactor Core SLs B 2.1.1 BASES (cont i n.ued) SAFETY.LIMITS APPLICABILITY SAFETY LIMIT . * . VIOLATIONS *:* .. *:.-. *psAPS *uNrr'* 3 The reactor core SLs are established to protect the integrity of the fuel clad barrier to the release of radioactive to the environs. SL 2.1 .1.1 and SL 2.1.1.2 the core operates within the fuel . design SL 2.1.1 .3 ensures that the reactor vessel water level is greater than. the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations. SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES. Exceeding an SL may cause fuel damage and create a potential for radioactive in excess of 10. CFR 100, "Reactor Site Criteria, " limits (Ref. 3) and 10 CFR 50. 67, "Accident Source Term," for accidents analyzed using AST (Ref 4). Therefore, it is required to insert all insertable control rods and restore cdmpliance with the SLs within 2 The .2 hour.. Completion _Time ensures that the operators take prompt remedial aeti on *and al so ensures that the probability of an ac.ci dent occurri*ng during this period is minimal . '**. 7*' ,* '.-.--. . * ... -. .. ,, __ '.:'* .. * .. ,* ,,"* *-(continued) *. ,* Revis'(on. No. 76 BASES REFERENCES PBAPS UN IT 3 1. DELETED Reactor Core SLs B 2.1.1 2. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," la test approved revision. 3. 10 CFR 100. 4. 10 CFR 50.67. 5. SIL No. 516 Supplement 2, January 19, 1996. B 2:0-6 Revision No. 130 j "* ,1, .. I. I . *.:.* RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs) B 2.1.2 Reactor Coolant System (RCS) Pressure SL BASES BACKGROUND The SL on reactor steam dome pressure protects the RCS against overpressurization. In the event of fuel cladding failure, fission products are released into the reactor coolant. The RCS then serves as the primary barrier in preventing the release of fission products into the Establishing an upper limit on reactor dome pressure ensures continued RCS integrity with regard to pressure excursions. Per the UFSAR (Ref. 1) , the reactor

• cool ant pressure boundary (RCPB) shal 1 be designed with. sufficient margin to ensure that the design are not during normal operation and
• operational transients. During.normal operation and abnormal operational transients; RCS *pressure is limited from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code (Ref. 2). To ensure system integrity, all RCS components are hydrostatically tested at 125% of design pressure, in accordance with ASME Code requirements, prior. to initial operation when there is no.fuel in the core. *Any further hydrostatic' testing with fuel in the core may be done under LCO 3.10.1, ".Inservice Leak and Hydrostatic. Testing Operation." Following inception.of unit operation, *RCS components -shall be pressure in accordance with the requirements of ASME C6de, Section XI (Ref. 3}. -.. . . . the RCS could result in a breach of * ** . the RCPB redi.Jci ng the nuniber of protective barriers designed APPLICABLE ... SAFETY ANALYSES PB.('.PS UNIT*3
• to prevent radioactive eases froni. exceeding the 1 i mi ts. specified iti 10 CFR 50.67 "Accident Source Term" (Ref. 4) .. If this 6ccurred in cladding fai 1 ure, f i ssi On products could_ enter the' ccmtainment atmosphere. The.RCS safety/relief valves and the Reactor Protection System Reactor Pressure---High. Function have settings* established to. ensure that the RCS pressure SL will not be exceeded .. . .(continued j. ..'-. B 2.0-7 .:

BASES APPLICABLE SAFETY ANALYSES (continued) SAFETY LIMITS APPLICABILITY SAFETY LIMIT VIOLATIONS PBAPS UNIT 3 RCS Pressure SL B 2.1.2 The RCS pressure SL has been selected such that it is at a pressure below which it can be. shown that the integrity of the system is not endangered. The reactor pressure vessel is designated to Section III, 1965 Edition of the ASME, Boiler and Pressure Vessel Code, including Addenda through the summer of 1966 (Ref. 5), which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig. The SL of 1325 psig, as measured in the reactor steam dome, is equivalent to 1375 psig at the lowest elevation of the RCS. The RCS is designed to ASME Section III, including Addenda through the winter of 1981 (Ref. 6), for the reactor recirculation piping, which permits a maximum pressure transient of 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes. The maximum transient pressure allowable in the RCS pressure vessel under the ASME Code, Section III, is 110% of design pressure. The maximum transient pressure allowable in the RCS piping, valves, and is 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The most limiting of these allowances is the 110% of design pressures of 1250 psig; therefore, the SL on maximum allowable RCS pressure is established at 1325 psig as measured at the reactor steam dome. SL 2.1.2 applies in all MODES. continued B 2.0-8 Revision No. 58 BASES SAFETY LIMIT VIOLATIONS (continued) REFERENCES PBAPS UNIT 3 RCS Pressure SL B 2.1.2 Exceeding the RCS pressure SL may cause immediate RCS failure and create a potential for radioactive releases in excess of 10 CFR 50.67, "Accident Source Term," limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours. The 2 hour Completion Time ensures that the operators take prompt remedial action and also assures that the probability of an accident occurring during the period is minimal. 1 . UFSAR, Section 1.5.2.2. 2. ASME, Boiler and Pressure Vessel Code, Section III, Article NB-7000. (continued) *-J --B 2.0-9 Revision No. 76 BASES REFERENCES (continued) PBAPS UNIT 3 3. RCS Pressure SL B 2.1.2 ASME, Boiler and Pressure Vessel Code, Section XI, Article IW-5000. 4. 10 CFR 50.67. 5. ASME, Boiler and Pressure Vessel Code, Section III, 1965 Edition, including Addenda to summer of 1966. 6. ASME, Boiler and Pressure Vessel Code, Section III, 1980 Edition, Addenda to winter of 1981. B 2.0-1.0 *** Revision No. 76 LCO Applicability B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY BASES LC Os LCO 3.0.1 LCO 3.0.2 PBAPS UN IT 3 LCO 3.0.1 through LCO 3.0.8 establish the general requirements applicable to all Specifications in Sections 3.1 through 3.10 and apply at all times, unless otherwise stated. LCO 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when the LCO is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of each Specification). LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered. The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCO are not met. This Specification establishes that: a. Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and b. Completion of the Required Actions is nqt required when an LCO is met within the specified Completion Time, unless oiherwise specified. There are two basic types of Required Actions. The first type. of Required Action specifies a time limit in which the LCO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the *specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon ACTIONS.) The second type of Required Action specifies the continued B 3:0-1 Revision No.* ioo. BASES LCO 3.0.2 (continued) PBAPS UNIT 3 LCO Applicability B 3.0 remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable le¥el of safety for continued operation. Completing the Required Actions is not required when an LCO is met or is no longer applicable, unless otherwise stated in the individual The nature of some Required Actions of some Conditinns necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Condition no longer exists .. The individual LCO's ACTIONS specify the Required Actions where this is the case. An example of this is in LCO "RCS Pressure and Temperature Limits." The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The reasons for intentionally. relying on the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, or investigation of operational problems. Entering ACTIONS for these reasons must be done in a manner that does not compromise safety. Intentional entry into ACTIONS should not be made for operational convenience .. Alternatives that would not result in redundant equipment being inoperable should be used instead . . Doing so limits the time both subsystems/divisions of a safety function are inoperable and limits the time other conditions exist which result in LCO 3.0.3 being entered. Individual Specifications may specify a time limit for performing an SR when equipment is removed from service.or bypassed for testing. In.this case, the Completion Times of the Required Actions are when this time limit . expires, if the equipment remains removed from service or bypassed. When a change in MODE or other specified condition is

• required to comply with Required the unit may-enter a MODE or other specified in which another Specification becomes applicable. In.this case, the Completion limes of the associated Actions would. apply from the po1nt in time that the new Specification becomes applicable and the ACTIONS Condition(s) are ent_ered. (continued} B 3.0-2* Rev i s i c:in No . O . I I BASES (continued) LCO 3.0.3 PBAPS UNIT 3 LCO Applicability B 3.0 LCO 3.0.3 the actions that must be implemented when an LCO is not met and: a. An associated Required Action and Completion Time is not met and no other Condition applies; or b. The condition of the unit is not specifically addressed bythe associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS . specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.
• This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation tannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. It is not intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being fnoperab le. Upon entering LCO 3.0.3, 1 hour is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with. the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to reach lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times. (continued) B 3.0-3 Revision No. 0 BASES LCO 3.0.3 (continued) PBAPS UNIT 3 LCO Applicability B 3.0 A unit shutdown required in accordance with LCO 3.0.3 may be terminated and LCD 3.0.3 exited if any of the following occurs: a. The LCO is now met. b. A Condition exists for which the Required Actions have now been performed. c. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited. The limits of Specification 3.0.3 allow 37 hours for
• the unit to be in MODE 4 when a shutdown is required during MODE I operation .. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for reaching the next lower MODE applies. If a lower MODE is reached in less time than allowed, however, the total allowable time to reach MODE 4, or other applicable MODE, is not reduced. For example, if MODE 2 is reached in 2 hours, then the time allowed for reaching MODE 3 is the next 11 hours, because the total 'time for reaching MODE 3 is not from the allowable limit of 13 hours. Therefore, if remedial measures are completed that would permit a return to MODE 1; a penalty 'is not incurred by having to reach a lower MOOE of operation in less than the total time allowed. In MODES I, 2, and 3, LCO provides actions for Conditions'not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 4 and 5 because the unit is already in the. mo.st restrictive Condition required by *Leo 3.0.3. *.The requirements of LC0*3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE or 3) because the ACTIONS of individual define the remedialmeasure,s to be taken. ' ' Exceptit>ns to LCO 3.0.3 are *provided in instances where requiring a unit shutdown, in with LCO 3.0.3, appropriate measures for the
• associated condition* of the unit. *An example .of this is in LCO 3 7 7 ,, "Spent Fuel Ston1ge Pao 1 Water Leve 1 . " LCO 3. 7. 7 .. has an Applicability .of "During.movement of fuel assemblies (contfoued) B 3.0-4 Revision No. ()

BASES LCO 3.0.3 (continued) LCO 3.0.4 ** PBAPS UN IT 3 LCO Applicability B 3.0 in the spent fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.7 are not met while in MODE 1, 2, or 3, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCO 3.7.7 of movement of fuel assemblies in the spent fuel storage pool" is the appropriate Required Action to complete in lieu of actions of LCO 3.0.3. These exceptions are addfessed in the individual Specifications. LCO 3.0.4 establishes limitations on changes ih MODES or other specified conditions in the Applicability when an LCD is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the desired to be entered) when unit conditions are such that the requirements of the LCD would not be met, in accordance with LCO 3.0.4.a, LCO 3.0.4.b, or LCO 3.0.4.c. LCO 3.0.4.a allows.entry into a MODE or other condition in the Applicability with the LCO not met when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Compliance with Required Actions that permit continued operation of the unit for an unlimited period of time or other specified condition provides an acceptable level of safety for

• continued operation. This is without regard to the of the unit before or after.the MODE change. Therefore, in such cases, entry into a MODE or other specified. condition in the Applicability may be made in with the provisions of the Required LCO 3.0.4.b allows entry into a MODt or other specified condition in the Applicability with the LCO not met after of a risk assessment addressing inoperable* systems a*nd compo.nents-, consideration of the results, determination of the_acteptability of entering the MODE or other specified condition in the Applicability, and establishment of risk *actions, if Th-e ri use quantitative,. qualitative, or bl end.ed approaches, and the risk assessment wi 11. be conducted using* th.e pl ant program, procedures,* and criteria in pl ace to implement* lo CFR -50.65(a)(4), which requires that.risk of maintenance activities be assessed and managed. The risk assessment, for the of LCO 3.0.4.b, must take j nto account* all inoperable-Technical Speci fi cat i ori. . equipment whether the is included in the normal 10 CFR 50;65(a)(4)* risk assessment scope. The 0ill be using the and guidance,endorsed by Regulatory 1.182, and Managing Risk Before Maintenance Activities at Nuclear Power P l a n t s . " . Re g u l a to r y Gu i d e 1 . 182 e n d o r s e s . th e g u i d a n c e * (continued) B 3.0-5 Revision NO. 53_ -

BASES LCD 3.0.4 (continued)

• PBAPS UN IT 3 LCD Applicability B 3.0 in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness *of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk quantitative and qualitative guidelines for establishing risk management actions, and example risk management acti.ons. These include actions to plan and conduct other activities in a manner that controls o v e r a l l r i s k , i n c re a s e d r i s k aw a r e n e s s by s h i ft a n d management ,personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures)., and determination that the proposed MODE change is Consideration should also be given to the probability of completing restoration such that the requirements of the LCD would met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.
• LCD 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-0l provides guidance relative to consideration of simultaneous unavailability of multiple systems and component?. The results of the risk assessment shall be considered in determining the of entering the MODE or other condition in the Applicability, and any corresponding risk management actions. The LCD 3.0.4.b risk* assessments do not have to be documented. The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCD, the use of the LCD 3.0L4.b allowance should be generally acceptable, as long as the risk is managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the LCD 3.0.4.b allowance is prohibited .. The LCOs governing these system and components contain Notes prohibiting the use of LCD 3.0.4.b by stating that LCD 3,0.4.b is not applicable. LCD 3.0.4:c allows entry into a MODE or other specified condition in the Applicability with the LCD met based on a Note in the Specification which states LCD 3.0.4.c is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk ass.essment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Speci.fication. The risk assessments performed to justify the use of LCD 3.0.4.b usually only consider systems and components. For this reason, LCD 3.0.4.c is typically continued B 3 .0-'Sa Re.vision No. 53

. i BASES LCD 3.0.4 (continued) LCD 3.0.5 PBAPS UN IT 3 LCD Applicability B 3.D applied to Specifications which describe values and parameters (e.g., Reactor Coolant System specific activity), and may be applied to other Specifications based on NRC plant-specific approval. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an MOOE or other specified condition in the Applicability. The provisions of LCD 3.0.4 shall not prevent changes in MODES or other specified conditions in the Appljcability that are required to comply with ACTIONS. In addition, the provisions of LCD 3.0.4 shall not prevent changes in MODES or other specified conditions in. the Applicability that result from any unit shutdown. In this context, a unit shutdown is defi*ned as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4 . . Upon entry into a MODE or other specified condition in the Applicability wtth the LCD not met, LCD 3.0.1 LCD require entry into the applicable Conditions and Required Actions until the Condition is resolved, until the LCD is met, or until the unit is not within the Applicability of the Technical Surveillances do not have to be performed on the associated inoperable equipmerit (or on variables outside the specified limits), as permitted by SR 3.0.1. Therefore, utilizirig LCD 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for any Surveillances that have not been on inoperable .. equipment. However, SRs must be met to ensure OPERABILITY* prior to declaring the associated equipment OPERABLE (or within limits) and restoring compliance with affected LCD. *

• LCD 3.0.5 establishes the allowance for equipment to service under when it has from or declared to comply with ACTIONS. The sole purpose of this is to provide an exception to LCD 3.D.2 to not comply with the applicable Required Action(s)) to allow the performance of SRs to demonstrate:
• a. The OPERABILITY of the equipment being returned to . . service; or b .. The OPERABILITY of continued) .. B 3.0-6 . Revision No.*53 BASES LCO 3.0.5 (continued) LCO 3.0.6 PBAPS UNIT 3 LCO Applicability B 3.0 The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the allowed SRs .. This Specification does not provide time to perform any other preventive or corrective maintenance. *An example of demonstrating the OPERABILITY of the equipment
• being returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the SRs. An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system obt of tripped condition to prevent the trip function from occurring during the performance of an SR on another channel in the other trip system. A similar example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to.permit the logic to function and indicate the appropriate response during the performance of an SR on another channel in the same trip system. LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that have an LCO specified in the Technical Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant *is maintained in a safe tondition are specified in the support systems' LCO's Required Actions. These Required Actions may include entering supported system's Conditions and Required or may specify other Required Actions. When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported (continued) B Revision No. 0 BASES LCO 3.0.6 (continued) LCO 3.0.7:* PBAPS UNIT 3 LCO Applicability B 3.0 systems' LCOs' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the support system's Required Actions. However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actionsfor the supported system. This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is
• immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions. and Actions shall be entered in accordance with LCO 3.0.2. Specificatfon 5.5.ll, "Safety Function Determination Program (SFDP);" ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6, . an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result _of the support system inoperability and corresponding exception .to entering supported system Conditi-0ns and Required Actions. The SFDP implements the requirements of LCO 3.0.6. . Cross division checks to identify a loss of safety function for those support .systems that support safety systems are required.-* The cross division verifies that the supported systems of the redundant_ OPERABLE. support system are OPERABLE, the-reby ensuring safety function is retained. If this evaluation determines that a loss of safety function exists, the appropriate CondiJions and Required Actions of the LCO in which.the loss of safety function.exists are to be entered.-* . There are certairi tests and operations required to be performed at. various times over the life _of the unit.* These special tests and operations are necessary.to demonstrate select urri 1: performance .characteristics, to perform special maintenance and to perform_ (continued) B 3.0-8 Revision No. O . I

!* BASES LCO 3.0.7 (continued) LCO 3,0.8 PBAPS -UN IT 3 LCO Applicability B 3.0 special evolutions. Special Operations LCOs in Section 3.10 allow specified TS requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect. The Applicability of a Special Operations LCO represents a condition not necessarily in compliance with the normal requirements of the TS. Compliance with Special Operations LCOs is optional. A special operation may be performed under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. If it is desired to perform the special operation Qnder the provisions of the Special Operatioris LCO, the requirements of the Special Operations LCO shall be followed. When a Special Operations LCG requires another to be met, only the requirements of the LCO statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other LCO not be met, the ACTIONS of the Special Operations LCO apply, not the ACTIONS of the other However, there are "instances where the Special Operations LCO Is ACTIONS may dirett the other LCO's ACTIONS be met. The Surveillances of the _other LCO are not required to be met, unless _specified in the Special Operations LCO. If conditions exist such that the Applicability of any other LCO is met, all the other LCO's requirements (ACTIONS and SRs} are required to be met concurrent with the requirements of the Special Operations.LCD. --conditions under which systems are considered to remain capable of performing their intended -safety function when associated snubbers are not capable of .providing.their associated support function(s). This LCO states that the supported system is not considered to be solely due to one Dr more snubbers not capable of -performin9 their assotiated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing; or repair of one oi:-more snubbers not : _ capabl_e _of performing their associated support functi on(s) -and appropriate cornpensator}':measures are specified in the continued -B 3.0-9 -Revision -No._ 100 BASES LCO 3.0.8 (continued) PBAPS UN IT 3 LCO Applicability B 3.0 snubber requirements, which are located outside of the Technical Specifications CTS) under licensee control. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control by the licensee. If the allowed time expires and the snubber(s) are unable to perform associated support function(s), the affected supported sYstem's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2. LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supporterj system. LCO 3.0.8.a allows 72 hours to restore the snubber(s) before declaring the supported system inoperable. The 72 hour Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system. LCO 3.0.8.b applies when one or more snubbers are not capable of providing their associated support function(s) to more . than one train or subsyste*m of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 hours tp restore the snubber(s) before declaring the system inoperable. The 12 hour Completion Time is reasonable based on the low probability of a seismic concurrent with an event that wou1d require operation bf the supported system occurring while the snubber(s) is Care) not of performing their associated support function(s). When applying LCO 3.0.8.a or LCO 3.0.8.b one of the following two means of heat removal must be available 1) at least one high pressure makeup path (i.e., using high pressure coolant injection CHPCI) or reactor core isolation cooling CRCIC)) and heat removal capability (i.e., suppression pool cooling), including a minimum set of supporting equipment required for success, not .associated with the inoperable snubber(s), or 2) at least one low pressure makeup path Ci .e., low pressure coolant injection (LPCI) or core spray (CS)) and heat removal capability (i.e., suppression pool cooling or shutdown cooling), a*minimum set of supporting equipment, not associated with the inoperable snubber(s). continued B 3.0-9a Revision No. 100

• i* BASES LCO 3.0.8 (continued) PBAPS UN IT 3 LCO Applicability B 3.0 LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, -use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more snubbers are not able to perform their associated support function. LCO 3.0.8 does not apply to non-seismic functions of snubbers. Prior to using LCO 3.0.8.a for seismic snubbers that may also have non-seismic functions, it must be confirmed that at least one train of each system that is by the inoperable snubber(s) would remain capable of performing the system's required safety or support functions for postulated design loads other than seismic loads. LCO 3.0.8.b is not to be applied to seismic snubbers that also have non-seismic functions. B 3.0-9b Revision No: 107 SR App 1 i cabi 1 ity B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 PBAPS UNIT 3 SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications in Sections 3.1 through 3.10 and apply at all times, unless otherwise stated. SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCD apply, unless otherwise specified in the individual SRs .. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO. Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when: a. The systems or components are known to be inoperable, although still meeting the SRs; or b.. The requirements of the*surveillance(s) are known to be not met between required Surveillance performances. Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a Special Operations LCO are only applicable when the Special Operations LCO is used as an allowable exception to the requirements of a Specification. Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status. {continued) B 3.0-10 Revision No. O BASES SR 3.0.1 (continued) . ..: SR 3.0.2-* PBAPS UNIT 3 SR Applicability B 3.0 Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition-where other necessary post maintenance tests can be completed. Some examples of this process are: a. Control Rod Drive maintenance during refueling that requires scram testing at> 800 psi. However, if other appropriate testing is satisfactorily completed and the scram time testing of SR 3.1.4.3 is satisfied, the control rod can be considered OPERABLE. This allows startup* to proceed to reach 800 psi to perform other necessary testing. ' . High pressure coolant injection (HPCI) maintenance during shutdown that system functional tests at a_ specified pressure. Provided other appropriate testing is satisfactorili completed, startup can
• proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post
• SR the meeting the _ specified Frequency _for Surveillances and any Required Action.with a Cc;>mpletion Tillie that requires the perfodic* ** performance Qf the Required Action on a "onc.e per ... 11*
• interval. __ * * -* SR 3.0.2-permits a 25% extension of the interval *specified in the Frequency.* This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance act i.vi ti es) * * (continued) _ . *B 3.0-11 Revision No: 0 __ ,

BASES SR. (continued) .... ':. *.* __ . -..... ' .*. -/ *. ' .... ',,. SR Applicability B 3.0 The 25% extension does significantly degrade the reliabiJity that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most.probable result of any particular Surveillance be.i ng performed is the veri f i ca*t ion of conformance with the SRs. : The exceptions to SR 3. O 2 are those Surve i 11 ances for which the 25% of the interval specified in the Frequency does not apply .. These exceptions are stated in _the indhidual Specifications. The requirements of regulations take precedence over the TS. Therefore, when a test interval is specified in the regulations, the test i riteryal .. be extended by the TS, and the SR include a Note in_.the Frequency stating, "SR 3.0.2is not applicable." An example of an excepttori when the test i"terval.is not specified in the regulatfons is the Note in the Primary Containment Leakage .Rate Testing Program, "SR 3.0.2 is not applicable-." This .exception* i's provided because the program* intludes of test intervals. . . . ,*,,. . . . . ' ; . As stated in SR 3. O. 2 ;. the 25% extension al so does-not apply to the* -in.-itial portion. of a periodic Completion Time that requires performance on ** "once per ... " *basis. The 25% extension applies to each after the init1al perf9rniance. The initial performance of Required whether it is particular Surveill.ance or some otne.r .remed i a 1 action,. i s considered. a. single action with a . single :Completion n me. One reason f Or* not. allowing the. 25% extension :to th.is CompJetion Time i_s that. such an action usually verifies that no Joss *of function *has occurred by* chec'ki ng. the stat.us of redundant or diverse. components or . accomplishes the functi an* of the inoperable' equipment in an alternative manner. . :: .. "Jhe of SR 3.0 .. 2' are not .. intencied.to be used*;._:. ,repeatec;l,ly,'mereTy ; as .. operat.i.oria l .. coriven ience to extend . Survetl 1 intervals ,(other than those .consistent with . **. *.* . refuel jng *intervals) 'or Completion Tillie *intervals .beyon(:t:those speci fi e.d.>' ' . ' ' " .SR :-:\ -. lhe to defer dec.laring. -j affected: equipme.nt inoperab] e or an e

• the when a Surveillance has not .... *beE!n completed _the-s*pecif_ied A delay .. -. : ... _: .. PBAPS* UNIT *3* * * '. period .. of to 24 or up to the. Ji mi t* the he_d : "-.. **-' ,* .: . **,*:.-*=**-. *-.:*, .. ** : -' -. ___ i ' . . , ' *. . .
• I .. _ .. ,._.-._ . . -' . .
• Revis.ion' No. 6 ** -. . .-.. . , .-. . ----,

BASES SR 3.0.3 (continued) SR Applicability B 3.0 Frequency, whichever is greater, applies from the point in *I time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met. This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance. The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance. since.there is a time interval specified, the missed should be performed at the first reasonable opportunity. SR provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a of MODE changes imposed by Required Actions Failure to comply with specified Frequencies for SRs is expected to be an infrequent Use of the delay period established by SR 3.G.3 is a flexibility which is not intended to be used as an operational convenience to extend Surveillance intervals: Whil*e up to 24 hours or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plarit risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to uni't conditions, planning, availability of personnel, and the required to perform the Surveillance. This risk impact should be managed through the program in continued 83.0-13 *Revision No. *1 BASES SR 3.0.3 (continued) SR 3.0.4 PBAPS UN IT 3, SR Applicability B 3.0 place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, 'Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants.' This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condihon as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the . importance of the component. Missed Surveillances for important components should be analyzed quantitatively. *If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to. determine the safest course of action. All missed Surveillances wil*l be placed in the licensee's Corrective Action Program. lf a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the. Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance. Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1. SR 3.0.4 establishes the that all applicable SRs be met before entry intb a MODE or other specified condition in the Applicability. This Spetification that system and component . OPERABILITY limits are met before entry into MODES or other specified in the . Applicability f6r which these systems and components ensure safe operation of the unit. The.ptovisions 6f this

• Specification should not be interpreted as endorsing the to exercise the practice of restoring systems or components to OPERABLE status before entering an associated MODE or bther specified coridition in the Applicability.
• A provision is to allow entry into a MODE or other specified condition ih the Applicability an LCO is not met due to Surveillance not beirig met in accordance with LCO 3.0.4. . . . . (continued B 3.0-14 Revision No. *53 I .. BASES SR 3.0.4 (continued) PBAPS UNiT 3 SR Applicability B 3.0 However, in certain circumstances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that Surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the LCD is not met in this instance, LCO 3.0.4 will *govern any restrictions that may (or may not) apply to MODE or other specified condition changes, SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3. The provisions of SR 3.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions i*n the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4. The precise requ1rements for performance of SRs are specified such that exceptions to SR 3.0.4 are not necessary. The specific time frames and .conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO's Applicability, would have its Frequency specified such that it is not "due" until the specific conditions
• needed are met. Alternately, the Surveillance may be stated in the form of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency. B 3.0-15 Revision No. 53 SDM B 3.1.1 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1 SHUTDOWN MARGIN {SOM) BASES BACKGROUND SOM requirements are specified to ensure: a. The reactor can be made subcritical from all operating conditions and transients and Design Basis Events; b. The reactivity transients associated with postulated accident conditions are controllable within acceptable limits; and c. The reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition. These requirements are satisfied by the control rods, as described in the UFSAR Section 1.5 (Ref. 1), which can compensate for the reactivity effects of the fuel and water temperature changes experienced all operating
• conditions. APPLICABLE .The control rod drop accident. (CRDA) analysis (Refs. 2 SAFETY ANALYSES and 3) assumes the core is subcritical with the highest PBAPS UNIT 3
• worth control rod withdrawn. Typically, the first control rod withdrawn has a very high reactivity worth should the core be critical during the withdrawal of the control _rod, the consequences of a CR.DA -could exceed the fuel damage limits for a CRDA (see Bases for LCO 3.1.6, "Rod Control0). Also, SOM is assumed-as an initial condition for the control rod removal error during refueling (Ref. 4) and Juel assembly insertion error during refueling (Ref._ 5) accidents. _The analysis of these reactivity
• inserti.on_events_assumes the refueling interlocks are OPERABLE when the reactor is in the refuel i ng mode of .. operation._ -. These interlocks prevent. the withdrawal of more -*than one control* rod from the *core during_ refueling .. * (Special consideration and.requirements for multiple control rod withdrawal during refueling are covered in Special LCD 3;10:6, riMultiple tontrol Rod Withdrawal-Refueling.0) *The analysis assumes this -'conditiotris acceptable since 'the core will be shut down -. with the highest worth control rod withdrawn, if adequate * (cont i n.ued) -83.1-1* *Revision No. O -1. I I BASES APPLICABLE SAFETY ANALYSES (continued) LCD APPLICABILITY ACTIONS PBAPS UNIT 3 SDM B 3.1.l SDM has been demonstrated. Prevention or mitigation of reactivity insertion events is necessary to limit energy deposition in the fuel to prevent significant fuel damage, which could result in undue release of radioactivity. Adequate SDM ensures inadvertent criticalities and potential CRDAs involving high worth cont.rel rods (namely the first control rod withdrawn) will not cause significant fuel damage. SDM satisfies Criterion 2 of the NRC Policy Statement. The specified SOM limit accounts for the uncertainty in the demonstration of SDM by testing. Separate SOM limits are provided for testing where the highest worth control rod is determined analytically or by measurement. This is due to the reduced uncertainty in the SOM test wheh the highest worth control rod is determined by measurement. When SOM is demonstrated by calculations not associated with a test (e.g., to confirm SOM during the fuel loading sequence), additional margin is included to account for uncertainties in the calculation. To ensure adequate SDM during the design process, a design margin is in.eluded to account for uncertainties in the design calculations (Ref. 6). In MODES I and 2, SOM must be provided because subcriticality with the highest worth control rod withdrawn is assumed in the CRDA analysis (Ref. 2) .. *Jn MODES 3 and 4, is required to ensure the reactor will be held subcritical with margin for a single withdrawn control rod. SOM is required in MODE 5 to prevent an open vessel, inadvertent.criticality during the withdrawal of a single control rod from a core cell containing one or more fuel assemblies (Ref .. 4) or*a.fuel assembly insertion error (Ref. 5) * . . . A.I With SDM*not within the* limits of the LCD .in MODE 1 or 2*,. SDM* must be restored within 6 *
• Jail ure . to meet the
• specified SDM may be caused by a control rod.that cannot be inserted. The allowed Completion Time .of 6. hours is * . . (continued) B.3.1-2 Revision No *. O BASES ACTIONS PBAPS UNIT 3 A.I . (continued) SOM 8 3.1.l acceptable, considering that the reactor can still be shut down, assuming no failures of additional control rods to insert, and the low probability of an event occurring during this interval. 8.1 If the SOM cannot be restored, the plant must be brought to MODE 3 in 12 hours, to prevent the potential for further reductions in available SOM (e.g., additional stuck control rods). The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. With SOM not within limits in MODE 3, the operator must immediately initiate action to fully insert all insertable control rods. Action must continue until all insertable control rods are fully inserted. This action results in the least reactive condition for the core. D.l, D.3, and D.4 With SDM not within limits in MODE 4, the operatoi must inunediately initiate action to fully insert all insertable control rods. Action must continue until all insertable control rods are fully inserted. This action results in the
• 1east reactive condition for the core. Action must also be initiated within 1 hour to provide means for control of potential radioactive releases. This includes ensuring secondary containment is OPERABLE; at least one Standby Gas Treatment (SGT) subsystem for Unit 3 is OPERABLE; and secondary containment isolation capability (i.e., at least one secondary containment isolation* valve and associated instrumentation are OPERABLE, or other acceptable administrative controls to assure isolation capability), in each associated secondary contai-nment penetration flow path not isolated that is assumed to be isolated to mitigate radioactivity releases. This may be performed as (continued) . B Revision No. 0 BASES ACTIONS PBAPS UNIT 3 D.l. D.2. 0.3. and D.4 {continued) SOM B 3.1.1 an administrative check, by examining logs or other information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the surveillances needed to demonstrate the OPERABILITY of the components. If, however, any required.component is inoperable, then it must be restored to OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE. E. l, E. 2, E. 3, E. 4, and E. 5 With SOM not within limits in MODE 5, the operator must immediately suspend CORE ALTERATIONS that could reduce SOM, e.g., insertion of fuel in the core or the withdrawal of control rods. Suspension of these activities shall not preclude completion of movement of a component to a safe . condition. Inserting control rods or removing fuel from the core will reduce the total reactivity and are therefore *
• excluded from the suspended actions. Action must also be inunediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Action must continue until all .insertable control rods in core cells containing one or more fuel assemblies have .been *fully inserted. *control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and therefore do not have to be inserted. Action also be within I to provide means . for contra l of potential radioactive rel eases. This . includes ensuring secondary containment is OPERABLE; at least one SGT subsystem for Unit 3 is OPERABLE; and . secondary containment isolation capability {i.e., at least one secondary containment isolation valve and associated instrumentation are OPERABLE, or other acceptable administrative controJs to assure isolation capability), _in each associated secondary containment penetration flow path not isolated that is assumed to be isolated to mitigate
• rad*ioactive releases. This may be, performed as an administrative check, by examining logs or other (continued) . B 3 .1-4 . Revision.No. 0 I !

BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 3. E.l, E.2, E.3, E.4, and E.5 (continued) SDM B 3.1.1 information, to determine if the components are out of service for*maintenance or other reasons. It is not necessary to perform the SRs needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status. Action must continue until all required components are OPERABLE. SR 3.1.1.1 Adequate SDM must be verified to ensure that the reactor can be made subcritical from any initial operating condition. This can be accomplished by a test, an evaluation, or a combination of the two. Adequate SDM is demonstrated before or during the first startup after fuel movement or shuffling within the reactor pressure vessel, or control rod replacement. Control rod replacement refers to the decoupling and removal of a control rod from a core location, and subsequent replacement with a new control rod or a control rod from another core location. Since core reactivity will vary during the cycle as a function of fuel depletion and poison burnup, the beginning of cycle (BOC) test must also account for changes in core reactivity during the cycle. Therefore, to obtain the SDM, the initial measured value must be increased by an adder, "R", which is the difference between the calculated value of maximum core reactivity during the operating cycle and the calculated BOC core reactivity. If the value of R is negative (that is, BOC is the most reactive point in the cycle), no correction to the BOC measured value is required (Ref. 3). For the SDM demonstrations that rely solely on calculation of the highest worth control rod, additional margin (0.10% 8k/k) must be added to the SDM limit of 0.28% 8k/k to account for uncertainties in the calculation. The SDM may be demonstrated during an in sequence control rod withdrawal, in which the highest worth control rod is analytically determined, or during local criticals, where the highest worth control rod is determined by testing. Local critical tests require the withdrawal of o.ut of (continued) B 3.1-5 Revision No. 73 BASES SURVEILLANCE REQUIREMENTS. REFERENCES PBAPS UNIT 3 SR 3 .1.1.1 (continued) SDM B 3.1.1 sequence control rods. This testing would therefore require bypassing of the Rod Worth Minimizer to allow the out of sequence withdrawal, and therefore additional requirements must be met (see LCO 3.10.7, "Control Rod Operating"). The Frequency of 4 hours after reaching criticality is allowed to provide a reasonable amount of time to perform the required calculations and have appropriate verification. During MODES 3 and 4, analytical calculation of SDM may be used to assure the requirements of SR 3.1.1.1 are met . . During MODE 5, adequate SDM is required to ensure that the reactor does not reach criticality during control rod withdrawals. An evaluation of each in vessel fuel movement during fuel loading (including shuffling fuel within the core) is required to ensure adequate SDM is ma:intained during refueling. This evaluation ensures that the intermediate loading patterns are bounded by the safety analyses for the final core loading pattern. For example, bounding analyses that demonstrate adequate SDM for the most reactive configurations during the refueling may be performed to demonstrate acceptability of the entire fuel movement sequence. These bounding analyses include additional margins to. the associate.d uncertainties. Spiral offload/reload sequences, including modified quadrant spiral offload/reload sequences, inherently satisfy the SR, provided the* fuel assemblies are reloaded in the same configuration analyzed for the new cycle: Removing fuel from the core will result in an increase in SDM. 1. UFSAR, Sections 1. 5. 1. 8 and 1. 5. 2. 2. 7 *. 2. Section 14. 6 2 . . 3 .: . riGerieral Electric *standard Application for Re.actor_ Fuel," approved revision .. 4.. UFSAR,. Section 14. 5. 3. 3 .. 5; ;. " . UFSAR, -". SeC::tion 14 .5. 3. 4. (continued) B _3.1-6 Revision No. 7.3 BASES REFERENCES (continued) PBAPS UNIT 3 6. UFSAR, Section 3.6.5.4. B-3. l-7, SDM B 3.1.1 Revision No. 73 Reactivity Anomalies B 3.1.2 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.2 Reactivity Anomalies BASES BACKGROUND PBAPS UNIT 3 In accordance with the UFSAR (Ref. 1), reactivity shall be controllable such that subcriticality is maintained cold conditions and acceptable fuel design limits are not exceeded during normal operation and abnormal operational transients. Therefore, reactivity anomaly is used as a measure of the predicted versus measured (i.e., monitored) core reactivity during power operation. A large reactivity anomaly could be the result of unanticipated changes in fuel reactivity or control rod worth or at conditions not consistent with those assumed in the predictions of core reactivity, and could potentially result in a loss of SOM or violation of acceptable fuel design limits. Comparing predicted versus measured core reactivity supports the SOM demonstrations (LCD 3.1.l, "SHUTDOWN MARGIN (SOM)") in assuring the reactor can be brought safely to cold, subcritical conditions. When the reactor core is critical or in normal power operation, a reactivity balance exists and the net reactivity is zero. A comparison of predicted and measured reactivity is convenient under such a balance, since parameters are being maintained relatively stable under steady state power conditions. The.positive inherent .in the core design is balanced by the negative rea.cti vity of the control components' thermal feedback' neutron leakage, and materials in the core that absorb neutrons; .such as burnabla absorbers, producing zero net reactivity.

• In to achieve the required fuel cycle energy output, the uranium enrichment in the new fuel loading and the fuel loaded in the previous cycles provide excess positive reactivity beyond that required to sustain steady state operation at the beginning of cycle (BOC). When the reactor is critical at RTP and operating moderator temperature, the excess positive reactivity is compensated by burnable absorbers (e.g., gadolinia), control rods, and whatever neutron poisons (mainly xenon and samarium) are present in the The predicted core reactivity, as represented by continued B *3.1-8 No. 113'
• BASES BACKGROUND (continued) APP LI CABLE SAFETY ANALYSES LCD PBAPS UNIT 3 Reactivity Anomalies B core keffective Ckeff), is calculated by a 30 core simulator code as a function of cycle exposure. This calculation is performed for projected operating states and conditions throughout the cycle. The monitored core keft is calculated by the core monitoring system for actual plant conditions and is then compared to the predicted value for the cycle exposure. Accurate prediction of core reactivity is either an explicit or implicit assumption in the accident analysis evaluations (Ref. 2). In particular, SDM and reactivity transients, such as control rod withdrawal accidents or rod drop
• accidents, are very sensitive to accurate prediction of core reactivity. These accident analysis evaluations rely on computer codes that have been qualified against available test data, operating plant data, and analytical benchmarks. Monitoring reactivity anomaly provides additional assurance that the nuclear methods provide an accurate representation of the core reactivity. The comparison between measured and predicted initial core reactivity provides a normalization for the calculational models used to predict core reactivity. If the measured and predicted core keffCs> for 1dentical core conditions at BOC do not reasonably agree, then the assumptions used in the reload cycle design analysis or the calculation models used to predict core keff may not be accurate. If reasonable. agreement between and predicted core reactivity exists at BOC, then the prediction may be to the value. Thereafter; any significant in the measured core ketf from the predicted core keff that *develop during fuel depletion may be an indicatibn that the assumptions of the DBA and transient analyses are no longer. id, or that* an unexpected in has occurred.
• Reactivity anomalies satisfy Criterion 2 of the NRC Policy Statement.* Large differences between monitored and core reactiv'ity may indicate that the assumptions of the DBA and transient analyses are no valid, or that the continued B 3.1-9 Revision No. *113 BASES LCO (continued) APPLICABILITY . ACTIONS PBAPS UNIT 3 Reactivity Anomalies B 3.1.2 uncertainties in the "Nuclear Design Methodology" are larger than expected. A limit on the difference between the monitored and the predicted core keff of +/- 1% has been established based on engineering judgment. A> 1% deviation in reactivity from that predicted is larger than expected . for normal operation and should therefore be evaluated. A deviation as large as 1% would not exceed the design conditions of the reactor and is on the safe side of the postulated transients. In MODE 1, most of the control rods are withdrawn and steady state operation is typically achieved. Under these conditions, the comparison between predicted and monitored core reactivity provides an effective measure of the reactivity anomaly. In MODE 2, control rods are typically being withdrawn during a startup. In MODES 3 and 4, all control rods are fully inserted and therefore the reactor is in the least reactive state, where monitoring core reactivity is not necessary. In MODE 5, fuel loading results in a continually changing core reactivity. SOM requirements (LCO 3.1.1) ensure that fuel movements are performed within the bounds of the safety analysis, and an SOM demonstration is required during the first startup following operations that could have altered core reactivity (e.g., fuel movement, control rod replacement, shuffling). The SOM test, required by LCO 3.1.1, provides a direct comparison of the predicted and monitored core reactivity at cold conditions; therefore, reactivity anomaly is not required during these conditions . Should an anomaly develop between measured and predicted core reactivity, the core reactivity difference must be restored to within the limit to. ensure continued operation is within the core design assumptions. Restoration to within the limit could be performed by an evaluation of the core design and safety analysis to determine the reason for the anomaly. This evaluation normally reviews the core conditions to determine their consistency with input to design calculations. Measured core and process parameters are also normally evaluated to determine that they are within the bounds of the safety analysis, and safety analysis calculational models may be reviewed to verify that they are adequate for representation of the core conditions. continued B 3.1-10 Revision No. 94 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS* UNIT 3 A.l (continued) Reactivity Anomalies B 3.1.2 The required Completion Time of 72 hours is based on the low probability of a OBA occurring during this period, and allows sufficient time to assess the physical condition of the reactor and complete the evaluation of the core design and safety analysis. If the .core reactivity cannot be restored to within the 1% limit, the plant must be brought to a MODE in which the lCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. SR 3.1.2.1 *The core* monitoring. system cal cul ates the core keff for the conditions obtained from plant instrumentation. A comparison. of the monitored core keff to the predicted core keff at the same cycle exposure is used to cal cul ate* the
• react1v-ity difference. The comparison is required when the core reactivity has potentially changed by a significant amount.* This may occur following a refueling in which new fuel as*semblies are loaded, fuel assemblies are shuffled within the core, or control replaced or shuffled . . ControJ fod refers to the decoupling and removal of a control rod from *a core* location, and subsequent replacemeht With a new control rod or a control rod fr9m core 16catidn*. Also; core reactivity changes during the lrterval after equilibMum conditions following a startup is based *on the need for* xeno.n concentration*s_*in the* core; such that an . a'ccurate comparison between the monitored and predicted core keff can be For the purposes of this SR, the reactor is to be equilibrium conditions when state operat*i o_n.s *(no control rod movement or core continued B 3.1-11 Re,vision No. 113 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 3 SR 3.1.2.1 (continued) Reactivity Anomalies B 3.1.2 flow changes) at ::::: 75% RTP have been obtained. The 1000 MWD/T Frequency was developed, considering the relatively slow change in core reactivity with exposure and operating experience related to variations in core reactivity. The comparison requires the core to be operating at power levels which minimize the uncertainties and measurement errors, in order to obtain meaningful . results. Therefore, the comparison is only done when in MODE 1. 1. UFSAR, Section 1.5. 2. UFSAR, Chapter 14 .. B-3.1-12 Revision*No. o Control Rod OPERABILITY B 3 .1.3 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.3 Control Rod OPERABILITY BASES BACKGROUND Control rods are components of the Control Rod Drive (CRD) System, which is the primary reactivity control system for the reactor. In conjunction with the Reactor Protection System, the CRD System provides the means for the reliiable control of reactivity changes to ensure under conditions of normal operation, including abnormal operational transients, that specified acceptable fuel design limits are not exceeded. In addition, the control rods provide the capability to hold the reactor core subcritical under all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the CRD System. The CRD System is designed to satisfy the requirements specified in Reference 1. The CRD System consists of 185 locking piston control rod drive mechanisms (CRDMs) and a hydraulic control unit for each dr.ive mechanism. The locking piston type CROM is a double acting hydraulic piston, which uses condensate water as the operating fluid. Accumulators provide additional energy for scram. An index tube and piston, coupled to the control rod, are locked at fixed increments by a collet The collet fingers engage notches in the index tube to prevent unintentfonal* withdrawal.of the control rod, but without restricting insertion.
• This Specification, along with LCO 3.1.4, "Control Rod Scram Times,"and LCO 3.1.5, "Control Rod Scram Accumulators," ensure that the performance of the control rods in the event of a Design Basis Accident (OBA) or transient meets the assumptions used in the safety analyses of References 2, 3, and 4. APPLICABLE The analytical methods and assumptions used in the SAFETY ANALYSES evaluations involving control rods are presented in References 2, 3, and 4. The control rods provide the primary means for rapid reactivity control (reactor scram), for maintaining the reactor subcritical and for limiting the potential effects of reactivity insertion events caused by malfunctions in the CRD System. (continued) . PBAPS. UNIT 3 s-3.-1-13 . Revision No. O _J BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UN IT 3 Control Rod OPERABILITY B 3.1.3 The capability tQ insert the control rods provides assurance that the assumptions for scram reactivity in the OBA and transient analyses are not violated. Since the SOM ensures the reactor will be subcritical with the highest w6rth control rod withdrawn (assumed single failure), the additional failure of a second control rod to insert,. if required, could invalidate the demonstrated SOM and potentially limit the ability of the CRO System to hold the reactor subcritical. If the control rod is stuck at an inserted position and becomes decoupled from the CRO, a control rod drop accident CCROA) can possibly occur. Therefore, the requirement that all control rods be OPERABLE ensures the CRO System can perform its interided function. The control rods also protect the fuel from damage which could result in release of radioactivity. The limits protected are the MCPR Safety Limit CSL) (see Bases for SL 2.1.1, "Reactor Core SLs" and LCD 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)"), the 1% cladding strain fue] design limit (see for LCD 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)"), and the fuel damage limit (see Bases for LCD 3.1.6, "Rod Pattern Control") during reactivity insertion events. The negative reactivity insertion (scram) provided by the CRO System provides the analytical basis for determinatiori of. p l a n t t h e rm a l l i mi ts an d p r o v i d e s p r o t e ct i on a g a i n s t Jue l damage limits during a CRDA. The Bases for LCO 3.1.4, LCO 3.1.5; and LCD 3.1.6 discuss in more detail how the SLs are protected by the. CRQ System. Control rod OPfRABILITY satisfies Criterion 3 of the NRC Policy Statement . .Th*e OPERABILITY of an individual control rod is based on a combination of factors; primarily, the scram insertion .times, the control rod c6upling integrity, and the ability to determine the control rod position, Accumulator OPERABILITY is addressed by LCD 3.1.5. The associated accumulator status for a control rod only affects the scram insertion times;-therefore, an inoperable accumulator does not immediately require declaring a control rod Although not all control rods are required to be OPERABLE to satisfy the intended reictivity .control requirements, strict continued B 3.1-14 Revision No. 50 BASES LCO {continued) APPLICABILITY ACTIONS PBAPS UNIT 3 Control Rod OPERABILITY B3.l.3 control over the number and distribution_ of inoperable control rods is required to satisfy the assumptions of the OBA and transient analyses. In MODES 1 and 2, the control rods are assumed to function during a OBA or transient and are therefore required to be OPERABLE in these MODES. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod OPERABILITY during these conditions. rod requirements in MODE 5 are located in LCO 3.9.5, "Control Rod OPERABILITY-Refueling.11 The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod. This is acceptable, the Required Actions for each Condition provide appropriate compensatory actions for each inoperable control rod. Complying with the Required Actions may allow for continued operation, and subsequent inoperable control rods are governed by subsequent Condition entry and application of associated Required Actions.
• A.I. A.2. A.3, and A.4 A control rod is considered stuck if it will not insert by either CRD drive water or scram pressure (i.e., the control rod cannot be inserted by CRD drive water and cannot be inserted by scram pressure.) With a fully inserted control rod stuck, only those actions specified in Condition C are required as long as the control rod remains fully The Required Actions are modified by a Note, which allows the rod worth minimizer (RWM) to be bypassed if required to allow continued operation. LCO 3.3.2.1, "Control Rod Block Instrumentation," provides additional requirements when the RWM is bypassed to ensure compliance with the CRDA analysis. With one withdrawn control rod stuck, the local scram reactivity rate assumptions may not be met if the stuck control rod separation criteria are not met. Therefore, a verification that the separation criteria are met must be performed immediately. The separation criteria are not met if a) the stuck control rod occupies a location adjacent to two "slow" control rods, b) the stuck control rod occupies a location adjacent to one "slowR control rod, and the one "slow" control rod is also adjacent to another "slow" control rod, or c) if the stuck control rod occupies a (continued) B 3.1-15 Revision No. 2 BASES ACTIONS PBAPS UN IT 3 A.1. A.2. A.3. and A.4 (continued) Control Rod_ OPERABILITY B 3.1.3 location adjacent to one "slow" control rod when there is another pair of "slow" control rods adjacent to one another. The description of ;'slow" control rods is provided in LCO 3.1.4, "Control Rod Scram Times." In addition, the associated control rod drive must be disarmed in 2 hours. The allowed Completion Time of 2 hours is acceptable, considering the reactor can still be shut down, assuming no additional control rods fail to insert, and provides a reasonable time to perform the Required Action in an orderly manner. The control rod must.be isolated from both scram and normal insert and withdraw pressure. Isolating the control rod from scram and normal insert and withdraw pressure prevents damage to the CROM. The control rod should be isolated from scram and normal insert and withdraw pressure, while cooling water to the CRO. Monitoring of the insertion capability of each withdrawn control rod must also be performed within 24 hours from discovery of Condition A concurrent with THERMAL POWER greater than the low power setpoint CLPSP) of the RWM._ SR 3.1.3.3 performs periodic tests of the control rod insertion capability of withdrawn control rods. Testing each withdrawn control rod ensures that a generic problem does not exist._ This Completion Time also allows for an excepti_on to the normal "time zero" for beginning the allowed-outage time "clock." The-Required Action A.3 Completion only upon of Condition A with THERMAL POWER than the actual LPSP of the RWM, since the notch insertions may .not be compatible with the requirements of rod pa-ttern control CLCO 3.1.6) and the RWM'CLCO Jhe lompletion Time of 24 from 6f £pndition A concurrent THERMAL POWER greater than the LPSP of-the RWM provides-a re as 6 nab l e ti me . to test _the -control rods , cons i de r i n g the potential for a'need to r:educe power to perform the T6 allow* cont.in.Lied operation with a -'withdr_awn control rod stuck, an of adequate SOM is also within 72 hours. Should a OBA or tr_ansient require a shutdown, to preserve the single.failure criterion, ah control rod have to be to fiil insert when _ r;equfred.
• The-refo-re, the _original SOM demonstration may not be valid. The.SOM must therefore be evaluated (by or a*nalysis) with the stuck.control rod at its B 3.1-16 Revision No. so*

BASES ACTIONS PBAPS UN IT 3 A.1. A.2. A.3. and A.4 (continued) Control Rod OPERABILITY B 3.1.3 stuck positioh and the highest worth OPERABLE control rod assumed to be fully withdrawn; The allowed Completion Time of 72 hours to verify SOM is adequate, considering that with a single control rod stuck in a withdrawn position, the remaining OPERABLE tontrol rods are cap!ble of providing the required scram and shutdown reactivity. Failure to reach MODE 4 is only likely if an additi anal control rod adjacent to the stuck control rod also fails to insert during a required scram. Even with the postulated additional single failure of an adjacent control rod to insert, s0fficient reactivity control remains to reach and maintain MODE 3 conditions (Ref. 5 and 6). With two 6r more withdrawn control rods stuck, the plant must be brought to MODE.3 within 12 hours. The occurrence of mqre than one control r6d stuck at a withdrawn position increases the probability that the reactor cannot be shut down if required. Insertion of all insertable control *rods the possibility of an additional failure of a control rod to insert. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in Bn orderly manner and without challenging plant sjstems. C.l and C-.2 With one or more control rods inoperable f6r reasons other than being in the withdrawn position (including . _ control_ rod which: 1s stuc1<. *in the fully _inserted position) may continue, the control rods are fully :inserted within 3_ hours and ,disarmed (electrkally or hydraulically) within 4 hours. Inserting a control rod scram capabilities are not adversely affected. The control rod is disarmed to prevent subsequent contro-1* rods can be hydraulically disarmed by closing the drive water and exhaust water* isolation control rods can be electrically disarmed by disconnecting power *'from all four directional* co'ntrol *valve solenoids. Required Action {.i modified by a Noie, the RWM to be to insert{on of the inoperable conl i nued B 3.1"17. *Revision No. 64 BASES ACTIONS PBAPS UN IT 3 C.l and C.2 (continued) Control Rod OPERABILITY B 3.1.3 control rods and continued operation. LCO 3.3.2.1 providei additional requirements when the RWM is to ensure compliance with the CRDA analysis. The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control rods in an orderly manner and without challenging plant systems. D.l and D.2 Out of sequence control rods may increase the potential* reactivity worth of a dropped control rod during a CRDA. At s 10% RTP, the arialyzed rod sequence (Ref. 5 and 6) requires inserted control rods not in with the analyzed rod position sequence to be separated by at least two OPERABLE control rods in all directions, including the diagonal. Therefore, if two or more i noperab.l e control rods are not in with the analyzed rod position sequence and not separated by at least two OPERABLE control rods, action must be taken to rest6re compliance with the analyzed rod position sequence or restore the control rods to OPERABLE status. Condition D is modified by a Note indicating that the Condition is not applicable when > 10% RTP, since the analyzed rod position sequence is not required to be followed under these conditions, as described in the for LCO 3.1:6. The allowed Completion Time of 4 is considering the low probability of a CRDA occurring. If any Required Action and associated Completion Time of Condition A, C, or D are not met, or there are nine or more inoperable control rods, the plant must be brought to a MODE in which the LCO does not To achieve this status, the plant must be brought to MODE 3 within 12 hours. This eniures all insertable control rods are inserted and places the reactor in a condition that does not require the active function .(i.e., scram) of the control rods. The number of control rods permitted to be inoperable when operating above 1 0 % RT P ( e . g . , n o C RD A co n s i d e r a t i o n s ) c o u.l d b e mo re t h a n the value specified, but the occurrence of a large number of continued B 3.1-18. Revision No. 64 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 3*. Ll (continued) Control Rod OPERABILITY B 3 .. 1. 3 inoperable control rods could be indicative of a generic problem, and investigation and resolution of the potential problem should be undertaken. The allowed Completion Time of 12 hours *is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems. SR 3.1.3.1 The position of each control rod must be determined to ensure adequate information on control rod position is available to the operator for determining control rod OPERABILITY and controlling rod patterns. Control rod position may be determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, or by the use of other appropriate methods. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.3.2 DELETED SR 3.1.3.3 Control rod insertion capability is demonstrated by each partially or fully withdrawn control rod at least one notch and observing that the control. rod moves. The control rod may then be returned to its original position. ensures* the control. rod is not stuck and is free to dn a scram signal. This Surveillance not required when THERMAL POWER is .less than or equal to actual LPSP of the RWM;. since the notch ihsertions may not be compatible the requirements of the analyzed rod positi6n CLCO 3.1.6) and the RWM CLCO The Surveillance Frequency is controlled* under the Surveillance Frequency Control Program. At any time, if a control rod is immovable, a *.*. ** 1. . -continued B 3.1-19 Revision No: 87

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BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 SR 3.1.3.3 (continued) Control Rod OPERABILITY B 3.1.3 determination of that control rod's trippability (OPERABILITY) must be made and appropriate action taken. For example, the unavailability of the Reactor Manual Control System does not affect the OPERABILITY of the control rods, provided SR 3.1.3.3 is current in accordance with SR 3.0.2. SR 3.1.3.4 Verifying that the scram time for each control rod to notch position 06 is 7 seconds provides reasonable assurance that the control rod will insert when required during a OBA or transient, thereby completing its shutdown function. This SR is performed in conjunction with the control rod scram time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," and the functional testing of SDV vent and drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlap this Surveillance to provide complete testing of the assumed safety function. The associated Frequencies are acceptable, considering the more frequent testing performed to demonstrate other aspects of control rod OPERABILITY and operating experience, which shows scram times do not significantly change over an operating cycle. SR 3.1.3.5 Coupling verification is performed to ensure the control rod is connected to the CROM and will perform its intended function when necessary. The Surveillance requires verifying a control rod does not go to the withdrawn overtravel position. The position feature provides a positive check on the coupling integrity since only an uncoupled CRD can reach the overtravel position. The verification is required to be performed any time a. control rod is withdrawn to the "full out" position (notch position 48) or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling (CRD changeout and blade replacement or complete cell disassembly, i.e., guide tube removal). This includes control rods inserted one notch and then returned continued B 3.1-20 Revision No. 80 BASES SURVEILLANCE REQUIREMENTS REFERENCES .. ' * . .-PBAPS .UN IT 3 SR 3.1.3.5 (continued) Control Rod OPERABILITY B 3.1.3 to the "full out" position during the performance of SR.3.1.3.2. This Frequency is considering the low probability that a control rod will become uncoupled when it is not being moved and operating experience related to uncoupling events. 1. UFSAR, Sections and 1.5.2.2. 2. UFSAR, Section 14.6.2. 3. UFSAR, Appendix K, Section VI. 4. UFSAR, Chapter 14. 5. NED0-21231, "Banked Position Withdrawal Sequence," Section 7.2, January 1977. 6. NEDE-24011-P-A, Electric Standard Application for Reactor Fuel," latest approved revision. '.:' B 3. 1-2.1 . Revision No. 64 Control Rod Scram Times B 3.1.4 B 3.1 REACTIVITY CONTROL SYSTEMS B 3 .1. 4 Contra l Rod Scram Times BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 The scram function of the Control Rod Drive (CRD) System controls reactivity changes during abnormal operational transients to ensure that specified acceptable fuel design limits are not exceeded (Ref. 1). The control rods are scrammed by positive means using hydraulic pressure exerted on the CRD piston. When a scram signal is initiated, control air is vented from the scram valves, allowing them to open by spring action. Opening the exhaust valve reduces the pres*sure above the main drive piston to atmospheric pressure, and opening the inlet.valve applies the accumulator or reactor pressure to the bottom of the piston. Since the notches in the index tube.are tapered on the lower edge, the collet fingers are forced open by cam action, allowing the index tube to move upward without restriction because of* the high differential pressure across the piston. As the drive moves upward and the *accumulator pressure reduces below the reactor pressure, a ball c.heck valve opens,* letting the re-actor pressure complete the scram action. If the reactor pressure is low, such as during startup, the accumulator will fully insert the control rod in the required time without assistance from reactor:pressure.

• The analytical methods and assumptions used in evaluating the control rod scram function are presented in **References 2, 3, and 4." The Design Basis Accident (DBA) and transient analyses a*ssume that all of the control rods scram at a specified insertiQn:rate. The resulting negative scram reactivity forms the basis.for the determination of plant thermal limits the MCPR). Other dfstributions of s_cram times several control rods scramming slower than the average time with several control*rods scramming faster than the average time) can also provide sufficient scra01 reactivity.* Surveillance of *each individual control rod's sc*ram time ensures the scram reactivity assumed in the OBA and transient analyses can be met. (continued) *B:3.l-22 ReviSion No. O BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UN IT 3 Control Rod Scram Times B 3.1.4 The scram function of the CRD System protects the MCPR Safety Limit CSU (see Bases for SL 2.1.1, "Reactor Core SLs" and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)") and the 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), which ensure that no fuel will occur if these limits are not exceeded. Above 800 psig, the scram function is designed to insert negative reactivity at a rate fast enough to prevent the actual MCPR from becoming less than the MCPR SL, during the analyzed limiting power transient. Below 800 psig, the scram function assumed to perform during the control rod drop accident (Ref. 5) and, therefore, *also provides protection against violating fuel damage limits during reactivitY. insertion accidents (see Bases for LCO 3.1.6, "Rod Pattern Control"). For the reactor vessel overpressure protection analysis, the scram function, along with the safety/relief valves, ensure that the peak vessel pressure is maintained within the applicable ASME Code limits. Control ro,d scram times satisfy Criterion 3 of the NRC Policy Statement. The scram times specified in Table 3.1.4-1 (in the accompanying LCO) are required to ensure.that the scram reactivity assumed in the OBA and transient analysis is met (Ref; 6). To account for single failures and "slow" scramming control rods, the scram times specified in Table 3.1.4-1-are faster than those assumed in the design basis analysis. The scram times have a margin that al.lows up to 7% of the rods (e.g., 185 x 7% = 13) to have scram times exceeding the specified limits Ci .e., "slow" control rods) assuming a single stuck control rod (as allowed by LCO 3.1.3, "Control Rod OPERABILITY") and an additional control rod scram per the single failure criterion. The scram times are specified as a function of reactor steam dome pressure-to account for the pressure dependence of the scram times. The scram times are specified reJative to measurements based on reed switch positions, which provide the control. rod position The reed switch closes ("pickup") when the continued B-3.1-23 Revision *No. 50 BASES . LCO (continued) APPLICABILITY ACTIONS PBAPS UNIT 3 Control Rod Scram Times B 3.1.4 index tube passes a specific location and then opens ("dropout") as the index tube travels upward. Verification of the specified scram times in Table 3.1.4-1 is accomplished through measurement of the 11dropout11 times. To ensure that local scram reactivity rates are maintained within acceptable limits, no more than two of the allowed "slow" control rods may occupy adjacent locations. Table 3.1.4-1 is modified by two Notes, whiC:h state that control rods with scram-times not within the limits of the table are considered "slow" and that control rods with scram times > 7 seconds are considered as requ*ired by SR 3 .1.3 .4. This LCO applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed (LCO 3.1.3). Slow scramming control rods may be conservatively declared inoperable and not accounted for as "slow" control rods. In MODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these plant conditions. These events are assumed to occur during startup and power operation; therefore, the scram function of the control rods is required during these MODES. In .
• MODES 3 and 4, the. control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is This provides adequate requirements for contra 1 rod scram capabi 1 i ty during these , Scram requirements in MODE 5 are contained in LCO 3.9.5, "Control Rod OPERABILITY-Refueling.... .
• A.1 When the requirements of 'this Leo are not met, the rate. of negative reactivity insertion during a scram may not be within the assumptions of the safety analyses. Therefore, the pl ant must be brought to a MODE in whith the LCO does.*
• not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from* full power conditions in an. orderly manner and. without challenging plant systems. . . (continued)** *., B.3.1-24 Rev.is iOn No. 0 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 Control Rod Scram Times B 3.1.4 The four SRs of this LCD are modified by a Note stating that during a single control rod scram time surveillance, the CRD pumps shall be isolated from the associated scram accumulator. With the CRD pump isolated, Ci .e., charging valve cl.osed) the influence of the CRD pump head does not affect the single control rod scram times. During a full core the CRD pump head would be seen by all control rods and would have a negligible effect on the scram insertion times. SR 3.1.4.1 The scram reactivity used in OBA and transient analyses is based on an assumed control rod scram time. Measurement of the scram times with reactor steam dome pressure 800 psig demonstrates acceptable scram times for the transients analyzed in References 3 and 4. Maximum scram insertion times occur at a reactor steam dome pressure of approximately 800 psig because of the competing effects of reactor steam dome pressure and stored accumulator energy. Therefore, demonstration of adequate scram times at reactor steam dome pressure 800 psig ensures that the measured scram times will be within the specified limits at higher pressures. Limits are specified as a function of reactor pressure to accciunt for the sensitivity of the scram insertion times with pressure and to allow a range of pressures over which scram time testing can be performed. To ensure that scram time testing is performed within a reasonable time after a shutdown 120 days or longer, all control rods are required to be tested before exceeding 40% RTP. This Frequency is acceptable the additional surveillances performed for control rod OPERABILITY, the frequent verification of adequate accumulator pressure, and the required testing of control rods affected by fuel movement within the associate core cell and by work on control rods or the CRD System. SR 3.1.4.2 Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. The sample remains representative continued B 3.1-25 Revision No. 58 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 SR 3.1.4.2 (continued) Control Rod Scram Ti mes B 3.1.4 if no more than 7.5% of the control rods in the sample.tested are determined to be "slow". With more than 7.5% of the sample declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 7.5% criterion Ci .e., 7.5% of the active sample size) is satisfied, or until the total number of "slow" control rods (throughout the core, from all Surveillances) exceeds the LCO limit. For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data may have been previously tested in a sample. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.4.3 When work that could -affect the scram insertion time is performed on a control rod or the CRD System, testing must be done to demonstrate that each affected control rod retains adequate scram performance over the range of applicable reactor press.ures from zero to the maximum
• pressure. This can be met by performance 6f time testing or Diaphragm Alternative Response Time (DART) testing, wheh it is concluded that DART testing monitors *the performance of all affected components. *The testing must be performed once before dec*l ari ng the control rod OPERABLE .. The required testing must: demonstrate the affe6ted control rod is still within acceptable limits. The l.imit.s for reactor pressures < 800 psig established based on a -"high probability of meeting the acceptance *c.ri teri a at reactor pressures ;:=: 800 psi g ; Lim i ts for ;:=: 8 O O psi g are found i n Tab l e 3 .. 1. 4 -1. * . If .testing demonstrates the .affected cont'rol *rod does not. meet {1mits, but is* within: the 7 second limit of Tabl'e 3;1.4:1; Note 2* the' control rod: earl° be *declared OPERABLE -. ' -and "slow.*'.' continued . . -* . B 3.1-26 Revision No. 87 I I.*** BASES SURVEILLANCE REQUIREMENTS REFERENCES* PBAPS UN IT 3. SR 3.1.4.3 (continued) Control Rod Scram Times B 3.1.4 Specific examples of work that could affect the scram times are (but are not limited to) the following: removal of any CRD for maintenance or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator, isolation valve or check valve in the piping required for scram. The Frequency of once prior to declaring the affected control rod OPERABLE is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of contra 1 . rod OPERABILITY. SR 3.1.4.4 When work that could affect the scram insertion time is on a control rod or CRD System, or when fuel movement within the reactor vessel occurs testing must be done to demonstrate each affected control rod is still within the 1 i mits of Tab 1 e 3 .1. 4-1 with the reactor steam dome 800 psig. Where work been performed at high reactor pressure, the requirements of SR 3.1.4.3 and SR 3.1.4.4 can be satisfied with one test. For a control rod affected by work performed while shut down, however, a zero and high pressure test may be required. This ensures that, to withdrawing: the control rod for operation) the control rod scram is a6ceptable ope(ating pressure conditions. Alternatively, *a control rod scram-test during hydrostatic testing coul.d also satisfy both criteria. When fuel occurs withjn the reactor vessel, only those control rods associated with the core cells affected by the fuel mci'veme.nt are requh*ed to be scram time tested.
• During a routine* refueling outage, it* is expected that all'control rods will be affected.
• The of ooce pri6r exceeding 40% RTP is acceptable because of the capabi 1 i ty to te.st* the control* rod over of operating and the more frequent survei*l lances on othe*r *aspects of control rod OPERABILITY. 1. UFSAR, Sections 1.5'.l.3'and .1.5.2.2. 2. UFSAR, Section 14.6.2 .. continued B Revision No. 58 BASES REFERENCES PBAPS UNIT 3 3. UFSAR, Appendix K, Section VI. 4. UFSAR, Chapter 14. Control Rod Scram Times B 3.1.4 5. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision. 6. Letter from R. E. Janecek (BWROG) to R. W. Starostecki (NRC), "BWR Owners Group Revised Reactivity Control System Technical Specifications," BWROG-8754, September 17, 1987. B 3 .1.-28 ' Revision No. 73 Control Rod Scram Accumulators B 3.1.5 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.5 Control Rod Scram Accumulators BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UN IT 3 The control rod scram accumulators are part of the Control Rod Drive CCRD) System and are provided to ensure that the control rods scram under varying reactor conditions. The control rod scram accumulators store sufficient energy to fully insert a control rod at reactor vessel pressure. The accumulator is a hydraulic cylinder with a free floating piston. The piston separates the water used to scram the control rods from the nitrogen, which provides the required energy. The scram accumulators are necessary to scram the tontrol rods within the required insertion times of LCO 3.1.4, "Control Rod Scram Times." The analytical methods and assumptions used in evalJating the control rod scram function are presented in References 1, 2, and 3. The Design Basis Accident (OBA) and transient assume that all of the control rods scram at a specified insertion rate. OPERABILITY of each i ndi vi dual control rod scram accumulator, along with LCO 3.1.3, "Control Rod OPERABILITY," and LCD 3.1.4. ensures that the scram reactivity assumed in the OBA and analyses can met. The of an inoperable accumulator may invalidate prior scram time measurements. for . the assoc i ate d co rit r o l rod . The scram function of the CRD System, and therefore the OPERABILITY of .the accumulators, protects the MCPR Safety Limit Bases.for SL 2.1.1, Core SLs" and LCD 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and 1% cladding plastic str.ain fuel design_ limit (see Hoses for .. LCO 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)"), which .I ensure that. no fuel damage will occur if these limits are not ex c e e d e d ( s e e B a s e s fo r LC 0 3 . 1 . 4 ) . I n a d d it i o n , t h e s c r am function at low reactor vessel pressure (i.e., start.up
• conditions) provides prcitection violating fuel limits during reactivity insertion (see BGses for* LCD 3.1.6, "Rod Pattern Contfol *rod accumulators satisfy Criterion 3 of the NRC Policy ' (continued) B 3.1-29 Revision No. 50_

BASES (continued) Control Rod Scram Accumulators B 3.1.5 LCO The OPERABILITY of the control rod scram accumulators is required to ensure that adequate scram insertion capability exists when needed over the entire range of reactor pressures. The OPERABILITY of the scram accumulators is based on maintaining adequate accumulator pressure. APPLICABILITY ACTIONS PBAPS UNIT 3 In MODES I and 2, the scram function is required for mitigation of DBAs and transients, and therefore the scram accumulators must be OPERABLE to support the scram function. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requ1rements for control rod scram accumulator OPERABILITY during these cond.itions. Requirements for scram accumulators in MODE 5 are contained in LCO 3.9.5, "Control Rod The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod scram accumulator. This is acceptable since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable accumulator. Complying with the Required Actions may allow for continued operation and subsequent inoperable accumulators governed by subsequent Condition entry and application of associated Required Actions. A.I and A.2 With one control rod scram accumulator inoperable and the reactor steam dome pressure. 900 psig, the control rod may be declared "slow," since the control rod will still scram at the reactor operating pressure but may not satisfy the required scram times in Table 3.I.4-I. Required Action A.I is modified by a Note indicating that declaring the control rod "slow" only applies if the associated control scram time was within the limits of Table 3.I.4-I during the last scram time test. Otherwise, the control *rod would already be considered "slow" and the further degradation of scram performance with an inoperable accumulator could result in excessive scram times. In this event, the associated (continued} B 3.I-30 Revision No. 0 BASES ACTIONS I I PBAPS UNIT 3* A.I and A.2 {continued) Control. Rod Scram Accumulators B 3.1.5 control rod is declared inoperable (Required Action A.2) and LCO 3.1.3 is entered. This would result in requiring the affected control rod to be fully inserted and disarmed, thereby satisfyjng its intended function, in accordance with ACTIONS of LCO 3.1.3. The allowed Completion Time of 8 hours is reasonable, based on the large number of control rods available to provide the scram function and the ability of the affected control rod to scram only with reactor pressure at high reactor pressures. B.1. B.2.1. and B.2.2 With two or more control rod scram accumulators inoperable and reactor steam dome pressure 900 psig, adequate pressure must be supplied to the charging water header. With inadequate charging water pressure, all of the accumulators could become inoperable, resulting in a potentially severe degradation of the scram performance. Therefore, within 20 minutes from discovery of charging watei header pressure < 940 psig concurrent with . **Condition B, adequate header pressure must be restored. The allowed Completion Time of 20 minutes is. tG place a CRD pump into service to restore the charging water .header pressure, if required. This _Completion Time is based on the ability of the reactor pressure *alone to fully insert all control rods. -The control rod may be declared since the control rod will still scram using only-reactor pressure, but may not satisfy: the times-in. Table 3.1.4-1. Required Action B.2.1.is modified by. a*Note indicating that declaring _the control rod -"slow" only applies if the associated contro.l scram.time is with::in the limits of Table 3.1.4-1 -9uri ng the last scram ti me. test-. Otherwise, the contra l rod .. *would already be considered 11slow11 and the further *degradation . of-scram performance with* an inoperable

• could result in excessive scram In .the as,sociated control rod is declared inoperable (Required: Action 2. 2) and LCO 3 .1. 3 entered.
• This would ' * >. * * (continued) B 3. 1...-31 -.. Revis.ion No *. 2 BASES ACTIONS PBAPS UNIT 3 Control Rod Scram Accumulators B 3.1.5 B.l. B.2.1. and B.2.2 (continued) result in requiring the affected control rod to be fully inserted and disarmed, thereby satisfying its intended function in accordance with ACTIONS of LCO 3.1.3. The allowed Completion Time of 1 hour is reasonable, based on the ability of only the reactor pressure to scram the control rods and the low probability of a DBA or transient occurring while the affected accumulators are inoperable. C.l and*c.2 With one or more control rod scram accumulators inoperable and the re*actor steam dome pressure < 900 psig, the pressure supplied to the charging water header must be adequate to ensure that accumulators remain charged. With the reactor steam dome pressure < 900 psig, the function of the
• accumulators in providing the scram force becomes much more important since the scram function could *become severely degraded during a depressurization event or at low reactor pressures .. Therefore, immediately* upon discovery of charging water header pressure < 940 psig, concurrent *Condition C, all control rods associated with inoperable accumulators must be verified to be fully inserted. control rods with inoperable accumulators may fail to scram under these low pressure conditions. The associated control rods must also be declared inoperable within 1 hour. The .allowed Completion Time of 1 hour is reasonable for *Required Action C.2, considering the low probability of a DBA or transient occurring during the time that the accumulator is inoperable. The switch must .be immediately placed in the shutdown position. if either Required Action and associated Completioh with the loss of the CRD charging pump (Required Actions B.1 and C. l) cannot he met. This
• en'sures that all insertable control. rods are inserted and that the reactor is in a condition that does riot require the (continued) Revision' No. 2 BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES . *.' PBAPS UN IT 3 12......l (continued) Control Rod Scram Accumulators B 3.1.5 active function Ci .e., scram) of the control rods. This Required Action is modified by a Note stating that the action is not applicable if all control rods associated with the inoperable scram accumulators are fully inserted, since the function of the control rods has been performed. SR 3.1.5.1 SR 3.1.5.1 requires that the accumulator pressure be periodically checked to ensure adequate accumulator pressure exists to provide sufficient scram force. The primary indicator of accumulator OPERABILITY is the accumulato0 pressure .. A minimum accumulator pressure is specified, below which the capability of the accumulator to perform its intended function becomes and the accumulator is considered inoperable. The minimum accumulator pressure of 940 psig is well below the expected pressure of approximately 1450 psig (Ref. 1). Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that significant degradation in scram times does not occur. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 3.4.5.3 and Figure 3,4.10. 2. UFSAR, Appendix K, Section VI: 3. UFSAR, Chapter B .3. 33 Revision No. 87
• , .. ** ... . . '*, :f .* ** ..
• Rod Pattern Control B 3.1.6 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.6 Rod Pattern Control BASES BACKGROUND APPLICABLE SAFETY ANALYSES . ; . '_.-.*:.... PB(\PS'UNIT 3 Control rod patterns during startup conditions are controlled by the operator and the rod worth minimizer (RWM) * (LCO 3.3.2.1, "Control Rod Block so that only specified control rod sequences arid relative positions are allowed over the operating range of all control rods inserted to 10% RTP. The sequences 1 i mi t the potential . amount of reactivity addition that could o6cur in the of a Control Rod Drop Accident (CRDA). This Specification assures that the control rod patterni:; are consistent with the assumptions of the CRDA ana1yses of References 1 and 2. ' ' ' ' The analytical methods and assumptions used in evaluating the CRDA are summarized in References 1 and 2. CRDA analyses assume that the reactor operator follows prescribed . withdrawal sequences. These sequences define the potenti_al. initial conditions for the CRDA analysis. The RWM ( LCO 3. 3. 2. 1 ) provj des backup to operator cont rci 1 .. of . the
• withdrawal sequences to ensure that the initial conditions .of the _CRDA analysis are not Prevention or miti.gati on -pf positive reactivity insertion is necessary to limit the energy,deposition in the *fuel:, *thereby significant fuel damage which could result in the of radioactivity. Since the . Jai 1 ure consequences for. U02 have beeri shoWn *.to* be . . *. i nsigni fi cant below fuel 'energy depositions of 300 cal/gin (Ref, 3), the fuel. damage 280:cal/gm ** margin of safety from significant core damage which would. result i ri r'el ease of radiciaCti vity (Ref. 5) ,
• Generic*.*. *evaluations (Re.fs*;.1 and *6)of a de.sign basis CRDA (i.e., a CRDA resulting +n a peak fuel deposition o-f . .*.* .. ***** . 280 cal/gm) have *shown that if the* peak fuel enthalpy** remains below 280 .cal /gin, then the maximum reactor pr-essure. ' wi 11 be less than the re'qui red _ASME Code limits . (Ref. 7) . and the calculated o.ffsite doses will be well within the . limits (Ref: 5). * *(continued)** B: 3. -3.4 No. 76 . I I I . I I BASES APPLICABLE SAFETY ANALYSES (continued) PBAPS UN IT 3
• Rod Pattern Control B 3.1.6 Control rod patterns analyzed in Reference 1 follow the analyzed rod position sequence. The analyzed rod position sequence is applicable from the condition of all control rods fully inserted to 10% RTP (Ref. 2). For the analyzed rod position sequence, the control rods are required to be moved in groups, with all control rods assigned to a specific group required to be. within specified banked positions. The banked positions are established to minimize the maximum incremental control rod worth without being overly restrictive during normal plant operation. Generic analysis of the analyzed rod position sequence (Ref. 1) has demonstrated that the 280 cal/gm fuel damage limit will not be violated during a CRDA while following the analyzed rod position sequence mode of operation. The generic analyzed rod position sequence analysis (Ref. 8) also evaluates the effect of fully inserted, inoperable control rods not in compliance with the sequence, to allow a limited number Ci .e., eight) and distribution of fully inserted, inoperable control rods. When performing a shutdown of the plant, an optional rod position sequence (Ref. 91 may be used provided that all withdrawn control rods have been confirmed to be coupled. The rods may be inserted without the need to stop at intermediate positions since the possibility of a CRDA is eliminated by the confirmation that withdrawn control rods are coupled. When using the (Ref. 9) control rod sequence for shutdown, the RWM may be reprogrammed to enforce the requirements of the improved control rod insertion process, or may be bypassed and the analyzed rod position sequence implemented under LCD 3.3.2.1, Condition D controls. ,In order to use the Reference 9 shutdown process, an extra check is required in order to consider .a control rod to be "confirmed" to be coupled. This extra check ensures that no single operator error can result in an incorrect coupling check. For purposes of this shutdown process, the method for confirming that control rods are coupled varies depending on the position of the control rod in the core. Detail on this coupling confirmation requirement are provided in Reference 9. If the requirements for use of the control rod insertion process contained in Reference 9 are followed, the plant is considered in compliance with the rod position sequence as required by LCO 3.1.6. Rod pattern control satisfies Criterion 3 of the NRC Policy Statement. (continued) B 3.1-35 Revision No. 119 BASES (continued) Rod Pattern Control B 3.1.6 LCD Compliance with the prescribed control rod. sequences minimizes the potential consequences of a CRDA by limiting the initial conditions to those consistent with the analyzed rod position sequence. This LCD only applies to OPERABLE control rods. For inoperable control rods required.to be inserted, separate requirements are specified in LCD 3.1.3, "Control Rod OPERABILITY," consistent with the allowances for inoperable control rods in the analyzed rod position sequence. APPLICABILITY PBAPS UN IT 3 In MODES 1 and 2, when THERMAL POWER is 10% RTP, the CRDA is a Design Basis Accident and, therefore, compliance with the assumptions of the safety analysis is required. When THERMAL POWER is> 10% RTP, there is no credible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Ref. 2). In MODES 3, 4, 5, since the reactor is shut down and only a control rod can be withdrawn from a core cell containing fuel assemblies, adequate SOM ensures that the consequences of a CRDA are acceptable, since the reactor will remain subtritical with a single control rod withdrawn. (continued) B 3*. l-35a Revision No. 64 Rod Pattern Control B 3.1.6 BASES (continued) ACTIONS A.l and A.2 PBAPS UN 1T 3 With one or more OPERABLE control rods not in compliance with the analyzed rod position sequence, actions may be taken to either correct the control rod pattern or declare the associated control rods inoperable within 8 Noncompliance with the prescribed sequence may be the result of "double notching," drifting from a control rod drive cooling *water transient, leaking scram valves, or a power reduction 10% RTP before establishing the correct control rod pattern.* The number of OPERABLE control rods not in compliance with the prescribed sequence is limited to eight, to prevent the operator from attempting to correct a control .rod pattern that significantly deviates from the prescribed sequence. When the control rod pattern is not in compliance with the sequence, all control rod movement must be stopped except for moves needed to correct the rod pattern, or scram if warranted. Required Action A.1 is modified by a Note which allows the RWM to be bypassed to allow the affected control rods to be to their correct LCO 3.3.2.1 requires verification of control rod movement by a second licensed operator or a qualified member of the technical staff ( i . e., trained in accordance with an approved training program). This ensures that the control rods wi 11 be moved to the ccirrect position. A control rod not in compliance with the prescribed is .not considered inoperable except as required by Requfred Action A.2. The allowed Completion Time of 8 hours ,is reasonable, considering the restrictions on the.number of allowed out of sequence
• and the low probability of a CRDA occurring during time the contrbl rrids are out of sequence. B.1 and B.2 *. If nine--cir more OPERABLE .control rods a re not in compliance wi'th -the a'nalyzed rod *position sequence, the. control rod pattern significantly from the prescribed Control rod withdrciwal should to p rev e n t
• t he pot en ti a 1
• f o r f u rt h e r d e v i a ti on from t he prescribed sequence. Control_ rod insertion fo correct
• coritr_ol rods withdrawn beyond their allowed position is allowed.-s*ince; in general' insertion of control rods has continued B 3.1-36. Revision No. 64 J BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES PBl\PS UN IT 3 B.l and B.2 (continued) Rod Pattern Control B 3.1.6 less impact on control rod worth than withdrawals have. Required Action B.l is modified by a Note which allows the RWM to be bypassed to allow the affected control rods to be returned to their correct position. LCD 3.3.2.i requires verification of control rod movement by a second licensed operator or a qualified member of the technical staff. When nine or more OPERABLE control rods are not in compliance with the analyzed rod position sequence, the reactor mode switch must be placed in the shutdown position within 1 hour. With the mode switch in shutdown, the reactor is shut down, and as such, does not meet the applicability requirements of this LCD. The allowed Completion Time of 1 hour reasonable to allow insertion of control. rods restore compliante, and is appropriate relative to low probability of a CRDA occurring with the cont ro l rod s o u t of s e q u en c e . SR 3.1.6.1 The control rod pattern is verified to be in compliance with the analyzed rod position sequence to ensure the assumptions of the CRDA met. The Surveillance Frequency is controlled under the Surveillance Control Program. The RWM provides control rod to enforce the required sequence is tci OPERABLE when operating at 10% RTP. 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision. 2. Letter (BWROG-8644) from T. Pickens (BWROG) to G. C. Lainas (NRC), "Amendment 17 to General Electric Licensing Topical Report 3. UFSAR, Section 14.6.2.3. 4. Deleted. 5 . 10 CFR 50:67 .. continued , Revis1on No. 87 BASES REFERENCES (continued) PBAPS UNIT 3 6. Rod Pattern Control B 3.1.6 NED0-21778-A, "Transient *Pressure Rises Affected Fracture Toughness Requirements for Boiling Water Reactors," December 1978. 7. ASME, Boiler and Pressure Vessel Code. 8. NED0-21231, "Banked Position Withdrawal Sequence," January 1977. 9. NED0-33091-A, "Improved BPWS Control Ro(j Insertion Process," Revision 2, July 2004. B 3.1-38
• Revision Nb:.62 SLC System 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BASES BACKGROUND PBAPS UN IT 3 The SLC System is designed to provide the capability of the reactor, at any time in a fuel cycle, from full power and minimum control rod inventory (which is at the peak of the xenon transient) to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement. The SLC System satisfies the requirements of 10 CFR 50.62 (Ref. 1) on anticipated transient without scram using highly enriched boron. Using highly enriched boron in the SLC System increases the rate of Boron-10 injection and functions to shutdown the reactor core faster. This limits the heat generated that is transferred to the suppression pool during an ATWS event. Limiting the heat transferred to the suppression pool maintains the pool below design limits, which ensures adequate net positive suction head (NPSH) is available for the emergency core cooling system (ECCS) pumps without credit for containment accident pressure. The SLC System is also used to maintain suppression pool pH at or above 7 following a loss of coolant accident (LOCA) involving significant fission product releases. Maintaining suppression pool pH levels at or above 7 following an accident ensures that sufficient iodine will be retained in the suppression-pool water. Reference 1 requires a SLC System with a minimum flow capacity and boron content equivalent in control capacity to 86 gpm of 13 weight percent sodium pentaborate solution. Natural sodium pentaborate solution is 19.8% atom Boron-10. Therefore, the system parameters of concern, boron concentration (C), SLC pump flow rate (Q), and Boron-10 . enrichment (E), may be expressed as a mulliple of ratios. The expression is as follows: c Q E x x 13% weight 86 gpm 19.8% atom If the product of this expression 1, then the SLC System satisfies the criteria of Reference 1. As such, the product of this expression at the minimum acceptance * (continued-) B 3.1-39 Revision No. 119 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES. . *. ,: SLC System B 3.1.7 criteria for the surveillances of concentration, flow rate and boron enrichment is> 1.69, which reflects that the SLC System exceeds the criteria of Reference 1. The SLC System consists of a boron solution storage tank, two positive displacement pumps, two explosive valves that are provided in parallel for redundancy, and associated piping and valves used to transfer borated water from the storage tank to the reactor pressure vessel CRPV). The borated solution is near the bottom of the core shroud, where it then mixes with the cooling water rising through the core. A smaller tank containing demineralized water is provided for testing purposes. The SLC System is initiated from the main control room; as directed by the emergency operating procedures, if the operator believes the reactor cannot be shut down, or kept* shut down, with the control rods. The SLC System is used in the event that enough control rods cannot be inserted to accomplish shutdown and cooldown in the normal manner. The SLC System injects borated water into the reictor core to add negative reactivity to compensate for all-of_the various reactivity effects that could occur during plant operations. To meet this objective, it is necessary to a quantity of boron, which produces a concentr-ati on of 660 ppm of natural boron, in the reactor cool ant *at 68°f. To all ow for potenti.al -leakage and imperfect mixing in the reactor system, a.n additional amount of boron"'equal to 25% of the amount cited above. is added as a minimum (Ref. 2). The minimum l_evel of_ sodium pentaborate in._solution in the SLC tank Ci 52%) and the limits in Figure 3;1.7-1 are ialculated such that required is achieved, with additional inar_gin .associated with using_ highly ehr.i ched -boron to-increase the r-ate of Boron-10 *if1jection, accountlng for 'dilution in th-e RPV wit,h normal water leVe1 and 1ncludlng th*e water volume in .the residual 'heat removal shutdown cooling piping and in-the recirculation loop piping. This quantitj of borated solution is the amount that is above the pump suction shutoff-level in the boron solution storage tank. No credit _ for the Of tank volume that cannot be injected*.> The.maximum allowable concentr_ation of sodium _ -** p.entaborate depictedin Figure 3.1.7-1 has been established to. e_nsure that the solution, saturation temperature does not exceed 43°F.
• Using highly enriched boron Ci :e,., SR 3 . l . 7 '. 16 *; 9 2 . 0 % ) i n t h e S LC Sy s t e tn. i n c re a s es th e -r a t e o f (continued) B_3.l-40 Revision No. 119 BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICAB.ILITY PBAPS UN IT-3 SLC System B 3.1.7 Boron-10 injection and functions to shutdown the reactor core faster. This limits the heat generated that is transferred to the suppression pool during an ATWS event. Limiting the heat transferred to the suppression pool maintains the pool below design limits, which ensures adequate NPSH is available for the ECCS pumps without credit for containment accident pressure. The sodium pentaborate solution in the SLC System is also used, post-LOCA, to maintain suppression pool pH at or 7. The system parameters used in the calculation are the minimum allowable volume, Boron-10 enrichment, and concentration of sodium pentaborate in solution in the SLC tank. These minimum allowable values are required to maintain suppression pool pH 7.0 post-LOCA. This prevents radioactive iodine from fe-evolving, which limits the iodine release to the plant environs and minimizes the radiological consequences to comply with 10 CFR 50.67 limits (Ref. 3). The SLC System satisfies Criteria 3 and 4 of the NRC Policy Statement. The OPERABILITY of the SLC System provides backup capability f6f reactivity control independent of normal reactivity. control provisions provided by the control rods. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank and the availability of a f)dw path to the RPV, *including the OPERABILITY of the pumps and valves. Two SLC subsystems are fequired to be OPERABLE; each contains an OPERABLE pump, an explosive valve,* pipingi valves, and instruments and controls to en s u r e a n O P ERA B L E
• fl ow pa t h . In MODES 1 and*2, shutdown capability is requjred. In MODES li-2, *and 3, SLC System capability is required in or*de.r to-ni.aintain post OBA LOCA suppressiOn* pool pH. _In 3*-and:4, control rods to, be withdrawn si.nce. the reactor m6de is in shutdbwn and a control . . rod block is applied; This provides*adequate controls to _ensure *that the reactor remains subcri.tical .. In MODE 5,
• onJy a single contrbl rod can.be withdfawn* from a core cell containing* fuel assemblies .. '* Demonstration of adequate SOM .. . (LCO 3:ld, "SHUTDOWN *MARGIN (SOM)") ensures that the reactor wfll not* become criti-tal.
• Therefore, the SLC System. is ndt required be OPERABLE'. when only a single coritrol rod can be withdrawn. *
• continued Revision No. 11.9 J BASES APPLICABILITY (continued) ACTIONS
• PBAPS UN IT 3 SLC System B 3.1.7 In MODES 1, 2, and 3, the SLC System must be OPERABLE to en,sure that offsite doses remain within 10 .CRF 50.67 (Ref. 3) limits following a LOCA involving significant fission product releases. The SLC System is designed to maintain suppression pool pH at or above 7 following a LOCA significant fission product releases to ensure that iodine will be retained in the suppression pool water. A.l and A.2 If the boron solution concentration is> 9.82% weight but the concentration and temperature of boron in solution and pump suction piping temperature are within the limits of Figure 3.1.7-1, operation is permitted for a limited period since the SLC subsystems are capable of performing the intended function. It is not necessary under conditions to declare both SLC subsystems inoperable since the SLC subsystems are capable of performing their intended function. The concentration and temperature of boron in solution and pump suction piping temperature must be verified to be within the limits of Figure 3.1.7-1 within 8 hours and once per 12 hours thereafter (Required Action A.1). The temperature versus concentration curve of Figure 3.1.7-1, for concentrations> 9.82% weight, ensures a. 10°F margin will be maintained above the saturation temperature. This ensures that b6ron does not pretipitate out of solution in the storage tank or in the pump suction piping due to boron solution (below the saturation temperature for the given The Completion
• Time for performing Required Action A.l is considered acceptable given the low probability of a Design Basis Acc{dent (OBA) transient occurring concurrent with the failure of the control rods to shut down the reactor and operating experience which has shown there are relatively slow variations in the measured parameters of concehtration and temperature over these time *periods. Continued operation is only permitted for 72 hours before boron solution concentration must be restored 9.82% weight. Taking into cbnsideration that the SLC System design capability still exists for vessel injection under these conditions and the low probability of the temperature and concentration limits of Figure 3.1.7-1 not being met, the allowed Time of 72 hours is acceptable and adequate tfme to restore conceritration to within limits. *
• continued B 3.1-.42 Revision N6.*119 _J

! '. BASES ACTIONS (continued) PBAPS UNIT 3 SLC System B 3.1.7 If one SLC subsystem is inoperable for reasons other than Condition A, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this condition, the remaining OPERABLE subsystem is adequate to perform the shutdown function. However, the overall reliability is reduced because a single failure in the remaining OPERABLE subsystem could result in the loss of SLC System shutdown capability. The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the intended SLC System function and the low probability of a OBA or severe transient occurring concurrent with the failure of the Control Rod Drive (CRD) System to shut down the plant. If both SLC subsystems are inoperable for reasons other than Condition A, at least.one subsystem must be restored to OPERABLE status within 8 The allowed Completion Time* of 8 hours is considered acceptable given the low probability of a OBA or transient occurring concurrent with the failure of the control rods to shut down the reactor. D.l and D.2 If any Required Action and*associated Completion Time is not met, .the plant brought to a MODE in which the LCD. does not apply .. To achieve this status, the plant must be brought to MODE 3. within 12 hours and MODE 4 within 36 hours .. The allowed Completion Times are reasonable, based on* operating experience, to reach the required from full power conditions in ati orderly manner ahd without challenging plant systems. (continued). B 3. F43 Re vision No.* H9 BASES (continued) S U RV E I L LAN C E REQUIREMENTS PBAPS UN IT 3 SR 3.1.7:1. SR 3.1.7.2. and SR 3.1.7.3 SLC System B 3.1.7 SR 3.1.7.1 through SR 3.1.7.3 verify certain characteristics of the SLC System (e.g., the level and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure that the proper borated solution level and temperature, including the temperature of the pump suction piping, are maintained. Maintaining a minimum specified borated solution temperature is important in ensuring that the boron remains in solution and does not precipitate out in the storage tank or in the pump suction piping. The temperature limit specified in SR 3.1.7.2 and SR 3.1.7.3 and the maximum sodium pentaborate concentration specified in Figure 3.1.7-1 ensures that a 10°F margin will be maintained above the saturation temperature. Control room alarms for low SLC storage tank temperature and low SLC System piping temperature are available and are set at 55°F. As such, SR 3.1.7.2 and SR 3.1.7.3 may be satisfied by verifying the absence of low temperature alarms for the SLC storage tank and SLC System piping. The Surveillance Frequency is controlled under the Survei 11 ance. Frequency Control Program. SR and SR 3.1.7.6 SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.1.7.6 verifies that each valve in the system is in its correct position, but does not apply to the squib (i.e., explosive) valves. Verifying the correct alignment for manual power operated valves in the SLC System flow path provides assurance that the proper flow paths will exist for system operation. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position from the control room, or locally by a dedicated operator at the va1*ve control. This is acceptable since the SLC System is a manually initiated system. This Surveillance also does not apply to valves that are locked, sealed, or otherwise secured in position since they are verified to be in the correct position prior to locking, sealing, or securing. This verification of valve alignment continued B 3.1-44 Revision No. 119 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 SR 3.1.7.4 and *sR 3.1.7.6 (continued) SLC System B 3.1.7 does not require any testing or valve manipulation; rather, it *involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Survei 11 ance Fr.equency is controlled under the Surveillance Frequency Control Program. SR 3.1.7.5 This Surveillance requires examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper contentration of boron exists in the storage tank. Having the proper concentration of boron in the storage tank ensures the SLC subsystems will perform their intended function of injecting no less than the minimum quantity of Boron-lQ and amount of sodium pentaborate required by ATWS analyses. The SLC subsystems function to quickly shutdown the reactor in the event of an ATWS. *This limits the heat generated is transferred to the suppressibn pool during an ATWS event. Limiting the heat transferred to*the suppression pool maintains the pool below d.esign limits, which ensures adequate NPSH is available for the ECCS pumps without credit fo*r containment accident pressure: The SLC subsystems also function to maintain sup.pression pool pH;;::: 7:0 under conditions. *SR must be anytime boron or water is added to the tank soiution to that the boron solution concentration is;;::: 8.32% we1ght and:-::; 9.82% weight. I SR*.3.1.7.5 must also be performecJ.'anytime* the temperature is . limits to that no'significant boron occurred .. The Surveillance Frequency is control l under. the.Surveillance Frequency Control Program. SR. 3.l..-7.7 Deleted .. *-'._' SR 3,1.7.8. Demon strati that each SL_C System pump develops a flow rate* . A9 .1 gpm at a discharge 1275 psi g ensures that.*. pump has hot tjegraded below values the CYGle. This minimum pump.flow rate requirement* ensures that'* when combi ned>with the sodium pentaborate ( cont i n Lied ) *g 3.1-45 . Revision No, *119 I BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 -SR 3.1.7.8 (continued) SLC System B 3.1.7 solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the reactivity effects encountered durinq power reduction, cooldown of the moderator, and xenon decay. The rate of negative reactivity insertion is increased by using highly enriched boron in the SLC System solutioh that increases the rate of Boron-10 injection and functions to shutdown the reactor core faster. This limits the heat generated that is transferred to the suppression pool during an ATWS e0ent. Limiting the heat transferred to the suppression pool maintains the pool below design limits, which ensures adequate NPSH is available for the ECCS pumps without credit for accident pressure. This test confirms one 6n the pump design curve and is indicative of overall_ performance. Such inserVice confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal-performance; The Frequency of this Surveillance is in accordance with the Inserv1ce Testing Program. SR-3.1.7.9 This ensures that there is a functioning flow path the boron solution storage tank to the RPV, including the firing of -an explosive valve.' The replacement charge -for the explosive valve shall be from the same manufactured batch as the one fired or another batch that has been certified by having one of that batch succes.sful ly fired. The Surve_i 11 ance may .be perfornied in separate steps to prevent .injecting boron into the RPV. An method for Verifying-flow from ttie pump to the RPV is to pump demi nerai i zed-water from a-test tank th('ough one SLC subsystem into _the RPV. The Surveillance Frequency is controll.ed the Frequency Control-P:rogram. (continued) B 3_. L46 Revision Nci. 119 BASES . SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UN IT* 3 SR 3.1.7.10 SLC System B 3.1.7 Enriched sodium pentaborate solution is made by m1.x1 ng granular, enriched sodium pentaborate with water. Isotopic tests on the granular sodium pentaborate to verify the actual B-10 enrichment must be performed prior to addition to the SLC tank in order to ensure that the proper B-10 atom percentage is being used. The tests may use vendor certification documents. 1. 10 CFR 50.62. 2: UFSAR, Section 3.8.4. 3. 10 CFR 50.67. ** Re-vlsi on No, 132 .. ,, ,, ** 1 '-., . : ' . I. --SDV Vent and Drain B 3.1.8 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1 .8 Scram Discharge Volume (SDV) Vent: and Drain Valves BASES BACKGROUND APPLICAB.LE . SAFETY ANALYSES. .,_,. ,,*** -_,-.* The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that sufficient volume is available at all times to allow a complete scram. During a scram, the SDV vent. and drain valves close to contain reactor As discussed in Reference 1,*the SDV vent and drain valves need not be considered primary containment isolation valves (PCIVs) for the Scram Discharge System. (However, at PBAPS, these valves are considered PCIVs.) The SDV is*a_volume of header. piping that connects to each hydraulic control unit (HCU) and drains into an instrument volume. There are two SDVs. (headers) and a common instrument volume that receives all of the tontrol rod_ drive (CRD) discharges. The volume is connected to a common. drain. line with two valves in series. Each header is connected to a common vent line. with two valves in series for a total of four vent valves. The header piping.is sized to receive and contain all the water discharged by the CRDs during a scram. The design.and *functions of the SDV are described in Reference 2. -,'". The Design Basis Accident and transieht analyses assume all of the control rotjs are capable of The acceptance criteria for the SDV verit .and drai.n valves. are .

• that they operate automatically to close during scram to limif the amount of reactor coolant discharged so that
• core cooling is maintained and offsite doses remain .within foe 1 i mi ts of to CFR 50. 67 (Ref: 3f Isolation *of the SDV can also be accomplished by*manuai * *closure of the SDV: val yes. Addi ti onalJ y, the di schargE:) of .. coolant the *spv c'an be terminated by scram :reset or closure of. the HCU manual i sol ati ori valves. . For a . * . * . .** bounding 1 eakage case, the offsi.te doses are well wi thi.n the limits of 10 CFR 50 67 (Ref. 3) ; and adequate core tooling * *... is maintained (Ref. 1) . *.*.The SDV vent* and drain valves all ow* drainage of the SDV duringnormalplant operation. to erisu re that the SDV h'as suf f i ci eht capacity to contain.* . the reactor coolant discharge during a full core scram. _To* ** ... *ensure th:i s capacity, a reactor scram * 'cLCO .. 1,' '!Reactor Protection System (RPS) *.Instrumentation") 1s ir)iti.ated if the SDV water leve'l iri*t'he . ::**:.: (continued) PBf.PS UNIT 3 B. 3 .. 1-48 " Revision No. 76 . . ' . . -

BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABILITY ACTIONS PBAPS UN IT 3 SDV Vent and Drain Valves B 3.1.8 instrument volume exceeds a specified setpoint. The setpoint is chosen so that all control rods are inserted before the SDV has insufficient volume to accept a full scram. SDV vent and drain valves satisfy Criterion 3 of the NRC Policy Statement. The OPERABILITY of all SDV vent and drain valves ensures that the SDV vent and drain vcilves will close d0ring a scram to contain reactor water discharged to the SDV piping. Since the vent and drain lines are provided with two valves in series, the single failure of one valve in the open position will not impair the isolation function of the system. Additionally, the valves are required to be opened following scram. reset to ensure that a path is available for the SDV piping to drain freely at other times. In MODES 1 and 2, scram be required; therefore, the SDV vent and drain valves must be OPERABLE. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate controls to ensure that only a single control rod can be withdrawn. Also, during MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Therefore, the SDV vent and drain valves are not required to be OPERABLE in these MODES since the reactor is subcritical and only one rod may be withdrawn and subject to scram. The ACTIONS Table is modified by Notes indicating that a separate Condition entry is allowed for each SDV vent and drain line. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable SDV line. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SDV lines are governed by subsequent Condition entry and application of associated Required Actions. When a line is isolated, the potential for an inadvertent scram due to high SDV level is increased. During these periods, the line may be unisolated under administrative control. This allows any accumulated water in the line to be drained, to preclude a reactor scram on SDV high level. This is acceptable since the administrative controls ensure the.valve can be closed quickly, by a dedicated operator, if a scram occurs with the valve open.

• B 3.1-49 Revision No. 58 BASES ACTIONS (continued) PBAPS UN IT 3 SDV Vent and Drain Valves B 3.1.8 When one SDV vent or drain valve is inoperable in one or more lines, the associated line must be isolated to contain the reactor coolant during a scram. The 7 day Completion Time is reasonable, given the level of redundancy in the lines and the low probability of a scram occurring during the time the valves are inoperable and the line is not isolated. The SDV is still isolable since the redundant valve in the affected line is OPERABLE. During these periods, the single failure criterion may not be and a higher risk exists to aliow reactor water out of the primary system during a scram. If both valves in a line are inoperable, the line must be isolated to contain .the reactor coolant during a scram. The 8.hour Completion Time to isolate the line is based on the low probability of a scram occurring the line is. not isolated and unlikelihood of s i griifi-cant CRD seal leakage:-. C.l -' If any Required Action Time is.not met, the-pl ant must be brought to a MO.DE in which the .LCD does n6ta_p_ply._.To achieve-thissta_tus,_ the plant must be brought to. at least MODE 3 withi*n 12 hours. The allowed Completion Time of l2 hours is reasonable, based on . operating experience,.to reach MODE 3*from full power in *orderly manner and without challenging plant systems.. * *. -. '. (continued) B 3.1-50
• Re v i s i on N o . 58. i.

BASES (continued) SURVEILLANCE REQUIREMENTS . PBAPS UNIT 3 SR 3.1.8.l SDV Vent and Drain Valves B 3.1.8 During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2 or SR 3.3.1.1.9 for Function 13, Manual Scram, of Table 3.3.1.1-1) t6 a1*1ow for drainage of the SDV piping. Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended functions during normal operation. This SR does not reqOire any testing or valve manipulation; rather, it involves verification that the valves are in the correct position. The Surveillance Frequency is controlled under the Frequency* control Program. SR 3.1.8.2 During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping. Cycling each valve through complete range of motion and open) ensures that the valve will function properly during a scram. The Surveillance Frequency is conirolled under the Surveillance Control Program. SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SOY vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain is verified. The closure time of 15 after receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis (Ref. 2).

• The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.l and the scram time testing of-*control rods in LCO 3.1.3 overlap this Surveillance to provide complete testing.of the assumed safety function: *-.The Su_rvei ll ance-Frequency is control led_ under-the Surveilla-nce Frequency-Control Pro*gram. (continued) B 3.F51 Revi s_i.on-No. 87 BASES (continued) REFERENCES
• PBAPS UN IT 3 1. SDV Vent and Drain Valves B 3.1.8 NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping," August 1981. 2. UFSAR, Sections 3.4.5.3.1 and 7.2.3.6. 3. 10 CFR 50-67. B.3.1-52 Revtsion No. 87 APLHGR B 3.2.1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE CAPLHGR) BASES BACKGROUND APP LI CAB LE SAFETY ANALYSES PBAPS UN IT 3 The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any axial location. Limits on the APLHGR are specified to ensure that the peak cladding temperature CPCT) during the postulated design basis loss of coolant accident (LOCA) does not exceed the limits specified in 10 CFR 50.46. The analytical methods and assumptions used in evaluating Design Basis Accidents CDBAs) that determine the APLHGR limits are presented in References 1, 2, 3, 4, S, and 7. (continued) Re vision No. 50 *.: I ___J BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS.UNIT 3 APLHGR B 3.2.1 LOCA analyses are performed to ensure that the APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR The analysis is performed using calculationa1 models that are consistent with the requirements of 10 CFR 50, Appendix K. A complete discussion of the analysis code is provided in Reference 11. The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution *within an A conservative multiplier is applied to the LHGR assumed in the LOCA analysis to account for the uncertainty associated with the measurement of the APLHGR. For single recirculation loop operation, a conservative multiplier is applied fo the APLHGR as specified in the COLR (Ref. 12). This is due to the conservative analysis assumption of an earlier departure from nucleate boi!ing with one recirculation loop available, resulting in a more severe cladding heatup during a LOCA. Power-dependent and flow-dependent APLHGR adjustment factors may also be provided per Reference 1 to ensure that fuel design limits are not exceeded due to the occurrence of a postulated transient event during operation at off-rated *(less than 100%) reactor power or core flow concitions. These adjustment are applied, if required, per the COLR and decrease the allowable APLHGR value. The APLHGR satisfies Criterion 2 of the NRC Policy Statement. The APLHGR limits specified in the COLR are the result of the fuel design and OBA analyses. The limits are developed as a function of exposure and are applied per the COLR. Revision No. 50 BASES LCD (continued) APPLICABILITY ACTIONS PBAPS UNIT 3 APLHGR B 3.2.1 With only one recirculation loop in operation, in conformance with the requirements of LCD 3.4.1, "Recirculation Loops Operating," the limit is determined by multiplying the exposure_ dependent APLHGR limit by a conservative factor. The APLHGR limits are primarily derived from LOCA analyses that are assumed to occur at high power levels. Design calculations (Ref. 6) and operating experience have shown that as pciwer is reduced, the margin to the required APLHGR limits increases. This trend continues down to the power range of 5% to 15% RTP when entry into MODE 2 occurs. When in MODE 2, the w{de range neutron monitor period-short scram function provides prompt scram initiation during any significant transient, thereby effectively removing any APLHGR limit compliance concern in MODE 2. Therefore, at THERMAL POWER levels< 23% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCD is not required. If any APLHGR exceeds the required limits, an assumption an initial of the OBA ahalyses may be met. prompt action should be taken to restore to within the required limits such that the pi ant within analyzed and within design limits of* the fuel rods. The 2 ho.ur Completion Ti me is s u ff i c i en t t o re s to r e t he A P L HG R Cs) t o w it h i n it s l i m i t s a n d acceptable based 6n the 16w probability Df OBA occurring with APLHGR.out of specification. If the APlHGR be restored to within its fhe* Time, the plant be brought to a MODE 'or other specified* condition in which the LCO does ncit apply .... To achieve this status, THERMAL POWER" mus:t be reducecj. to < RTP within 4 hours. The I continued B 3.2-3 Revision No. 119 BASES ACTIONS S U RV EI L LAN C E REQUIREMENTS REFERENCES . PBAPS UNLT 3 .B..J. (continued) APLHGR B 3.2.1 allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly manner and without challenging plant systems. SR 3.2.1.1 APLHGRs are required to be initially.calculated within 12 hours after THERMAL POWER 23% RTP and then periodically thereafter. They are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL 23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NED0-24011-P-A, Electric Application for Reactor Fuel," la.test approved reyision. UFSAR, Chapter 3. 3. Chapter 6. 4. UfSAR, Chapter 14. 5. Bottom Atomic Station Uriits 2 and 3, Single Loop Operation," May 1980. 6. NEDC-32162P, "Maximum Extended Load Line Limit and ARTS Improvement Analyses for Peach Bottom Atomic Power_ Station Uriits 2 and 3,'i Revision 2, March 1995. 7. * . NEDC--33566P,. "Safety Analysis Rep.ort for. Exel on Peach Bottom 'Atomic Power Station, Uni ts 2 and 3, Constant Pressure Power Uprate," Revision* 0. 8. Deleted 9-. NfD0-30130-A, -"Steady State* Nuclear Methods," . April: 1985. continued .B 3.2-4. Revision No. 119 .*.
• MCPR B 3.2.2 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR) BASES BACKGROUND MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power. The MCPR Safety limit (SL) is set such that 99.9% of the fuel rods avoid boiling transition if the limit is not violated (refer to the Bases for SL 2.1.1.2). The operating limit MCPR is established to ensure that no fuel damage results during abno.rmal operational transients. Although fuel damage does not necessarily occur if a fuel rod actually experienced boiling transition (Ref. 1), the critical power at which boiling transition is calculated to otcur has been adopted as a fuel design criterion. The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs. Based on these experimental data, correlations have been developed to predict cri ti ca 1 bundle power (i.e., the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling). Because plant operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur. APPLICABL.E The analytical methods and assumptions used in evaluating SAFETY-ANALYSES the abnormal operational transients to establish the operating limit MCPR are presented in References 2, 3, 4, 5, 6, 8, and 9. To ensure that the MCPR SL iS not exceeded during any trans*; ent event that *occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR). The types of transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest change .. in CPR (&PR). When the largest &PR (corrected for analytical uncertainties) is added to the MCPR SL, the required operating limit MCPR is obtained. (continued) . PBAPS* UNIT 3 B 3.2.,..6.
• Revision No. o BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABILITY PBAPS UNIT .3 MCPR B 3.2.2 The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power state (MCPRf and MCPRP, respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Refs. 6, 7, 8, and 9). Flow dependent MCPR limits are determined by steady state thermal hydraulic methods with key physics response inputs benchmarked using the three dimensional BWR simulator code (Ref. 10) to analyze slow flow runout transients. The flow dependent operating limit, MCPRf, is evaluated based on a single recirculation pump flow runout event (Ref. Power dependent MCPR limits (MCPRP) are determined by the codes used to evaluate transients as described in Reference 2. Due to the sensitiviti of the transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast scrams are bypassed, high and low flow MCPRP operating limits are provided for operating between 23% RTP and the previously mentioned bypass power level. The MCPR satisfies Criterion 2 of the NRC Policy Statement. The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (OBA) and transient analysis. The operating limit MCPR.is determined by the larger of the MCPRt and MCPRP limits. The MCPR operating are primarily derived from transient that are assumed to 6ccur at high power 1 evel s. Bel ow 23% RTP, the reactor is operating at a minimum pump speed' and-the void ratio is small. Surveillanc_e of thermal limits below 23% RTP is due to the large inherent margin that I ensures that the MCPR SL is not exceeded even if a limiting transient occurs: Statistical analyses indicate that nominal value of the initial MCPR expected at 23% RTP is > 3.5. Studies of the of limiting transient behavior have been performed over the range of power and continued B 3.2-7 Revisio*n No. 119 BASES APPLICABILITY (continued) ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN IT. 3 MCPR B 3.2.2 flow conditions. These studies encompass the range of key . actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as power is reduced to 23% RTP. This trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs. When in MODE 2, the wide range neutron monitor period-short function provides rapid scram initiation for any significant power increase transient, which effectively eliminates any MCPR compliance concern. Therefore, at THERMAL POWER levels< 23% RTP, the reactor is operating with substantial margin to the MCPR limits and this .LCO is not required. If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met. Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour Completion Time is normally *sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probability of a transient or OBA occurring simultaneously with the MCPR out of specification. If the MCPR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to< 23% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly manner and without challenging plant systems. SR 3.2.2.1 The MCPR is required to be initially calculated within 12 hours after THERMAL POWER 23% RTP and periodically thereafter. It is compared to the specified limits continued B 3.2-8 Revision No. 119 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT 3 SR 3.2.2.1 (continued) MCPR B 3.2.2 in the COLR (Ref. 12) to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL 23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient analysis. SR 3.2.2.2 determines the value of'* which is a measure of the actual scram speed distribution compared with the assumed distribution. The MCPR operating limit is then determined based on an between the applicable limits for Option A (scram ti_mes of LCO 3.1.4',"Control Rod Scram Times") and Option B (realistic scram times) analyses. The parameter, must be determined once_ within 72 hours after each set of scram time tests required by SR 3.1.4.1, SR 3.1.4.2, and S.R 3 . 1 . 4 . 4 because the effect i v e scram speed di st r i but i on -may durihg the or maintenance that could affect scram times. The 72 -hou_r Completion Time is acceptable due t"o the relatively minor changes" in' expected during* the fuel cycle._ --1. NU RE G -0 5 6 2 , J u n e; 19 7 9 . 2. _ -NED0-24011-P-A; "Gene_ral Electric Standard Application_ -for Reactor -Fuel,"-* latest approved revi sfon. -.-. . 3._ -UFSAR, C:ha-pter -3'. ,A>: UFSAR,--5. UFSAR, *Chapter.14. 6. NED0-2M29-l, "Peach _Bottom Atomic Power Station Units 2 and* 3, Single Loop-Operat_i on," May 1980. -cont i nUed B 3.2-9 Revision No. 119 BASES REFERENCES (continued) P.BAPS UN.IT 3 7. MCPR B 3.2.2 NEDC-32162P, "Maximum Extended Load Line Limit and ARTS Improvement Program Analyses for Peach Bottom Atomic Power Station Units 2 and 3," Revision 2, March 1995. 8. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 9. NEDC-32427P, "Peach Bottom Atomic Power Station Unit 3 Cycle 10 ARTS Thermal Limits Analyses," December 1994. 10. NED0-30130-A, "Steady State Nuclear Methods," April 1985. 11. NED0-24154,* "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors," October 1978. 12. ?each Bottom Unit 3 Core Operating Limits Report (COLR) . . * .. ,* B 3.2.:10 Revision No. 119 1: 1: LHGR B 3.2.3 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.3 LINEAR HEAT GENERATION RATE CLHGR) BASES BACKGROUND The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location. Limits on LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation, _including abnormal operational transients. Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials. Fuel design limits are specified to ensure that fuel system damage, fuel rod failure, or inability to cool the fuel does not occur during the anticipated operating conditions identified in Reference 1.
• APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the fuel system design are presented in References 1, 2, 3, 4, 5, 6, 7, 8, 9, and 12. The fuel assembly is designed to ensure (in conjunction with the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release. of radioactive materials in excess of the guidelines of 10 CFR, Parts 20, 50, and 100, as applicable. The PBAPS UN IT 3 . mechanisms that could cause fuel damage during operational . transients and that are considered in fuel evaluations are: a.* Rupture of the-fuel rod cladding caused by strain from the-relative expansion of the U02 pellet; and b, Severe overheating of the fuel rod cladding caused by inadequate cooling. A value of 1% plastic strain of the fuel cladding has been defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur (Ref. 10). Fuel design evaluations have been performed and demonstrate that the 1% fuel cladding plastic strain design limit is not during continuous operation with LHGRs up to the limit in the COLR. The analysis also continued B .3. 2-l l -. No. fOl BASES APPLICABLE SAFETY ANALYSES (continued) LCO AP PLI CAB I LITY ACTIONS PBAPS UN IT 3 LHGR B 3.2.3 includes allowances. for short term transient opera ti on above the operating limit to account for abnormal operational transients, plus an allowance for densification power spiking. Power-dependent and flow-dependent LHGR adjustment factors may also be provided per Reference 1 to ensure that fuel design limits are not exceeded due to the occurrence of a postulated transient event during operation at off-rated (less than 100%) reactor power or core flow conditions. These adjustment factors are applied, if required, per the COLR and decrease the allowable LHGR value. Additionally, for single recirculation loop operation, an LHGR multiplier may be provided per Reference 1. This multiplier is applied per the COLR and decreases the allowable LHGR value. This additional margin may be necessary during SLO to account for the conservative analysis assumption of an earlier departure from nucleate boiling with only one loop available. The LHGR satisfies Criterion 2 of the NRC Policy The LHGR is a assumption in the fuel design The fuel has been designed to operate at core power_ with sufficient design margin to the LHGR calculated to a 1% fuel cladding _plastic strain. The limit to accomplish this objective is specified in the COLR. The LHGR limits are derived from fuel design analysis that is limiting at high power-level conditions._-At core thermal power levels< _23% RTP, the reactor is :operating with a substantial margin to the LHGR limits and, therefore, the is only when the reactor is at 23% RTP. If any LHGR exceeds its required limit, an assumption tegarding an initial condition of the fuel design analysis i s n o t met . Th er e f o r e , . p romp t a ct i o n s h o u l d b e t a k e n to the LHGR(s-) to with-in its required limits such that the is within analyzed The -continued B3.2-12 .Revision No. 119 BASES ACTIONS PBAPS UN IT 3 . A.l (continued) LHGR B 3.2.3 2 hour Completion Time is normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification. If the LHGR cannot be restored to within its required limits within the Completion Time, the plint must be brought to a MODE or.other specified condition in which the LCD does not apply. To achieve this status, THERMAL POWER is reduced to< 23% RTP within 4 hours. The allowed *I Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER TO < 23% RTP in an orderly manner and without challenging plant systems. (continued) B 3.2-12a Revision No. 119 LHGR B 3.2.3 BASES (continued) SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 3. SR 3.2.3.1 Th e LH G R i s r e q u i r e d t o be i n it i a l l y c a l c u l a t e d wit h i n
• 12 hours after THERMAL POWER is 23% RTP and periodically thereafter. It is compared to the specified limits in the COLR (Ref. 11) to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL 23% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NED0-24011-P-A, "General Electric Standard Application for Reactor Fuel," la test approved revision. 2. UFSAR, Chapter 3. 3. UFSAR, Chapter 6. 4. UFSAR, Chapter 14. 5. NED0-24229-1, "Peach Boitom Atomic Power Station Units 2 and 3, Single-Loop Operation," May 1980.
• NEOC-32162P, "Maximum Extended Load Line Limit and ARTS Improvements Program Analyses for Peach Bottom Atomic Power Station Units 2 and 3," Revision 2, Mardi1995 ..
• 7. NEDC-33566P, "Safety Analysis Exelon Peach Bottom'Atomit Power Station, Units 2 and 3; Constant Pressure *. Power Uprate,, Revi.sion 0. 8. "'Peach Bottom Atomic Power. Sta ti on Units 2 and 3 SAFERiGESTR-LOCA. Loss-of-CooJant Acc1dent An al y s i s , " January 19 3 . -9 ..
• Atomic *Power s'tation Units 2 & :3"GNF2 ECCS-LOCA Evalu.ation," GE HHach.i Nuclear Energy;* ,* M'ar.ch 2011. 10. NUREG:osob, ft.2, Subsectirin II.A.2(g),
• 2; July l981. *
• 11. . -Peach B.ottom .un1t 3 Co.re-Operating Limits Report (COLR), .. ** 12. G*-080-VC-272, ***peach Bottom Atomic Power Station ECCSo . 'LO.CA EvaJ uati on for GE14," General-Electric Company,; GENE>Jll-03716-09-02P, July 2000.
• B Revision No. 119 RPS Instrumentation B 3.3.1.1 B 3,3 INSTRUMENTATION B 3.3.1.1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND PBAPS UNIT 3. The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limits, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS) and minimize the energy that must be absorbed following a loss of coolant accident (LOCA). This can be accomplished either automatically or The protection and monitoring functions of the RPS have been designed to ensure safe bperation of the This is achieved by specifying limiting safety system settings (LSSS) iri terms of parameters directly monitored by the RPS, as well .as LCOs on other reactor system parameters and. equipment .performance. The LSSS are defined in this Specification as the Allowable Values, which, in conjunction with the LCOs, establish the threshold f6r protective system attioh to prevent acceptable limits, including Safety Limits (Sls) during Design Basis Accidents (DBAs). The RPS, as shown in the UFSAR Section 7.2, (Ref. 1), includes sensors, relays, bypass circuits, and switches. that are necessary to cause initiation of a reactor scram. Functional diversity is provided by monitor.ing a wide range of dependent and independent parameters. The input parameters to the scram logic are from instrumentatibn that monitors reactor vesiel water reactor vessel *pressure, neutron flux, main steam line isolation valve position, turbine control .valve CTCV) fast closure trip oil pressure, .turbine. stop. valve CTSV) position, drywell pressure, scram d'ischa rge volume ( SDV) water .1 evel, condenser. vacuum',. as* 11ell *as reactor mode switch in shutdown position1 manual 5cram RPS switches. There are at least four. redundant sensor in.put signals from ea;ch of these parameters (with the exception of the manual scram signal and* the *reactor mode switch. in shutdown scram . . signal).*. Most channels. include electronic equipment (e.g., trip units) that compares measured input signals with
• setpoints .. When the setpoint is relay which then afi RPS* trip s1gnai to the tri-p logic. *
• continued Revision No. 119 BASES BACKGROUND (continued) .. PBAPS UN IT 3 RPS Instrumentation B 3.3.l.l The RPS is comprised of two independent trip systems (A and B) with three logic channels in each*trip system (logic channels Al, A2, and A3; Bl, 82, and B3) as shown in the Reference 1 figures. Logic channels Al, A2, Bl, and B2 contain automatic logic for which the above monitored parameters each have at least one input to each of these channels. The outputs of the logic channels in a trip system are combined in a one-out-of-two logic so that either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram. This logic arrangement is referred to as a one-out-of-two taken twice logic. In addition to the automatic logic channels, logic channels A3 and B3 (one logic channel per trip system) are manual scram channels. Both must be depressed in order* to initiate the manual trip function. Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is received. This 10 second delay on reset ensures that the scram function will. be completed. Twp scram pilot valves are lpcated in the hydraulic control unit for each control rod drive (CRD). Each scram pilot valve is solenoid operated, with the solenoids normally energized. The scram pilot valves control the air supply to the scram inlet and outlet valves for the associated CRD. When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to scram. The scram valves control the supply and discharge paths for the CRD water during a scram. One of the scram pilot valve solenoids for each CRD is *
• controlled by trip system A, and the other solenoid is controlled by trip system B. Any trip of trip system A. in conjunction with any tripin trip system B i:estilts in de-energizing both solenoids, air bleeding off, scram valves opening, and control rod scram. The backup scram valves, which energize on a scram signal to depressurize the scram air header, *are also controlled by the RPS. Addi ti ona 11 y, the RPS cont ro 1 s the SDV vent and drain valves such that when logic channels Al and Bl are deenergized or when logic channel A3 is deenergized the (continued) Revision No. o BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 3 RPS Instrumentation B 3.3.1.1 inboard SDV vent and drain valves close to isolate the SDV, and when logic channels A2 and 82 are deenergized or when* logic channel B3 is deenergized the outboard SDV vent and drain valves close to isolate the SDV. The actions of the RPS are assumed in the safety analyses of References 2 and 3. The RPS is required to initiate a reactor scram when monitored parameter values exceed the Allowable Values, specified by the setpoint methodology and listed in Table 3.3.1.1-1, to maintain OPERABILITY and to preserve the integrity of the fuel cladding, the reactor coolant pressure boundary (RCPB), and the containment, by minimizing the energy that must be absorbed following* a LOCA. RPS instrumentation satisfies Criterion 3 of the NRC Policy Statement. Functions not specifically credited in the accident analysis are retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basiS . . The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in.Table 3.3.1.1-1. Each Function must have a required number of OPERABLE channels per RPS trip system, with their setpoints the specified Allowable Value, where The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Allowable Values, .where applicable, are specified for each RPS Function specified in the Table. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the. trip setpoint, but .within its .*. Allowable Value, is acceptable. A channel is inoperable if its actual trip setting is not within its required Allowable* Value. *. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., vessel level), and when the measured *output value of * .* ... (continued)
• B 3.3-3 No.* O BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued} PBAPS UNIT 3 RPS Instrumentation B 3.3.1.1 the process parameter exceeds the setpoint, the associated device (e.g., trip unit} changes state. The analytic or design limits are derived from the limiting values of the process parameters obtained from the safety analysis.or other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for calibration, process, and instrument errors. The trip setpoints are determined from analytical or design limits, corrected for calibration, process, and instrument errors, as well as instrument drift. In selected cases,. the Allowable Values and trip setpoints are determined by engineering judgement or historically accepted practice relative to the intended function of the trip. channel. The trip setpoints determined in this manner provide adequate protection by as.suring instrument and process uncertainties expected for the environments during the operating time of the associated trip channels are accounted for. The OPERABILITY of scram pilot valves and associated solenoids, backup scram valves, and SDV valves, described in the Background section, are not addressed by this LCO. The individual Functions are required to be OPERABLE in the MODES or other specified conditions specified in the Table, which may require an RPS trip to mitigate the consequences of a design basis accident or*transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to provide primary and diverse initiation signals. The only MODES specified in Table 3.3.1.1-1 are MODES 1 and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4, since all control rods are fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1} does not allow any control rod to be withdrawn. In MODE 5, control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have*the capability to scram. Provided all other control rods remain inserted, no RPS function is required. In this condition, the required SOM (LCO 3.1.l} and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS will occur. (continued} B 3.3-4 Revision No. O BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) I . I. RPS Instrumentation B 3.3.1.1 The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis. Wide Range Neutron Monitor CWRNMl I.a. Wide Range Neutron Monitor Period-Short The WRNMs provide signals to facilitate reactor scram in the event that core reactivity increase (shortening period} exceeds a predetermined reference rate. To determine the reactor period, the neutron flux signal is filtered. The period of this filtered neutron flux signal is used to generate trip signals when the respective trip setpoints are exceeded. The time to trip for a particular reactor period is dependent on the filter time constant, actual period of . the signal and the trip setpoints. This period based signal is available over the entire operating range from initial control rod withdrawal to full power operation. In the startup range, the most significant source of reactivity change is due to control rod withdrawal. The WRNM provides diverse protection from the rod worth minimizer (RWM), which monitors and controls the movement of control rods at low
• power. The RWM prevents the withdrawal of an out of. sequerice control rod durtrig startup could result in an unacceptable neutron flux excursion (Ref. The WRNM mitigation of the neutron flux excursion: To demonstrate the_ capability of the WRNM System to mitigate control rod withdrawal .events, an analysis has been . performed (Ref. 3) to evaluate the consequences of control rod. withdrawal events.* during sta*rtup that are mitigated only by the* WRNM period-short The withdrawal of a .* control rod out of sequence, .during startup, .analysis 3) assumes that one* WRNM channel* in each trip system is .
• demonstrates that the WRNMs.provide protection :against local. c_ontrol rod withdrawal errors and. results in * . _peak* fuel enthalpy the 170 cal/gm fuel failure ., ,:. PBAPS UNIT 3
• threshold criterion. *
• The WRNMs are. al so capable of limiting other reactivity *. excursions such as cold e,ven_ts, _*althoughno credit* is. speci fi ca lly assumed. B 3.3-:.5*. (continued) . 17' Revision No. .
• BASES APPLICABLE SAFETY ANALYSES, LCO, and APPll CAB IL ITV PBAPS UNIT 3 RPS Instrumentation B 3.3.1.1 I.a. Wide Range Neutron Monitor Period-Short (continued)
• The WRNM System is divided into two groups of WRNM channels, with four channels inputting to each trip system. The analysis of Reference 3 assumes that one channel in each trip system is bypassed. Therefore, six channels with three channels in each trip system are required for WRNM OPERABILITY to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The analysis of Reference 3 has adequate conservatism to permit an Allowable Value of 13 The WRNM Period-Short Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential for criticality exists. In MODE 5, when a cell with fuel has its control rod withdrawn, the WRNMs provide monitoring *for and protection against unexpected reactivity excursions. In MODE l, the APRM System and the RWM provide protection against control rod withdrawal error events and the WRNMs are* not required. The WRNMs are automatically bypassed when the mode switch is in the Run position. -1. b. Wide Range Neutron Mon 1 tor -I nop This trip signal provides assurance that a minimum number of WRNMs are OPERABLE. Anytjme a WRNM mode switch is moved to
• any position other than "Operate," a loss of power occurs, or the self-test system detects a failure which would result in the l.oss of a safety-related function, an inoperative trip signal will be received by the RPS unless the WRNM is bypassed.
• Since only one. WRNM in' each trip system may be bypassed, only one WRNM*ifreach RPS tr_ip system may be inoperabl* without resu\tirig in an RPS trip signal. -. . . . .. ' '* Th-is Function was not spec.ifkally credit_¢d in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as .required by the NRC approved )icensing basis; -* (continued) B 3 .* 3.:;.6 -Revision No. 17 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UN IT 3 RPS Instrumentation B 3.3.1.1 l.b. Wide Range Neutron Monitor-Inop (continued) Six channels of the Wide Range Neutroh Monitor-Inop . Function, with three channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. Since this Function is not assumed in the safety analysis, there is no Allowable Value for this Function. This Function is required to be OPERABLE when the Wide Range Neutron Monitor Period-Short Function is required. Average Power Range Monitor CAPRM) The APRM channels provide.the primary indication of neutron flux within the core and respond almost instantaneously to flux increases. The* APRM channels receive input signals from the local power range monitors CLPRMs) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. Each APRM also includes an Oscillation Power Range Monitor COPRM) Upscale Function which monitors small groups of LPRM signals to detect thermal-hydraulic i nstabi l iti es. The APRM System is divided into four APRM channel S* and four 2-out-of-4 voter Each APRM channel provides inputs to each of the four voter channels.* The four voter channels are divided into two groups of two each, with each group of two providing inputs to one RPS trip system. The system i.s designed to all ow one APRM channel, but no voter channels, to be bypassed. A trip any one unbypassed APRM will result in a "half-trip" in all four of the voter channels, but no trip inputs to either RPS trip system. APRM trip Functions 2.a, 2.b, 2.c, and 2.d are voted independently from OPRM Upscale Function 2.f. Therefore, any Function 2.a, 2.b, 2.c, or 2.d trip from any two unbypassed APRM channels will result in a full trip in each of the four Voter channels, which in turn results in two trip inputs into each RPS trip system logic channel. (Al, A2, Bl, and B2), thus resulting in a full scram signal. a Function 2.f trip from any two unbypassed APRM channels will result* in a full trip from each of the four voter channels. Three of the four APRM channels and all four of the voter channels are required to be OPERABLE to ensure that no single failure will preclude a scram on a valid In provide a?equate coverage of the entire core, consistent with the design bases for the APRM Functions 2.a, 2.b, and 2.c, at least 20 LPRM inputs, with at least three LPRM inputs from each of the four axial levels at which the LPRMs are located, must be operable for each APRM channel, and the number of LPRM inputs that have become inoperable {and bypassed) since the last APRM calibration CSR 3.3.1.1.2) must be. less than ten for each APRM channel. For the. OPRM Upscale, Function 2.f, LPRMs are to of 3 or 4 detectors. A of 8 . eel ls per channel, each with a minimum of 2 *OPERABLE LPRMs, must be OPERABLE for the OPRM Function 2.f to be OPERABLE. continued B 3.3-7 Revision NO. 126 BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UNIT. 3 RPS Instrumentation B 3.3.1.1 2.a. Average Power Range Monitor Neutron Flux-High (Setdown) (continued) For operation at low power Ci .e., MODE 2), the Average Power Range Monitor Neutron Flux-High (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux-High (Setdown) Function will provide a secondary scram to the Wide Range Neutron Monitor Period-Short Function because of the relative setpoints. At higher power levels, it is possible that the Average Power Range Monitor Neutron Flux-High (Setdown) Function will provide the primary trip for a corewide increase in power. No specific safety analyses take direct credit for the Average Power Range Monitor Neutron Flux-High (Setdown) Function. However, this Function indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 23% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Therefore, it indirectly prevents fuel damage during . significant reactivity increases. with THERMAL POWER . < 23% RTP. The Allowable Value is based on preventing significant increases in power when THERMAL POWER is < 23% RTP. The Average Power Range Monitor Neutron Flux-High (Se.tdown) Function must be OPERABLE during MODE 2 when.control
• may be.withdrawn since the potential for criticality exists . . In MODE 1, the Average Power Range Monitor Neutron Flux-High Function provides protection against reactivity transi*ents and the RWM and rod block monitor protect against control rod withdrawal error events; 2.b. Average Power Range Monitor Simulated Thermal Power-High . The Average Power Monitor Simulaied Thermal monitors average flux to approximate the THERMAL POWER being transferred to the reactor cool ant. The APRM neutron flux is electronically filtered with a time* constant represehtative of the fuel heat transfer to generate a signal proportional to the THERMAL POWER.in the reactor. The trip level is varied as a function of. recirculation drive flow Ci .e., at lower core flows, the setpoint is reduced proportional to the reduction in power experienced as* core fl ow is reduced with a fixed control rod patterri) but is clamped at an upper limit that is always
• lower than the. Average Power Range Monitor Neutron Flux*Hi]h Function Allowable Value. A note is included., applicable when the plant .is. in sirigle recirculation loop operation per LCD 3.4.1, whjch requires the flow value, Used ih , Allowable v*alue equation, .be reduced by value of * (continued) B 3.3-8 *Revision No. il9 I BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UN IT 3 RPS Instrumentation B 3.3.1.1 2.b. Average Power Range Monitor Simulated Thermal Power-High (continued) is established to conservatively bound the inaccuracy created in the core flow/drive flow correlation due to back flow in the jet pumps associated with the inactive recirculation loop. The Allowable Value thus maintains thermal margins essentially unchanged from those for two loop operation. The value of dW is plant specific and is defined in plant procedures. The Allowable Value equation for single loop operation is only valid for flows down to W = dW; the Allowable Value does not go below 61.5% RTP. This is acceptable because back flow in the inactive recirculation loop is only evident with drive flows of approximately 35% or greater (Reference 19). The Nominal Trip Setpoint (NTSP) and the and as-left tolerances (Leave Alone Zone) were determined in accordance with Referente 10. The Average Power Range Monitor Simulated Thermal Power-High Function is not specifically credited in the safety analysis but is intended to provide an additional margin of protection from transient induced fuel damage during operation where recirculation flow is reduced to below the minimum required for rated power operation. The Average Power Range Monitor Simulated Thermal Power-High Function provides protection against transients where THERMAL POWER increases slowly (such as the loss of feedwater heating and protects the fuel cladding integrity by ensuring that the MCPR SL is not exceeded. During these events, the THERMAL POWER increase does not significantly lag the neutron flux scram. For rapid flux events, the THERMAL POWER lags the neutron flux and the Average Power Range Monitor Neutron F1ux-High Function will provide a scram signal before the Average Power Range Monitor Simulated Thermal Power-High Function setpoint is exceeded. Each APRM channel uses total drive flow signal representative of total core flow. The total drive flow signal is generated by the flow processing logic, part of the APRM channel, by summing up the flow calculated from two flow transmitter signal inputs, one from each of the two recirculation loop flows. The flow processing logic OPERABILITY is part of the APRM channel OPERABILITY requirements for this Function. The APRM flow processing logic is considered inoperable whenever it cannot deliver a flow signal less than or equal to actual Recirculation flow conditions for all steady state and transient reactor conditions while in Mode 1. Reduced or Downscale flow conditions due to planned maintenance or testing activities *during derated plant conditions (i.e. end of cycle coast down) .will result in conservative setpoints for the APRM Simulated Thermal Power-High function, thus maintaining that function operable. continued B 3.3-9 Revision No. 119
  • , .. ... ::c *. .:> . * . . BASES APPLICABLE SAFETY ANALYSES, . LCO, and APPLICABILITY .. RPS Instrumentation B 3.3.1.1 2.b. Average Power Range Monitor Simulated Thermal (continued) The Allowable Value is based on analyses that take credit for the Average Power Range Monitor Simulated Thermal High Function for the mitigation of non-limiting events. The THERMAL POWER time constant of < 7 seconds is based on the fuel heat and a signal* proportional to the THERMAL POWER. The *Average Power Rahge Monitor Power-High . Function is required to be OPERABLE in MODE 1 when there is the of gener&ting excessive THERMAL POWER and potentially the SL applicable to high pressure and core flow c6nditions (MCPR SL)r During MODES 2 and 5, other WRNM and APRM Functions provide protection for fuel cladding *
• 2.c. Range Monitor Neutron Flux-High . The Average Power R&nge .Monitor Neutron Flux-High Function is capaPle a. trip signal to fuel damage RCS For the .. protection of Reference Range*Mon)tor Neutron Flux-High Function is *
• assum_e.d to terminate the nia1n. steam isolation valve (MSIV) closure: event *and,* along.*with the safet,y/relief .valves.* .. * .(S/RVs};* l irnit.the peak*reactor p*ressure Vessel (RPV) . . pressure to less than the* ASME Code l i111i.ts. The control rod * . drop accident (CRDA) s (Ref. 5) takes credit for the Average Power Monitor Neutron to t_errrii nate *the .CRDA .. **.* * . . * .-. *' .. . ***-** .. **** .. _. -. :.-*. ,.," * ... *.-*,*.* . . ;** . .. ... . '* . : . .-.-: ... :**.*.,. ' --*"r *. ** . '* "-._\, *, PBAPS UNIT 3 **,: , .. ,* *, ,,-** ... ' _: ____ **.' .,. *, ... _..** ... : **: ,.. .*. . " . .J' .. . -*::J .. . ,_ . *. ; .,, . ".':-.*, .'*,' -* :*,*, *-' -: . . -... , .. ;:-. , .. **" . .-: .... *-*. '*. ** .... * ..-* . *: ,,. **!,, ., '.* :. ** . _ ..... * ... (continued) . . . .
• Revision No* .. 30 ** . .' .

I BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPSUNIT 3 RPS Instrumentation B 3.3.1.1 2.c. Average Power Range Monitor Neutron Flux-High (continued) The Allowable Value is based on the Analytical Limit assumed in the CRDA The Average Power Range Monitor Neutron Flux-High Function is required to be OPERABLE in MODE 1 where the potential consequences of the analyzed transients could result in the SLs MCPR and RCS pressure) being exceeded. Although the Average Power Range Monitor Neutron Flux-High Function is assumed in the CRDA analysis, which is applicable in MODE 2, the Average Power Range Monitor Neutron Flux-High (Setdown) Function conservatively bounds the assumed trip and, together with the WRNM trips, provides adequate protection. the Average Power Range Monitor Neutron Flux-High Function is not required in MODE 2 . . * ..... * (continued)* RevisionNo. 30 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UN IT 3 2.d. Average Power Range Monitor-Inop RPS Instrumentation B 3.3.1.1 Three of the four APRM channels are to be OPERABLE for each of the APRM Functions. This Function (Inop) provides assurance that the minimum number* of APRM channels are OPERABLE. For any APRM ch*annel, any time its mode switch is not in the "Operate" position, an APRM module required to issue a trip is unplugged, or the automatic self-test system detects a critical fault with the APRM channel, an Inop trip is sent to all four voter channels. Inop trips from two or more unbypassed APRM channels result in a trip output from each of the four voter channels to it's associated trip system. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy*and diversity of the RPS as required by the NRC approved licensing basis. There is no Allowable Value for this.Function. This Function is required to be OPERABLE in the MODES where the APRM Functions are required. 2.e. Voter The 2-0ut-Of-4 Voter Function provides the interface between the APRM Functions, including the DPRM Upscale Function, and the final RPS trip system logic. As such, it is required to be OPERABLE in the. MODES where the*APRM Functions are required and is necessary to support the safety analysis applicable to each of those Functions. Therefore, the 2-0ut-Of-4 Voter Function needs to be OPERABLE in MODES 1 and 2. All four Voter channels are required to be OPERABLE. Each voter channel includes s.el f-di agnostic functions. If any voter channel detects a critical fault in its owrt processing, a trip is issued from that voter channel to the associated. trip ' ' The 2-0ut-Of-4 Logic Module includes 2-0ut-Of-4 Voter and the APRM Interface hardware. The 2-0ut-Of-4 Voter Furiction 2.e votes APRM Functions 2;a, 2.b, 2.c, and 2.d of Function 2.f. This voting accomplished by the 2-0ut-Of-4 Voter hardware in the Of-4 Logic Module .. Each 2:out-Of-4 Voter includes two redundant sets of outputs to RPS. Each output set contains two independent contacts; one contact for Functions 2.a, 2.b, 2.c and 2.d, and the other contact for Function 2.f. The analysis in Reference 12 took credit for this redundancy in the justification of the 12-hour Completion Time for Condition A, so the voter Function 2.e must be declared inoperable if any df its functionality is jnoperable. However, the voter Function 2.e does not need to be declared inoperable due to any failure affecting only the plant portions of the 2-0ut-Of-4 Logic Module. that are not riecessary tb perform the 2-0ut-Of-4 Voter fun ct i.on. no Allowable Value for. this Function.* Cconti nued). B 3.3-12 :Revision No. 51 I : : BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PB A PS UN IT 3

• RPS Instrumentation B 3.3.1.1 2.f. Oscillation Power Range Monitor COPRM) Upscale The OPRM Upscale Function provides compliance with 10 CFR 50, Appendix A, General Design Criteria (GDC) 10 and 12, thereby providing protection from exceeding the fuel MCPR safety limit (SL) due to anticipated thermal-hydraulic power oscillations. Reference 22 describes the Detect and Suppress-Confirmation Density (DSS-CD) long-term stability solution and the licensing basis Confirmation Density Algorithm CCDA). Reference 22 also describes the DSS-CD Armed Region and the three additional algorithms for detecting thermal-hydraulic instability related neutron flux oscillations: the period based detection algorithm (PBDA), the amplitude based algorithm CABA), and the growth rate algorithm (GRA). All four algorithms are implemented in the OPRM Upscale Function,. but the safety analysis takes credit only for the CDA. The remaining three algorithms provide defense-in-depth and additional protection against unanticipated oscillations. OPRM Upscale Function OPERABILITY is based only on the CDA. The OPRM Upscale Function receives input signals from the local power range mpnitors CLPRMs) within the reactor core, which are combined into cells tor evaluation by the OPRM algorithms. DSS-CD operability requires at least 8 responsive OPRM cells
• per channel. The software includes a self-check for the OPRM cells; therefore, no SR is The OPRM Upscale .Function .is required to be OPERABLE when the plant*is 18% RTP, which i*s established as ci power level that. is greater than or equal.to 5% below the lower boundary of the: Armed Region. requirement is designed to encompass the region of where anticipated events could lead to and related neutron flux oscillations. The OPRM is automatically ehabled when THERMAL POWER, as indicated by the APRM Thermal Power, is 23% RTP corresponding to the MCPR
• monitoring.threshold and recirculation drive flow, is less than 75% of rated flow. This region is the OPRM Armed. Region; Note (h) allows for entry into *the DSS-CD Armed *without automati*c arming of DSS-CD prior to completely passing through Armed Region during the first startup and* *the first shutdown following_DSS-CD implementati_on. * *(continued) B 3.3-12a Revision No. 125 BASES APPLICABLE SAFETV' ANALYSES, LCO, and APPLICABILITY PBAPS. UN IT 3 RPS Ifistrumentation B 3.3.1.1 2.f. Oscillation Power Range Monitor (OPRM) Upscale (continued) As described in Reference 22 and 24, the RTP values for the OPRM Upscale Function to be OPERABLE (2 18% 'RTP) and for the OPRM Upscale Function to be auto-enabled (2 23% RTP) are sufficiently conservative for protection of the plant against thermal-hydraulic instabilities. The basis for the 5% RTP difference between the OPRM Upscale OPERABLE (18% RTP) and OPRM Upscale auto-enable value (23% RTP) is to ensure that no credible event, e.g., loss of feed water heating, could result in a plant power excursion where an inoperable OPRM channel entered into the OPRM Armed Region. Peach Bottom plant specific analyses performed at these low power levels (Ref. 24) have demonstrated that any power excursion resulting from credible events is bounded by 5% RTP. In addition, both the core-wide and channel decay ratios at the OPRM Upscale auto-enabled values are extremely low as documented in Reference 22, which demonstrates the low possibility of thermal-hydraulic instabilities at low power and confirms the conservatisms in the OPRM Upscale Function auto-enable RTP value. The conservatisms in the determination of the values for OPRM Upscale Function OPERABLE and the OPRM Upscale Function auto-enabled sufficiently compensate for possible inaccuracy of the APRM simulated thermal power signal versus actual core thermal . power at power levels< 23% RTP. Therefore, there is no need to perform any calibration of the APRM simulated thermal power signal to calculated power with RTP < 23% in order to determine the OPRM Upscale Function OPERABLE. If any OPRM aut6-enable setpoint is in a non-conservative condition, i.e., the OPRM Upscale is not auto-enabled with RTP 2 23% and reactor recirculation drive 75% of
• rated, the associated channel is considered inoperable for the OPRM Upscale Function. Alternatively, the auto-enable setpoint may be adjusted to place the channel in a conservative condition (armed). If placed in the armed condition, the channel is considered OPERABLE. Note (h) reflects the need for plant data collection in order to test the DSS-CD equipment. Testing the DSS-CD equipment ensures its proper operation and prevents spurious reactor trips. Entry into the DSS-CD Armed Region without automatic . arming of DSS-CD during this initial testing phase ilso allows for changes in plant operations to address maintenance or other operational needs. However, during this initial testing the OPRM Upscale Function is OPERABLE and DSS-CD operability and capability to arm shall be maintained at recirculation drive flow rates above the DSS-CD Armed Region flow boundary. continued B 3.3-12b Revision No. 125 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) _.,:. PBAPS UNIT 3 .. 3. Reactor Pressure-High RPS Instrllinentation B 3.3.1.1 An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This causes the neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. No specific safety analysis takes direct crecii t for this Function. However, the Reactor Pressure-High Function initiates a scram for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core For the overpressurization protection analysis of Reference 4, the
• Reactor Pressure-High Function is credited as a backup Scram Function only. The analyses cons.ervatively assume the scram occurs on the Average Power Range Monitor Scram Clamp signal, not the Reactor Pressure-High signal. The reactor scram, along with the.S/RVs, limits the peak RPV pressure to less than the ASME Section III Code limits. High reactor pressure signals are initiated from four pressure transmitters that sense reactor* pressure. The Reactor Pressure-High Allowable Value is chosen to provide a sufficient margin to the ASME Section III Code limits during.the event. Four channels of Pressure-High Function, with two channels in each 'trip system'arrariged in a one-out-of-two logic, *are to be OPERABLE to ensure that no single in'strument failure will preclude a scrani. from *this Function . on a valid signal. The Function .. is required *to 'be OPERABLE in MODES 1 .and 2 when the RCS is pressurized and the potent_ial .for pressure increa*se . 4. Reactor Vesse.1 Water Level-Low (L*evel 3) . . ..** Low RPV wa,t_er levei indicates. capability to cool the :fuel may be threatened.; Shml'ld .RPV level decrease too far, fuel *damage
• Therefore; a s'cram is initiated at Level 3 to substantially reduce the heat generated *1n the fuel* fission .. The Reactor Vessei Water Levei-:-Low (Level 3) Function is assumed 'in the of events.* resulting in' the decrease of reactor . (Ref. 6). is credit_ed as a backup scram f-qnction for large* and intermediate. bi:-eak LOCAs.inside *(continued) *. Revision No. *o APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY . ! PBAPS UNIT 3 RPS Instrumentation B 3.3.1.1 4. Reactor Vessel Water (Level 3) (continued) primary containment. The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Reactor Vessel Water Level-Low (Level 3) signals are initiated from four level transmitters that sense the difference between the. pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of. Reactor .Vessel Water Level-Low (Level 3) Function, with two in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that *no single instrument failure will preclude a scram from this Function on a valid signal. The Reactor Vessel Water Level-Low (Level 3). Allowable Value is selected to ensure that during normal operation the separator: skirts are not uncovered (this protects available re.circulation pump net positive suction head (NPSH) from significant carryunder) and, for transients involving loss of all nqrmal feedwater flow,. initiation of the low pressure EC.CS subsystems at Reactor Vessel Water-Lo:w Low Low (Level 1) will not be ..
• The Function is required in MODES 1 and 2 where considerable energy exists in the RCS resulting in the limiting and accidents. initiations at Reactor Vessel Water Level-Low Low (Level 2) and Low Low Low (Level 1)' protection_ for level transients in all other MODES. . . .
• 5 ._. *Maiii"*steam Isolation Valve-Closure . ' MSIV c;:losure results in loss of.the*main turbine and the* condenser as a sink ,for the nuclear steam supply system and iri.d.icates' a need to.shut down the reactor to reduce heat . . . . . . ' . generation. Therefo're,
• rE!actor scram is iriit.iated on Cl. Main -Steam Isolation Valve:--Closure signal* before the MSIVs * . are completeiy closed 'in of* the .complete of the normal-he'at 'Sink subsequen't ( continued) . _ ... B 3.3-::14 Revision No .. 0 BASES APPLICABLE pAFETY ANALYSES, LCO, and APPLICABILITY PBAPS.UNIT.3 5. Main Steam Isolation Valve-Closure RPS Instrumentation B 3.3.1.1 (continued) transient. However, for the protection analysis of Reference 4, the Average Power Range Monitor Scram Clamp Function, along with the limits the peak RPV pressure to less than the ASME Section III Code limits. That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis. The reactor scram reduces the amount of energy required.to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs to RPS trip -system A while the other inputs to RPS trip system B. Thus, each RPS trip system receives an input from eight Main Steam Isolation channels, each consisting of one position switch. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam . lines must close in order for *a scram to occur. In addition, certain combinations of valves closed in two lines will result in a half-scram. The Main Steam Isolation Valve-Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient: Eight _channels of the Main Steam Isol9-tion Valve-Closure Function, with four channels in each trip system, are required. to be OPEAABLE to ensure that no sing.le instrument failure will preclude the scram from this Function on a valid signal. This Function is only required in MODE 1 since, with the MSIVs open and the heat generation rate high, a pressurization transient can occur if the MSIVs close. In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection. (continued) -Revision No. o i* BASES APPLICABLE SAFETY ANALYSES, LCO, arid APPLICABILITY (continued) PBAPS UNIT 3 6. Drywell Pressure-High RPS Instrumentation B 3.3.1.1 High pressure in the drywell could indicate a break in the RCPB. A reactor scram is initiated to minimize the possibility of fuel damage and to reduce the amount of energy being added to the coolant and the drywell. The Drywell Pressure-High Function is assumed to scram the reactor during large and intermediate break LOCAs inside primary containment. The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure; The Allowable Value was selected to be as low as possible and indicative of a LOCA inside primary containment. Four channels of Drywell Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is required in MODES 1 and 2 where considerable energy exists in the RCS, resulting in the limiting transients and accidents. 7. Scram Discharge Volume Water Level-High_ The SDV receives the water displac_ed by the motion of the CRD pistons during a reactor scram.. Should this volume fill to a point where there is insufficient volume to accept the displaced water, control rod insertion would be hindered: Therefore, a re.actor scram is initiated while the remaining free vollline is still sufficient to accommodate the water from .a full core scram. No credit is taken for a scram initiated from the Scram Discharge Volume. Water Level-High Function.for any of the design basis accidents or transients. analyzed in* the UFSAR. However, this function is retained*** to ensure the RPS remains OPERABLE. (continued) B 3.3-16 Revision No. *o BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT-3 RPS Instrumentation B 3.3.1.1 7. Scram Discharge Volume Water Level-High (continued) SDV water level is measured by two diverse methods. The level is measured by two float type level switches and two thermal probes for a total of four level signals. The outputs of these devices are arranged so that one device provides input to one RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference 8. The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accommodate the water from a full scram. Four high.water level inputs to the RPS from four devices are required to be OPERABLE, with two devices in each trip system, to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed. 8. Turbine Stop Valve-Closure Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients* that must be limited. Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of the transients that would result from the closure of these valves. The Turbine Stop Valve-Closure Function is the primary scram signal for the turbine trip event analyzed in Reference 7 and the feedwater controller failure event. For these events, the reactor scram reduces the amount of energy required to b.e absorbed and ensures that the MCPR SL is not exceeded. Turbine Stop Valve-Closure signals are initiated from four position switches; one located on each of the four TSVs. Each switch provides two input signals; one to RPS trip system A and the other, to RPS trip system B. Thus, each RPS trip system receives an input from four Turbine Stop Valve-Closure channels. The logic for the Turbine Stop (continued) B 3.3:--17 Revision No. 0 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY .. * .. RPS Instrumentatirin B 3.3.1.1 8. Turbine Stop Valve-Closure (continued) Valve-Closure Function is such that three or more TSVs must be closed to produce a scram. In addition, certain combinations of two valves closed will result in a half-*scram. This Function be at THERMAL POWER 26.7% RTP as measured at the turbine first stage pressure. This is normally accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function .. The Turbine Stop Valve-Closure Allowable Value is selected to be high enough to imminent TSV closure, thereby reducing the severity of the subsequent pressure transient. Eight channels of Turbine Stop Valve-Closure Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER 26.7% RTP. This . 1* *Function is not required when THERMAL POWER is < 26.7% RTP s_i'nce the Reactor Pressure.-Hi gh and th.e Average Power Range Monitor Clamp are adequate to maintain the necessarf safety margins.
• 9. *Turbine Control Valve Fast Closure. Trip Oil Pressure:::_Low Fast clos.ure.of the TCVs results*ih the loss of a heat. sink that reactor pressure, neutron flux, and heat **transients that must .be limited. Therefore, .a reactor scram is i nltiated on TCV fast 'cl os*ure in anti ci pati'on of the tran'sients' thaf would: result from the closure of these ,* valves.'* The Turbine .Control: Valve Fa.st Closure, Trip Oil .*Pressure-Low :F'unet_ion is the* pri,mari scram.signal for the generator* load rejecfion event analyzed in Reference 7 and the.generator rejection with bypass failure event. For these the reactor the of energy required to .. :be absorbed and ensures that. the MCPR SL is not exceeded.:* .;. * ** .. . " continued PBAPS UN IT 3 B 3.3-18 Revision No. 119 ; .

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UN.IT 3. RPS Instrumentation B 3.3.1.1 9. Turbine Control Valve Fast Closure. Trip Oil Pressure-Low (continued) Turbine Control Valve, Fast Closure, Trip Oil Pressure-Low signals are initiated by the relayed emergency trip supply oil pressure at each control valve. One pressure switch is associated with each control valve, and the signal from each switch is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL 26.7% RTP. This is normally accomplished automatically by pressure switches sensing turbine first stage pressure; opening of the turbine bypass valves may affect this Function. The Turbine C6ntrol Valve Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure. F6ur thannels of Turbine Valve Fast Closure, Trip Oil Pressure-Low Function -with two channels in each trip arranged in a logit are required to be OPERABLE to ensure that no* single in_strument failure will preclude a from Function on a valid signal. This Function iS required, consistent with the analysis assumptions, whenever THERMAL POWER 26.1% RTP. This Function is not requ1 red when THERMAL POWER is < 26. 7% .RTP, since the Reactor Pressure-High and the Average Power Range Monitor Scram Clamp Functions are adequate maintain the necessary safety margins. --10. Turbirie Condenser-Low Vacuum The Turbine Co-nden_ser-_Lo1:JVacuum Function -protects the -integrity of* the-* con:deriser *by sc:rammi ng the reactor and thereby decreasing the severity of the low condenser vacuum t r an s i en t. o n t he con d en s er : . Th i s fun ct i on* a l s o e n s u r e s . integrity of the reactor due to loss of its n.ormal heat sink. The reatt_orscram on a Turbine -Condenser-Low Vacuum si ghal wl.l i occur. pdor -to a reactor scram _from a Turbine St o p Va 1 ve -::-C l .o s u re s i

• g n a l . Th i s f u n Ct iO n is _ n o t specifically credited in any accident analysis but is being retained for the overall reduDdancy arid diversity of the RPS the NRC apprdved licensing basis. . . continued . -. . . -B Revision No. 119 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY
• P BA PS UN IT 3 RPS Instrumentation B 3.3.1.1 10. Turbine Condenser-Low Vacuum (continued) Turbine Condenser-Low Vacuum signals are initiated from four vacuum pressure transmitters that provide inputs to associated trip systems. There are two trip systems and two channels per trip system. Each trip system is arranged in a one-out-of-two logic and both trip systems must be tripped in order to scram the reactor.
• The Turbine .Vacuum Allowable Value is specified to ensure that a scram occurs prior to the integrity of the main condenser being breached, thereby limiting the damage to the normal heat sink of the reactor. Four channels of the Turbine Condenser-Low Vacuum Function *with two channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will scram from this function on a valid signal. This Function is only required in MODE 1 where considerable energy exists which could challenge the integrHy of the main condenser if vacuum is low. In MODE 2, the Turbine Condenser-Low Vacuum Function is not required because at low power levels the transients are less. severe. 11. Deleted continued B 3.3-20 Bev1sion No .. 119 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS u*Nrr 3 RPS Instrumentation B 3.3;1.l 12. Reactor Mode Switch-Shutdown Position The Reactor Mode Switch-Shutdown Position Function provides signals, via the manual scram logic channels, directly to the scram pilot solenoid power circuits. These manual scram logic channels are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
• The reactor mode switch is a keylock four-position, bank switch. The reactor mode switch is capable of scramming the reactor if the mode swttch is placed in the shutdown position.* Scram signals from the mode switch are into each of the two RPS manual scram logic channels. There is no Allowable Value for this Function, since the channels are actuated based solely on reactor mode switch position. Two channels of Reactor Mode Switch-Shutdown Position Function, with one channel. in each manual scram trip system, are available and required to be OPERABLE. The Reactor Switch-Shutdown Pnsition. Function is required to be OPERABLE in MODES 1 and 2, and MODE 5 with control rod withdrawn frdm a core cell containing one or more assemblies, since the MODES and other specified when control rods are withdrawn. continued B 3.3-21 *Revision No. 119_.

BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY (continued) . . PBAPS UNIT.3 13. Manual Scram RPS Instrumentation B 3.3.1.1 The Manual Scram push button channels provide signals, via the manual scram logic channels, directly to the scram pilot solenoid power circuits. These manual scram logic channels are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis. There is one Manual Scram push button channel for each of the two RPS manual scram logic channels. In order to cause a scram it is necessary that each channel in both manual scram trip systems be actuated. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons. Two channels of Manual Scram with one channel in each manual scram trip system are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are with¢rawn. 14. RPS Channel Test Switch There are four RPS Channel Test Switches, one associated with each of the four automatic scram logic channels (Al, A2, Bl, and B2)" These switches allow the operator

• to test the OPERABILITY of each individual logic channel without the necessity of using a scram function trip. This is accomplished by placing the RPS Channel Test Switch in test, which will input a trip signal into the associated RPS logic channel. The RPS Channel Test Switches were not specifically credited in the accident analysis. However, because the Manual Scram Functions at Peach Bottom Atomic *Power Station, were not configured the same as the generic model in Reference 9, the RPS Channel Test Switches were included in the anaiysis in Reference 10. Reference 10 concluded that the Surveillance Frequency extensions from (continued) B 3.3-22 Revision No. 0

,.., .. ** :-. 'J. '.-=*** .. BASES RPS Instrumentation B APPLICABLE .SAFETY ANALYSES, LCO, and APPLICABILITY 14. RPS Channel Test Switch (continued) RPS Functions, described in Reference 9, were not affected by the difference in configuration, since each automatic RPS channel has a test switch which is functionally the same as the manual scram switches in the generic model. As such, the RPS Channel Test Switches are retained in the Technical .*, .. ' . ';', ' '" * .... -.,, .:. . * ' .. ,* Specif1cations.

• There is no Allowable Value for this Function since the are mechanically based solely on the of the switches.
• Four channels of RPS Channel Test Switch with two channels fn each trip in a one-out-of-two logic are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5*with any control rod withdrawn from a core cell containfng orie or more fuel assemblies, since these are the MODES other specified conditions when tontrol rods are withdrawn. A Note been prbvided to modify the *ACTIONS related to . RPS 'instrumentation channels .. Section 1.3; Completion Ti mes, spec if i es that . once a Condition has been entered,' , '.*subs*equent divisions, subsystems,. components; or variables expressed 1n the Cohditiori; discovered to be.* inoperabl_e or * . . not wi.th'i n l i inits-, will . riot result in separate entry *1 nto *: *the Condition. *.Section 1:3 also .:specifies *that Required .. Actions: of:the ,Conditio_n continue.to apply for each . additi.ona:*1 failure; with Completion Times based on initial entry in_to . ._the Condition:** Howeyer, the? Required: Actions. for .. * . inopefrable RPS _i nstrume.ntat ion .chanriel s proV1 de appropriate ** . compensatory measures **for . separate inoperable channels> As such,. . a Note* h*as been ,'provi.ded that a 1 lows *separate . *Condition entr.Y for .. each inoperable -RP.S instrumentation-*.* *. ,. .... * :. * . channeJ. > :* : .*. * * * .. ' * * .. ' : '. *,._ ,_: *.*-:.-* * * !"< ,, **: ;:.**_ *. . :A.1 arid A;*2 *_*., : -: .. ... .. <*:** : .. :*. *: . ..... *.**' *** Becalise(9(,the::diversity of sensors *available to .prcwide-; *trip s_l"gna1s and.th:e:redundahcy :of the RPS d_esign, aJ1 . . . . allowable out *of service. time>o.f 12 hours has been shown to** be i2:;*&**13}*to permit * . * /. *anf lnope.r.(lble. chanhe 1 However; this*: * . ' out :*of servke' is. only acceptable. provided the. * *ass_ocfatecf * ... * * * '* .. ' * * ** .: *. .'*:* ' .. *.,* *'***' (continued) .. . ' ', . .. _:.* .. *.: -.... .-........ . Revi.sion No: ... -30 ** . ***.

BASES ACTIONS PBAPS UNIT 3 A.l and A.2 (continued) RPS Instrumentation B 3.3.1.1 Function's.inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.l, B.2, and C.l Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped condition per Required Actions A.l and A.2, Placing the inoperable channel in trip (or the associated trip system in trip) would compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternatively, if it is not desired to place the channel {or trip system) in trip (e.g., as in the case where placing inoperable channel in trip would result in a full scram), Condition D must be entered and its Required Action taken. As rioted, Action A.2 is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of one required APRM channel affects both trip systems. For that cbndition, Required Action A.l must be satisfied, and is the only aCti on (other than. restori'ng operabi.l i ty) that wi 11 restore capability to a single failure. Inoperability of more than one required APRM channel of the. same trip results in loss of trip capability and entry into Condition C, well as int6 Condition A for channel.: B.l and B.2 C.onditi.on B exists when, for any one or more Functions, at least cine 'required channel is *inoperable in each trip system. In this*.c*ondition', provided at least one channel* per trip system fs OPERABLE; the RPS still. maintains trip ca pa bi l iti for that FunCti but cannot accommodate a* si.ngle .failure in either*t_rip system. Required B.1 and B .. 2 liniit the time t.he RPS scr.am 16gic, for any Function, not single in_ both trip (e.g., and one-out-of--one arrangement for a typicai .four channel "Function). The .reduced reliabflity of this logic_ arran.gement was not evaluated in References 9; 12 or 13 fol". the 12 hour *completion Within the 6 hour allowance, . t h e a s s o t i a t e d Fu nc t*i o n w i l l *

• h a v e a l l
• re q e d c h a n n e l s OPERABLE or in trip (or any combination) iri one trip system. continued
• B 3. 3-24 . * :;Revision*No; 51 J BASES ACTIONS PBAPS UNIT .3
• B.l and B.2 (continued) RPS Instrumentation B 3.3.1.1 Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in References* 9, 12 or which justified a 12 h6ur allowable out of service time as presented in Conditi*on A. The trip system in the more degraded state should be placed in trip or, alternatively, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions). The decision of which trip system is in the more degraded state should be based on prudent judgment and take into current plant conditions (i.e., what MODE plant is in); If this action would result in a scram or RPT, it is permissible to place the other trip system or its inoperable channels in trip. The 6 hour Time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probability of extensive of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a scram. *
• Alternately, if it is not desired to place the inoperable chanriels (or one trip system) in trip (e.g,, .as ih the case where placing the ihoperable channel or associated trip system in trip would result in a scram, condition D must be and its Action taken. As noted, Condition Bis n6t applicable for APRM Functions 2.c, or 2.f. Inoperability of an APRM I channel both trip systems and is not associated with a specific trip system as are the APRM 2-0ut-Of-4 voter and other nbn-APRM channels for which_ Condition B applies. For an inoperable APRM channel, Required Action A.1 must be satisfied, and is the only actinn (other than restoring operability) that will restore capability to accommodate a single failure: Inoperability of a Function in more than one required APRM channel results in of trip capability for that Function and entry into Condition C, as well as entry into Condition A for each channel. Because Condition A and C provide Required Actions that are appropriate for the inoperability of APRM Functions 2.a, 2.b, 2.c, 2.d, or I* 2.f, and these* functions are not associated with specific trip systems as are the APRM 2-0ut-Of-4 voter and other APRM channels, B does not apply. continued flevision No. 51

... *. ,* :*.: .*' ... '. ,' . --; . . ;* ;'"'_ * .. * . '* . BASES ACTIONS (continued) "; .. ' .. '* * *. r-* .. :-.. PBAPS UNIT 3 C.1 RPS Instrumentatipn B 3.3.1.l Required Action C.1 is intended to ensure-that appropriate actions are taken if multiple, inoperable, untripped _ channels within the same trip system for the same Function -result in an automatic Function, or two or more manual Functions, not maintaining RPS trip capability. A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or .the associated trip system is in trip), such that both trip systems will generate a trip signal from the given Functioh on a valid signal. For the typical Function with of-two taken twice logic and the IRM and APRM Functions, *this would require both trip systemi to have one channel OPERABLE or in trip (or the associated trip system in trip) ..

• For Function 5 (Main Steam Isolation Valve-Closure), this* would require both trip systems to have each channel with the MSIVs in three main steam lines (not'* necessarily the same main steam*lines for both trip
• _ systems)OPERABLE or in trip (or the associated trip system in trip). For. Function 8 (Turbine Stop Valve-Closure),* -this would require both trip systems to have three channel.s, each OPERABLE.or in trip (or the associated trip system in * -trip). For Functions 12 (Reactor Mode Switch-Shutdown .Position) and 13 {Manual Scram), this wouid require both. 0 'trip systems *to.have one channel, each OPERABLE in trip .(or tbe associated trip system in trip).
• The Comp let iOn Ti me is i.ntended to all ow the operator -time to evaluate and-repair any discovered The l hour Completion:Time is acceptable because it minimizes. risk*-while allowing time for restoration or tripping of cha,nnel s. * -*
• D. l , Required Action D.l 'Condition referenced in Table applicable -conditibn specified in the Table is Function and MODE-or.* _other spec_ifi ed* condition dependent and may change as-:the * -Action -of a previous Condit.ion is completed. Each time an inoperable channel has not niet any Required Action _ *. -,of:Conditiori A, B, or C the Completiori Time .*has expired-,Co11dition-D will-be entered-for that_channel _ and providei for trarisfer'to appropriate subsequent. Condition. -* * . . . . . -.. (continuedt . B 3.3-26. Revisibn :No. 3.0: ; .... _, -. .......

BASES ACTIONS (continued) E.1. F.l and G.1 RPS Instrumentation B 3.3.1.l If the channel (s) is not restored to OPERABLE status or placed in trip (or the associated trip system in trip)* within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. The allowed Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition, the Completion Time of Required Action E.l is consistent with the Completion Time provi_ded in LCO 3.2.2, "MINIMUM c R IT I c AL p 0 w ER RAT IO ( Mc p R ) . II If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. L..l If OPRM Upscale trip capability is not maintained, Condition I exists and Backup Stability Protection (BSP) is required. The Manual BSP Regions a re described in Reference 22. The Manual BSP Regions are procedurally established consistent with the guidelines identified in Reference 22 and require s p e c i f i e d ma n u a l o p e r a t o r a ct i on s i f c e r.t a i n p red e f i n e d operational conditions occur. The Completion Time of immediately is based on the importance of limiting the period of time during which no automatic or . alternate detect and suppress trip capability is in place. I.2 and I.3 Actions I.2 and I.3 are both required to be taken in conjunction with Action I.l if OPRM Upscale trip capability is not maintained. As described in Section 7.4 of Reference 22, the Automated BSP Scram Region is designed to avoid reactor instability by automatically preventing entry into continued B 3.3-27 Revision No. 125 BASES ACTIONS . -----.--.. *_, PBAPS UNIT :,3 I.2 and I.3 (continued) RPS Instrumentation B 3.3.1.1 the region of the power and flow-operating map that is susceptible to reactor instability. The reactor trip would be initiated by the modified APRM Simulated Thermal Power-High scram setpoints for flow reduction events that would have terminated in the Manual BSP Region I. The Automated BSP Scram Region ensures an early scram and SLMCPR protection. ' The Completion Time of 12 hours to complete the specified actions is reasonable, based on operational experience, and based on the importance of restoring an automatic reactor . trip for thermal-hydraulic instability events. BSP is intended as a temporary means to protect against hydraulic instability events. The action should be initiated immediately to document the situation a_nd prepare the report. The reporting requirements of Specification 5.6.8 document the corrective actions and schedule to restore the required channels to an OPERABLE status. The Completion Time of 90 days shown in Specification 5.fr.8 is adequate to allow time to evaluate the cause of the inoperability and to determine the appropriate corrective and schedule to restore the required channels to OPERABLE status. . . ' If the Required Action I is not completed within the associated Completion Time, then Action .. J is required .. -Th<;: Bases for the Manual BSP Regions and associated Completion Time is in the Bases for I. l.

• Th*e Manua 1 BSP Regions a re required in conjunction with the BSP .* The BSP Boundary, as in Section 7.3 o.f Reference. 22, defines.an operating .domairi where.potential initabilitj events can be .effecti veJy addressed *by the specified BSP manual actioris. The BSP Boundary is constructed such that a
• fl ow re<;luctiOri event initiated from this. bouhda ry and terminated ,. at the .i::ore**natural drtulation line (NCL) would.not exceed the Manual BSP Region I stability criterion, . Potential * . develop slowly as a of the feedwater tempera_ture tra.hsierit (Ref. 22) . . The Compiet:ion Time of .12* hours to complete the specified * .'.actions* rs. rea*sonable, based* on operational experience, to* reach the specifi t condit;i on from full *power cond.iti ons in an orderly man.ner.and. without cha lleng.i ng pl ant systems . c'onti nLied B 3.3-27a No. 125 I BASES RPS Instrumentation B 3.3.1.1 ACTIONS J.3 (continued) --PBAPS UNIT 3 BSP is a temporary means for protection against hydraulic instability events. An extended period of inoperability without automatic trip capability is not justified. Consequently, the required channels are required to be restored to OPERABLE status within 120 days. Based on engineering judgment, the likelihood of an instability event that could not be adequately handled by the use of the BSP Regions (See Action J.l) and the BSP Boundary (See Action J.2) during a 120-day period negligibly small. The 120-day period is intended to allow for resolution of a variety of equipment problems (e.g., design changes, extensive analysis, or other unforeseen circumstances). This action is not intended to be used for operational convenience. Cdrrectiori of most equipment failures or inoperabilities is expetted to normally be accomplished within the completion times allowed for Actions for Condftions A and I. A Note is provided to indicate that LCD 3.0.4 is not applicable. The intent of the note is to ailow plant startup whn'e operating within the 120-day Compl_etion Time for Required Action J.3. _The primary purpose of this exclusion is to allow an orderly completion of design and verification activities, in the event of a required design change, without undue impact on plant Dperation.
• K.l -If the required channels are not restored t6 OPERABLE status . and the Required Actions of J are not met within the associqted .completion Ti*mes, then the plant must be placed in an operating conditi'on in which the LCD does not apply. To achieve-this _st_aJus; t_he--pl ant must be brought to less than 18% .. RTP within A hours. *The allowed Com_pletion Time _is reasonable, based on operat1ng experience; to reach the specified operating power -1 evel-from full power conditions in an orde.rly manner and wi_thout challenging plant systems. (continued) B 3.3-27b Revi slon No._ 126 I BASES (continued) SURVEILLANCE. REQUIREMENTS PBAPS UN I1 3 RPS Instrumentation B 3.3.1.1 As noted at the beginning of the SRs, the SRs for each RPS instrumentation Function are located in the SRs column of Table 3.3.1.1-1. The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note based on the reliability analysis (Refs. 9, 12 & 13) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probabiljty that the RPS will trip when SR 3.3.1.1.1 Performance of the CHANNEL CHECK ensures that .a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the parameter should read approximately the same value. Significant between instrument channels could be an of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to veri.fying the instru.mentation continues to operate properly each CHANNEL CALIBRATION. Agreement criteria are determined by plant staff based on a combination of the channel instrument uncertainties, including i ndi ca ti on and readabi 1 i ty. *If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more.frequent, checks of channels during normal operational use *of the displays associated with the channels required by the LCO. SR 3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to* the reactor power ffom a heat balance. The Surveillance Frequenty is under the Surveillance Frequency Control Program. continued Revision .No: 125*

BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 SR 3.3.1.1.2 (continued) RPS B 3.3.1.1 A restriction to satisfying this SR when < 23% RTP is provided that requires the SR to be met only 23% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when< 23% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR, LHGR and APLHGR). At 23% RTP, the Surveillance is required to have been satisfactorily performed in accordance with SR 3.0.2. A Note is provided which allows *an in THERMAL POWER above 23% if the Frequency is not met per SR 3.0.2. In this event, the* SR be performed within 12 hours after reaching or exceeding 23% RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR. SR 3.3.1.1.3 (Not Used.) SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. The Surveillance Frequency is controlled . under the Surv.ei 11 ance Frequency Control Program. SR 3.3.1.1.5 and SR* 3.3.1.1.6 A CHANNEL FUNCT10NAL TEST is performed on required channel to erisure that the entire will perform the intended function ..

• Any setpoint adjustment *shall be made . with the assumptions the £urrent plant specific setpoint method6logy. As noted, SR is required to be performed MODE MODE 1, since testing of the MODE 2 required WRNM Functions cannot be performed in MODE 1 _ without utilizing lifted leads, or.movable links. This allows entry into MODE 2 if the Frequency is not met per SR 3.0.2. In this the SR must be performed within hours after entering MODE 2 from MODE 1. hours i5 based on operating experience in consideratton ***of providing a reasonable time in_ which to complete the SR . . The Surveillance is coritrolled under the _Surveillance Frequency Control (continued) -B 3. 3-29--Revision No.-1.19 i . I BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS µNIT 3 SR 3.3.1.1.7 (Not Used.) SR 3.3.1.1.8 RPS Instrumentation B 3.3.1.1 LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP) System. This establishes the relative local flux profile for appropriate representative input to the APRM System. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.1.1.9 and SR 3.3.1.1.14 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific methodology. For Function 5, 7, and 8 channels, verification that the trip settings are less than or equal to the specified Allowable Value during the CHANNEL FUNCTIONAL TEST is not required since the channels consist df mechanical switches and are not subject to drift. An exception to this are two of the Function 7 level switches which are not mechanical. These Scram Discharge Volume CSDV) RPS switches (Fluid Components Inc.) are heat sensitive electronic level detectors which actuate by sensing a difference iri temperature. The temperature detectors are permanently affixed within the scram discharge volume piping conservatively below the level (allowable value as measured in gallons) at which an RPS actuation signal will occur. Since there is no drift involved with the physical location of these switches, verifying the trip settings are less than or equal to the specified allowable value during the CHANNEL FUNCTIONAL is not required. Additionally, historical calibration data has indicated that the FCI level switches not exceeded their Allowable Value when tested. In addition, Function 5 and 7 instruments are not accessible . while the unit is operating at power due to high radiation . and the installed indication instrumentation does not provide accurate indication of the trip setting. For the Function 9 channels, verification that the trip settings are less than or equal to the specified Allowable Value continued B 3.3-30 Revision No. 119 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 RPS Instrumentation B 3.3.1.1 SR 3.3.1.1.9 and SR 3.3.1.1.14 (continued) the CHANNEL FUNCTIONAL TEST is not required since the instruments are not accessible while the unit is operating at power due to high radiation and the installed indication instrumentation does not provided accurate indication of the trip setting. Waiver of these verifications for the above functions is considered acceptable since the magnitude of drift assumed in the setpoint calculation is based on a 24 month calibration interval. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.1.1.10. SR 3:3.1.1.12. SR 3.3.1.1.15. and SR* 3.3.1.1.16 A CHANNEL CALIBRATION is a complete check of the instrument loop arid the sensor .. This test verifies that the channel responds to the parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts successive calibratibris, with the* current plant setpoint methodology. As hated f6r SR 3.3.1:1.10, radiation detectors are excluded from CHANNEL CALIBRATION due to ALARA reasons (when the pl ant is operating, the radiati.ori detectors are generally in a high rad i at i on are a ; the steam tunnel ) . Thi s ex cl us i on i s acceptable because the radiation are passive d e v i c es , wit h m i n i ma l d r i ft . To c om p l et e t he .r a d i a t i o n *CHANNEL SR 3.3.1.1.16 requires that the radiation detectors be calibrated .in accordance with the *. Sur*vei.ll9nce Frequenc:;y.Control Program. * **.SR 3.3:1.1,12. for futiction is modified by two . Notes as identified i-n Tabie _3.3.1.1-1..' The first Note . requJres evaluatjon of channel performance for the 'where the setting for the channel setpoint is.'
• tqlerance put_ conser:vatfve. with respect "to*the.Allowab*le Value. Evaluation of channel performance. will verify thaLthe channel w111 continue to behave in accordance-with safety analysis assumptions and the channel performance assumptions the setpoint_ methodology. The purpose of .the-assessment is_ to ensure confidence in the : channel perfo.r.mance prior to-returning .the channel to -*.:serv1ce. For channels det_ermined.to.be OPERABLE but degraded, after r*eturning the channel to service the *,performance of these channels wi l,l' be evai uated under the continued ' ' B 3;3-31 No.

BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 RPS Instrumentation B 3.3.1.1 SR 3.3.1.1.10. SR 3.3.1.1.12. SR 3.3.1.1*.15. and SR 3.3.1.1.16 (continued) plant Corrective Action Program.* Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the Leave Alone Zone around the NTSP. Where a setpoint more conservative than the NTSP is used* in the plant surveillance procedures CATSP), the Leave Alone Zone and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the Leave Al one Zone around the NTSP, then the channel shall be declared inoperable. The second Note also requires that NTSP and the methodologies for calculating the Leave Alone Zone and _the as-f_ound tolerances be in the Bases for the . applicable Technical Specifications. The Frequency is controlled under the Frequency Control Program. As noted for SR 3.3.l.Ll2, neutron detectors are excluded ffom CHANNEL CALIBRATION because they are* passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for .by performihg the calor1metric calibration CSR 3.3.1.1.2) and-the LPRM calibration against the TIPs CSR 3.3.1.1.8). A secorid_note is provided for SR 3.3.1.1.12. that allows the WRNM SR-fo be performed. wi.thi n 12 hours of entering MODE 2 from MODE 1. -_Tes.ting of _the MODE 2 WRNM Functions cannot be performed in MODt* 1 wit.fioi.Jt.utilizing jumpers, lifted leads or This Note al1ows entry into MODE 2 from MODE l; .i.f the Frequency *is -not met per SR 3_.*0.2. Twelve -hours is .. based. on operating experience and *in consideration of' provicjing a time 'in wh*ich to complete:the SR. : .-* .. -. A third note is provided* for SR that includes in the SR-the recirculation flow.(drive fiow) -which supply the .flow signal to the APRMs. The APRM.Simulated Thermal "Power-Higb Function (Function 2.b) and the Upscaie.Ft.inction (Function 2.f), both require a valid drive fl ow si-gn*aJ. The APRM Simulated Thermal (continued) B 3. >32 Revision No: 119 BASES SURVEILLANCE REQUIREMENTS 'UNIT 3 RPS Instrumentation B 3.3.1.1 SR 3.3.1.1.10. SR 3.3.1.1.12. SR 3.3.1.1.15. and SR 3.3.1.1.16 (continued) uses drive flow to vary the trip setpoint. The OPRM Upscale Function uses drive flow to automatically enable or bypass the OPRM Upscale trip output to RPS. A CHANNEL CALIBRATION of the APRM drive flow signal requires both calibrating the drive flow transmitters and establishing a valid drive flow I core flow relationship. The drive flow /core flow relationship is established once per refuel cycle, while operating at or near rated power and flow conditions. This method of correlating. core flow and drive flow is consistent with GE recommendations. Changes throughout the cycle in the drive flow I core flow relationship due to the changing thermal hydraulic operating conditions of the core are accounted for in the margins included in the bases or analyses used to the setpoints for the APRM Simulated Thermal Power-High Function and the OPRM Upscale Function. The Surveillarice Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.1.1.11 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the ent.i re channel wi 11 *perform the intended function. For the APRM Functions, this test supplements the self-test functions that operate cont i nu o us l y i n the AP RM and voter ch an n e.l s .

• The . scope of the APRM CHANNEL FUNCTIONAL TEST is limited to verificatioh of system trip output hardware. Software controlled functions aYe tested only iricidentally. Automatic internal functions check the EPROMs in the controlled logic is defined. Any in the EPROMs will be detected by the function resulting in a trip and/or alarm condition. The APRM CHANNEL FUNCTIONAL TEST covers the APRM channels (including recirculation flow processing -applicable to Function 2.b and the auto-enable portion of Function 2.f only}, the 2-0ut-Of-4 voter channels, and the interface connections i.nto the RPS trip systems from the voter channels. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. (NOTE: The actual voting logic of the 2-Voter Function is tested as part bf SR 3.3.1.1.17. actual auto-enable setpoints for the OPRM Upscale trip are confirmed by SR*3.3.1.1.19.)
• continued. B 3.3-33

/ .. I I BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 SR 3.3.1.1.11 (continued) RPS Instrumentation B 3.3.1.1 A Note is provided for Function 2.a that requires this SR to* be performed within 12 hours of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM Function cannot be performed in MODE 1 without utilizing jumpers or lifted leads. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. A second Note is provided for Function 2.b that clarifies that the CHANNEL FUNCTIONAL TEST for Function 2.b includes testing of the recirculation flow processing electronics, excluding the flow transmitters. SR 3.3.1.1.13 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER 26.7% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. Because turbine bypass flow this setpoint nonconservatively (THERMAL POWER is derived frbm turbine first stage pressure), the main turbine bypass valves must remain closed during the calibration at THERMAL POWER* 26.7% RTP to ensure that the calibration is valid. If any bypass channel's set point is nonconservative (i.e.,. the Functions are bypassed 26.7% RTP, either due to open main turbine bypass valve(s) or other reasons}, then the *affected Turbine Stop Valve-Cl a.sure and Turb.ine Control *valve Fast Closure,. Trip Oil Pressure_:Low Functions are considered inop.erable. Alternatively, the bypass thannel*can be placed in the If

• placed in the this SR is met and the channel is considered OPERABLE.
• The SurveiJlance Frequency is controlled under the Stlrveillance Frequency Control Program. continued . B 3.3-34 .* Revision Nci. 127 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UNIT 3 SR 3.3.1.1.17 RPS Instrumentation B 3.3.1.1 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods (LCO 3.1.3), and SDV vent and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The LOGIC SYSTEM FUNCTIONAL TEST for APRM Function 2.e simulates APRM and OPRM trip conditions at the 2-0ut-Of-4 voter channel inputs to check all of two tripped inputs to the 2-0ut-Of-4 logic in the voter channels and APRM related redundant RPS relays. SR 3.3.1.1.18 This SR ensures that the individual channel response times are maintained less than or equal to the original design value. The RPS RESPONSE TIME acceptance criterion is included in Reference 11. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.1.1.19 Deleted (continued) B 3.3-35 Revision No. 125 BASES (continued) REFERENCES ..... .-.. PBAPS UN IT -3 1. UFSAR, Section 7.2. 2. UFSAR, Chapter 14. RPS Instrumentation B 3.3.1.1 3. NED0-32368, "Nuclear Measurement Analysis and Control Wide Range Neutron Monitoring System Licensing Report for Peach Bottom Atomic Power Station, Units 2 and 3," November 1994. 4. NEDC-33566P, "Safety Analysis Report for Exelon Peach BottDm Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 5. UFSAR, Section 14.6.2. 6. UFSAR, Section 14.5.4. T. UFSAR, Sectioh 14.5.1. 8. P. Check (NRC) letter to G. Lainas (NRC.), "BWR Scram Di sch a rge System' Safety Evaluation' II December 1,. 1980. 9. -NED0-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System," March 1988. 10. "Techffical Specification Improvement Analysis for the Protection System for Peach Bottom AtomiC Power Station Units 2 and 3," October 198}. . 11. UFSAR, Section 7.2.3.9. 12. * "Nuclear Measurement Analysis and *Control. Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability* trip 'Function:", Octoper 1Q_95. *** -* * .. *' ---. -.. -:**.' ' . . 13.
• Supp.l ement l ,_ "Nuclear _Measurement Arialy,si s and Co.ritrol Pbwer Range Neutron Mo11itot CNUMAC PR.NM) Retrofit Plus* Option II.I Stability* Trip-*
• Fun'cti on'*; Supplement l", November 1997. 14. Deleted (continued) -*, -* -B .3.3-36 Revision No. 125 BASES REFERENCES (continued) . -:: .. . PBAPS UN IT 3 15. Deleted 16. Deleted 17. Deleted 18. *Deleted RPS Instrumentation B 3.3.1.1 19. NED0-24229-1, "Peach Bottom Atomic Power Station Units 2 and 3 Operation," May 1980. 20. Set point Methodology for Peach Bottom Atomi Power Statton and Limerick Generating Station, CC-MA-103-2001. 21. Backup Stability Protection (BSP) for Inoperable Option III Solutions, OG02-0119, July 17, 2002. 22. GE Hitachi Nuclear Energy, "GE Hitachi Boiling Water and *Suppress Solution -Confirmation Dehsity," NEDC-33075P-A, 8, November 23. GEH Tetter to NRC, "NEDC-33075P-A, Detect and Suppress *Solution -Confirmation Density (DSS-CD) Analytical Limit (TAC No. MD0277)," October 29', 2008. (ADAMS .Actession No. ML083040052). 24 .. OOO.N7936-RO, "Project Task Report -Generation Company LLC, Pea6h Bottom Atomic Station Uhit 2 &.3_ MELLLA+, Task _T0202: The_rmal-Hydraulic Stability," _*.April 2014 .. '*, ---" -..... *.:**'** .-_ ... ,-*, . **Revision No. 125

-B 3.3 INSTRUMENTATION WRNM Instrumentation B 3.3.1.2 I *B 3.3.1.2 Wide Range Neutron Monitor (WRNM) Instrumentation I BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 .. -., The WRNMs are capable of providing the operator with information relative to the neutron flux level at very low flux *1evels in the core. As such, the WRNM indication is used by the operator to monitor the approach to criticality and determine when criticality is achieved. The WRNM subsystem of the .Neutron Monitoring .System (NMS) consists of eight channels. Each of the WRNM channels can be bypassed, but only one at any given time per RPS trip system, by the operation of a bypass switch. Each channel includes one detector that is permanently positioned in the Each detector assembly consists of a miniature fission chamber with associated cabling, signal conditioning equipment, and electronics associated with the various WRNM functions. The signal conditioning equipment converts the current pulses from the fission chamber to analog DC currents that correspond to the count rate. Each channel also includes indication, alarm, and control rod blocks. However, *this LCD specifies OPERABILITY requirements only for the monitoring and indication functions of the WRNMs. During refueling, shutdown, and low power operations, the primary indication of neutron flux levels provided by the WRNMs or special movable detectors connected to the normal

• WRNM circuits. The WRNMs provide monitoring of reactivity changes during fuel or control rod movement and give the control room operator early indication of unexpected subcritical multiplicatiofi that could be indicative of an approach to criticality. Prevention and mitigation of prompt reactivity excursions during refueling and low power operation is provided by LCD 3.9.1, "Refueling Equipment Interlocks"; LCO 3.1.1, "SHUTDOWN MARGIN (SDM)"; LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"; WRNM Period-Short and (continued) B 3.3-37 Revision No. 17
• BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS* UN IT 3 WRNM Instrumentation B 3.3.1.2 . Average Power Range Monitor (APRM) Startup High Flux Scram Functions; and LCO 3.3.2.1, "Control Rod Block Instrumentation." The WRNMs have no safety function associated with monitoring neutron flux at very low levels and are not assumed to function during any UFSAR design basis accident or transient analysis which would occur at very low neutron flux levels. However, the WRNMs provide the only on-scale monitoring of neutron flux levels during startup and refueling. Therefore, they are being retained in Technical Speci fi cations. During startup in MODE 2, three of the eight WRNM channels are required to be OPERABLE to monitor the reactor flux level and reactor period prior to and during control rod withdrawal, subcritical multiplication and reactor criticality. These three required channels must be located in different core quadrants in order to provide a representation of the overall core response during those* periods when reactivity changes are occurring throughout the core. In MODES 3 and 4,.with the reactor shut down, two WRNM channels in two different quadrants provide redundant monitoring of flux levels in the core. In MODE 5, a spiral offload or reload, a WRNM outside the fueled region will no longer be required to be OPERABLE,. since it is not capable of monitoring netitron flux in the fueled region of the core. Thus, CORE ALTERATIONS* are . a 11 owed *in *a quadrant with no OPERABLE WRNM 1 n an adjacent quadrant provided the Table footnote {b), . * . requirement that the bundles being spiral reloaded -0r spir*l offloaded are all in a single fueled region containing at _ 1 east one *'OPERABLE WRNM is inet. Spira 1 re 1 oad i ng and offloading encompass reloading -0r offlolding a cell on.the . edge of a continuous fueled region (the cell can be reloaded or,offloaded in anj In nonspiral operations, two WRNMs are required to . be OPERABLE to provide redundant monitoring of reactivity changes in the reactor core. of the local nature of *reactivity changes refueling, is '. provided by requiring one WRNM to be OPERABLE for the . connected fuel in thequadrarit of reactor core where (continued) B 3.3-38 Revision No. 17 BASES LCO (continued) I APPLICABILITY , ACTIONS PBAPS WUl 3 WRNM Instrumentation B 3.3.1.2 CORE ALTERATIONS are being performed. There are two WRNMs in each quadrant. Any CORE ALTERATIONS must be performed in a region of fuel that is connected to an OPERABLE WRNM to ensure that the reactivity changes are monitored within the fueled region(s) of the quadrant. The other WRNM that is required to be OPERABLE must be in an adjacent quadrant containing fuel. These requirements ensure that the reactivity of the core will be continuously monitored during CORE ALTERATIONS. . Speci.al movable detectors, according to footnote (c) of Table 3.3.1.2-1, niay*be used in place of the normal WRNM nuclear detectors. These special detectors must be connected to the normal WRNM circuits in the NMS, such that the applicable neutron flux indication can be generated. These special detectors provide more flexibility in monitoring reactivity changes during fuel loading, since they can be positioned anywhere within the core during refueling. They must still meet the location requirements of SR 3.3.1.2.2 and all other required SRs for WRNMs. The Table 3.3.1.2-1, footnote (d), requirement provides for* conservative spatial core coverage. For a WRNM channel to be considered OPERABLE, it must.be providing neutron flux monitoring indication. The WRNMs are required to be OPERABLE in MODES 2, 3, 4, and 5 prior to the WRNMs reading 125E-5 % power to provide for neutron monitoring. In MODE 1, the APRMs provide adequate monitoring of reactivity changes in the core; therefore, the WRNMs are not required. In MODE 2, with WRNMs reading greater than 125E-5 % power, the WRNM Short function provides adequate monitoring and the WRNMs monitoring indication is not required.
• A.I and B.1 In MODE 2, the WRNM channels provide the means of monitoring core reactivity and criticality. With any number of the required WRNMs inoperable, the ability to monitor neutron flux is degraded. Therefore, a limited time is allowed to restore the inoperable channels to OPERABLE status. (continued) B 3.3-39 Revision No. 17 BASES ACTIONS I . I I PBAPS _ UNIT 3 -A.I and B.I (continued) WRNM Instrumentation B 3.3.1.2 Provided at least one WRNM remains OPERABLE, Required Action A.I allows 4 hours to restore the required WRNMs to OPERABLE status. This time is reasonable because there is adequate capability remaining to monitor the core, there is limited risk of an event during this time, and there is sufficient time to take corrective actions to restore the required WRNMs -to OPERABLE status. During this time, control rod withdrawal and power increase is not precluded by this Required Action. Having the ability to mon-itor the core with at least one WRNM, proceeding to WRNM indication greater than I25E-5 % power, and thereby exiting the Applicability of this LCO, is acceptable for ensuring adequate core and allowing continued operation. With three required WRNMs inoperable, Required Action B.l allows no positive changes in reactivity (control rod withdrawal must be immediately suspended) due to inability to monitor the changes. Required Action A.I still and allows 4 hours to restore monitoring capability prior to requiring rod insertion. This allowante is based on the limited risk of an event during this time, provided that no control rod withdrawals are allowed, and the desire to concentrate efforts on repair, rather_ than to immediately -shut -down, th no WRNMs OPERABLE. In if the required number of WRNMs_is not restored to OPERABLE-status w:ithin the allowed Completion Time, the reactor--shall be placed _in MODt _With all control rods fully--inserted, the-core is in its 1 east reactive state with the most margin to criticality. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to .reach.MODE 3 from fl!ll power conditions in an orderly manner and w_ithout plant --D. I and D. 2. -' -With one. Qr more required WRNMs 1rioperable in MODE 3 or* 4, -the}ieutron flux monitoring .capability> is _degraded or --,----:nonexistent. --The requirement* to 'fully insert all insertable control rods ensures that the reactor will be at its minimum react'.:ivit.Yleve_l while no ,neufr()n monitoring capability is . (continued) -B3.3-40" Revision No; 17 ... '

BASES ACTIONS SURVEILLANCE -REQUIREMENTS. PBAPS. UN IT 3 D.1 and D.2 (continued) WRNM Instrumentation B 3.3.1.2 available. Placing the reactor mode switch in the shutdown position prevents subsequent control rod withdrawal by maintaining rod block. The allowed Completion Time of 1 hour is sufficient to accomplish the Required Action, and takes into account the low probability of an event requiring the WRNM occurring during this interval. E.1 and E.2 With one or more required WRNMs inoperable in MODE 5, the ability to detect local reactivity changes in the core during refueling is degraded. CORE ALTERATIONS must be immediately suspended and action must be immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Suspending CORE ALTERATIONS prevents the two most probable causes of reactivity changes, fuel loading and control rod withdrawal, from occurring. Inserting all insertable control rods ensures that the reactor will be at its minimum rea.ctivity given that fuel is present in the core. Suspension of CORE ALTERATIONS shall not preclude completion of the movement of a component to a safe, conservative position. (once required to be initiated) to insert control rods must continue until a 11 insert ab 1 e. rods in core ce 11 s containing one or more fuel assemblies are inserted. As noted at the beginning of the SRs, the SRs for each WRNM Applicable.MODE or other specified conditions are found in the SRs column of Table 3 .3 .1.2..,;l. -* .. -. SR and SR Perfo.rmarii;:e of the CHANNEL CHECK ensures -that a . gross of has*not A CHANNEL CHECK. is normally a co-mpari son of the parameter indicated on. one channel to a simil.ar parameter on another channel. It* * . . is based on -the assumption that instrument channe 1 s monitoring the same parameter should read approximately the . . *. same value . .'Significant deviations between the instrument

• channfils .could be. an* of excessive instrument drift Jn o*ne of'. the channels or something even more serious. (continued) B-3 *. 3.:.41. Revfsion No. 17 BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 WRNM Instrumentation B 3.3.1.2 SR 3.3.1.2.1 and SR 3.3.1.2.3 (continued) A CHANNEL CHECK will detect gross charinel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. -Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including-indication and readability. If a channel is outside the criteria, it may be an indication that the iTistrument has drifted outside its limit. The Surveillance Frequency is controlled under the Surveillance Frequency Control The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO. -SR 3.3.1.2.2 To provide adequate coverage of potential reactivity changes in the core, one WRNM is required to be OPERABLE for the connected fuel in the quadrant where CORE ALTERATIONS are being performed, and the other OPERABLE WRNM must be in an adjacent quadrant fuel. Note 1 states that the SR is required to be met only during CORE ALTERATIONS. It is not required to be met at other times in MODE 5 since core reactivity chahges are not occurring. This Surveillance of a review of plant logs to ensure that WRNMs required to be OPERABLE for given CORE ALTERATIONS are, iri fact, OPERABLE. In th*e event that only one WRNM is required to be OPERABLE, per Table 3.3.1.2-1, fciotn6te Cb), only.the a: poftion of this SR is required. Note 2 clarifies that more one of the three .requirements can be met by the same OPERABLE WRNM. The Frequency is controlled under the Surveillance -Frequency Control Program. continued B -Revision No. 87-BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS WNIT 3 SR 3.3.1.2.4 WRNM Instrumentation B 3. 3 .1. 2 This Surveillance consists of a verification of the WRNM readout to ensure that the WRNM reading i.s greater than a specified minimum count rate, which ensures that the are indicating count rates indicative of neutron_ flux levels within the core. The signal-to-noise ratio shown in Figure 3.3.1.2-1 is the WRNM count rate at which there is a 95% probability that the WRNM signal indicates the presence of neutrons and only a 5% probability that the WRNM signal is the result of noise (Ref. 1). With few fuel assemblies loaded, the WRNMs wi 11 not have a hi g-h enough count rate to satisfy the SR. Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate. To accomplish this, the SR is modified by Note 1 that states that the count rate is not required to be met on a WRNM has less than or equal to four fuel assemblies adjacent to the WRNM and no fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each WRNM and no other fuel assemblies in the associated core quadrant, even with a control rod withdrawn, the configuration will not be critical. In addition, .Ncite 2 states that this requirement does not have to spiral unloading. If the core is being in this
• manner, the various core configurations encountered will-not be critical. The Surveillance Frequency is controlled under the Surveillance Frequency Contrnl Program . . SR 3.3.1.2.5 Performance of a demonstrates the a s s o c i a t e d c h a n n e l w i l l fu n ct ib n p r o p e r l y .
• S R 3 . 3 . 1 . 2 . 5 i s
• required in MODES 2, 4 and 5 and the I -are OPERABLE while core reactivity changes .could be in**
• progress. The Surveill_ance Frequency is controlled under the 1-Survei 11 ahce Frequency Control Program. .conti mied . ,f. B 3.3-43 Revision Nci ... 87 BASES SURVEILLANCE REQUIREMENTS PBAPS UN I.l 3 SR 3.3.1.2.5 (continued) WRNM Instrumentation B 3.3.1.2 Verification of the signal to noise ratio also ensures that the detectors are correctly monitoring the neutron flux. The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability (THERMAL POWER decreased to WRNM reading of 125E-5 % power or below). The SR must be performed within 12 hours after WRNMs are reading 125E-5 % power or below. The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability. Although the Surveiliance could be performed while at higher power, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the WRNMs being otherwise verified to be OPERABLE Ci .e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances. SR 3.3.1.2.6 Performance of a CHANNEL CALIBRATION verifies the performance of the WRNM detectors and associated circuitry. The Frequency considers the plant conditions required to perform the test, the ease of performing the test, and the likelihood of a change in the system or component status. Note 1 excludes the neutron detectors from the CHANNEL CALIBRATION because they cannot readily be adjusted. The detectors are fission chambers that are designed to have a relatively constant sensitivity over the range and with an accuracy specified for a fixed useful life. continued B 3.3-44 Revision No. 87

!. BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 3 WRNM Instrumentation B 3.3.1.2 SR 3.3.1.2.6 (continued) Note 2 to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours of entering MODE 2 with WRNMs reading 125E-5 % power or below. The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability. Although the Surveillance could be performed while at higher power, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the WRNMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillance. 1. NRC Safety Evaiuation Report for Amendment Numbers 147 and 149 to Facility Operating License Numbers DPR-44 and Peach Bottom Atomic Power Station, Unit Nos. 2 and 3, August .20; 1989. * '* *: .-:*,:** . ,. .. : . B 3.3-45. Revision .No. 87 .... '** , , I: . . ,.-Control Rod Block.Instrumentation B 3.3.2.1 B 3.3 INSTRUMENTATION B Control Rod Block Instrumentation BASES BACKGROUND ... *.-. . ' . :: . _, ,_ .. -. ' .' .. Control rods provide the primary means for control of reactivity changes. Control rod block instrumentation includes channel sensors, logic circuifry, switches, and relays that are designed to ensure that specified fuel design limits are not exceeded for postulated transients and accidents.. high power operation) the rod bl6ck (RBM) provides protection for control rod withdrawal error events. During power control rod the rod worth minimizer (RWM) enforce specific cont_ro l rod sequences designed to mitigate th.e consequences . of th.e _control. rod drop accident (CRDA). During shutdown

• conditions, control rod blocks from the Reactor Mode Switch -Shutdown Pas it ion Function ensure that* al 1 control rods_ remai-n i nse.rted to *prevent inadvertent crit i ca 1 it i es. The* purpose* of RBM ts to.limit control rod withdrawal if*
• 1 oca li zed neutron flux a predetermined setpoint . during control r:-od manipuJations .. It is .to function to bl*ock:further control rod withdrawal to preclude *a MCPR .. Safety (SLY viol.ation. The RBM supplies* a signal to _the. Reactor Manual Control System (RMCS) to appropriately inhibit-control durjng pciwer. operation above
• the low_ power range* setpoi_nt. The. RBM has two channels, either.of which* can inltiate a control rod block when the channe!l output exceeds<the control rod block setpoint. -One RBM channel inputs into one RMCS rod block *circuit and the _ ***other RBM .channel inputs into the second .RMCS rod block .
• cir*cu-i_t> The RBM .chatiriel signal is generated by averaging a * *. se*t o*f' J ocal: power monitor ( signals at vari,ous tore-heights** ng :.'th_e**cant ro 1 r.od *being.with drawn. A *s'ignal. from one pf-the four redundant average power rarige ..
• monito*r *(APRM) *channels?suppl ies a reference. si"gnal for: one :,of the._HBM channels* and a.* s i gna 1 from another of the APRM * ** * .* _suppli s ig.n_al tO .the second RBM .* **.;channel> This' refereQi:e -signal *is used.to d_eterniine.wh,ich _ * .RBM .. .rarige" setpoftit *pow, i ntermedi*ate*,* 'or: h.i gh) *is enabl . * .
• If thari the.Jaw-power range :
• setpoint, *the RBM is automat teal 1 y **The R8M is . *:a.ls.a 1rntomatically bypassed* if_ a peripheral control rod is'
• sehktea: (Re.f.*.:1J, A rod block si_gnal As* also if . .an*RBM :.,i nc:iperabl e. trip s i nee this could.indicate a.* pro _w_Hh:_ th_e *RsM ,chan_n:e1 *. _ . ... ** . ' --., . .. '-** ' . :_, .. _ .*. :". . -*.* (conti nu_ed) PBAPS, UNJT 3 ... * . .--* ., . .,. Revtsi on No. 30 .:.** "".* ... '*.* . . . :

BASES BACKGROUND {continued) APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS UNIT 3 . .. -Control Rod Block Instrumentation B 3.3.2.1 The inoperable trip will occur if, during the nulling {normalization) sequence, the RBM channel fails to null or too few LPRM inputs are available, i.f a critical self-test fault has been detected, or the RBM instrument mode switch is moved to any position other than "Operate". The purpose of the RWM is to control rod patterns during startup and shutdown, such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to 10% RTP. The sequences effectively limit the potential amount and rate of reactivity increase during a CRDA. Prescribed control rod sequences are stored in the RWM, which will control rod withdrawal and insert blocks when the actual sequence deviates beyond a 11 owances from the store_d sequence. The RWM determines the actual sequence based position indication for each control rod. The RWM also uses feedwater flow and -steam flow signals to determine when the reactor power is above the preset power level at which the RWM is automatically bypassed {Ref. 2). The RWM is a single channel system that provides input into both RMCS rod block circuits. With the reactor _mode switch in the shutdown position, a _ control rod withdrawal block is applied to all control rods to ensure that the shutdown condition is maintained. This Function prevents inadvertent criticality as the result of a control rod withdrawal during MODE 3 or or during MODE 5 when the reactor mode switch is required to be in the shutdown position. The reactor mode switch has two channels; each inputting into a separate RMCS rod block -A rod block in.either RMCS circuit will provide a control-rod block to all'tontrol rods; -1. Rod Block Monitor The RBM is designed of the MCPR SL and the cladding 1% plastic strain fuel design limit that may result from a single control rod withdrawal error {RWE) event. The analytical methods and assumptions used in evaluating the RWE event are summarized in Reference 1. A (continued) B 3.3-47 -Revision No._31 _ ** .* . . \ BASES APPLICABLE

• SAFETY ANALYSES, LCO, and
• APPLICABILITY PBAPS UNIT 3 Control Rod Block Instrumentation B 3.3.2.1 1. Rod Block Monitor (continued) statistical analysis of RWE events was performed to determine the RBM response for both channels for each event. From these responses, the fuel thermal performance as a function of RBM Allowable Value was determined. The Allowable Values are chosen as a function of power level. The Allowable Values are specified in the CORE OPERATING LIMITS REPORT {COLR). Based on the specified Allowable Values, operating limits are established. The RBM Function satisfies Criterion 3 of the NRC Policy Statement. Two channels of the RBM are required to be OPERABLE, with their setpoints within the appropriate Allowable Values to ensure that no single instrument failure can preclude a rod block from this Function. The actual setpoints are calibrated. consistent with applicable setpoint methodology; Trip setpoints are in the setpoint calculations. The trip setpoints are selected to ensure that the setpoints do not exceed the Allowable Values between successive CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than. the trip setpoint; but within .its Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an .action should take place. The setpoints are compared to the actual process parameter (e.g., reactor power), and when measured output value of the process parameter exceeds the setpoint, the associated device trip unit) changes. state. The analyt,ic or design limits are derived from the limiting values of the process parameters obtained from the' safety analysis or other appropriate *documents. The
• Allowable Values are derived from analytic or design limits, corrected for calibration, process, and instrume*nt errors. The trip setpoints are determined from analytical or design limi_ts, corrected for calibration, process, and instrument errors, as well as,. instrument drift. In . selected cases, the Allowable Va.lues and trip setpoints .are determined by engineering judgement or historically accepted practice relative to the intended function of the channel. The tr1p setpoints determined in this manner provide . adequate protection by assuring instrument and process. uncertainties for the,environments during the operating time of the channel.s are accounted for. . C con ti niaed l
• B 3 .3-48 Revi sio*n No.* 3 _I BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS. UN It 3 Control Rod Block Instrumentation B 3.3.2.l 1. Rod Block Monitor (continued) The RBM is assumed to mitigate the consequences of an RWE event when 30% RTP. Below this power level, the consequences of an RWE event will not exceed the MCPR SL and, therefore, the RBM is not required to be OPERABLE (Ref. 1). When operating< 90% RTP, analyses (Ref. 1) have shown that with an initial MCPR 1.70, no RWE event will result in exceeding the MCPR SL. Also, the analyses demonstrate that when operating at 90% RTP with MCPR 1.40, no RWE event will result in exceeding the MCPR SL (Ref. 1). Therefore, under these conditions, the RBM is also not required to be OPERABLE. 2. Rod Worth Minimizer The RWM enforces the analyzed rod position sequence to *ensure that the initial conditions of the CRDA analysis are not violated. The analytical methods and assumptions used in evaluating the CRDA are summarized in References 3, 4, 5, and 11. The analyzed rod position sequence requires that control rods be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions. Requirements that the rod sequence is in compliance with the analyzed rod position seque.nce are specified in LCO 3.1.6, "Rod Pattern Control." When performing a shutdown of the plant, an optional control rod sequence (Ref. 11) may be used if the coupling of each withdrawn control rod has been confirmed. The rods may be inserted without the need to stop at intermediate positions. When using the Reference 11 control rod insertion sequence for shutdown, the RWM may be reprogrammed to enforce the requirements of the improved control rod insertion process, or may be bypassed and the improved control rod shutdown sequence implemented under.the controls in Condition D. The RWM Function satisfies Criterion 3 of the NRC Policy Statement. Since the RWM is a hardwired system designed to act as a backup to operator control of the rod sequences, only one channel of the RWM is available and required to be OPERABLE (Ref. 6). Special circumstances provided for in the Required Action of LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.6 may necessitate bypassing the RWM to allow continued operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the analyzed rod position sequence. The RWM may be bypassed as required by these conditions, but then it must be considered inoperable and the Required Actions of this LCO fo 11 owed. continued B 3.3-49 Revision No. 64 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY Control Rod Block Instrumentation B 3.3.2.1 2. Rod Worth Minimizer (continued) Compliance with the analyzed rod position sequence, and therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is < 10% RTP. When THERMAL POWER is> 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Refs. 4 and 6). In MODES 3 and 4, all control rods are required to be inserted into the core; therefore, a CRDA cannot occur. In MODE 5, since only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SOM ensures that the of a CRDA are acceptable, since the reactor will be subcritical. 3. Reactor Mode Switch-Shutdown Position During MODES 3 and 4, and during MODE 5 when the reactor* mode switch is required to be in the shutdown position, the core is assumed to be subcritical; no positive reactivity insertion events are analyzed .. The Reactor Mode Switch-Shutdown Position .control .rod withdrawal block that the reactor remains subcritical by blocking control rod withdrawal, thereby. preserving th.e assumptions of the
• The Reattor Mode *Position Function Criterion 3 the NRC Policy Two are required to be.OPERABLE to that no sh1gl e channel. fai fore will preclude a rod block when *required. Th.ere is no Allowable Value for:this Function are mechanically actJated based solely on reactor mode switch, on: . . . . -Our1 ng. conditidns .C MODE 3, 4, or 5), no .positive . . rea.ct.ivity. i'nse*rtion .events; are analyzed becau.se assumptions are that controi rod withdrawal' blocks a re provided to prevent when the react6r mode switch. is in the shutdown position, the control rod withdrawal block is to be OPERABLE. During *MODE 5 with .the-* reactor* mode switch in the refueling position, the . refuel .po.sitio"n.one-rod-out. interlockCLC0-3.9.2, "Refuel. ** ;Position One-Rod"Out Interfock") provides.the required control rod blocks. .... * ,, .* .. _-.. ... (continued) PBAPS UNIT -3
• B 3.3-50 Revision No. 64 Control Rod Block Instrumentation B 3.3.2.I BASES (continued) ACTIONS A.I With one RBM channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod block function; however, overall reliability is reduced because a single failure in the remaining OPERABLE channel can result I* in no control rod block capability for the RBM. For this : reason, Required Action A.I requires restoration of the PBAPS UNIT 3 inoperable channel to OPERABLE status. The Completion Time *of 24 hours is based on the low probability of an event occurring coincident with a failure in the remaining OPERABLE channel. If Required Action A.I is not met and the associated Completion Time has expired, the inoperable channel must be placed in trip within I hour. If both RBM channels are inoperable, the RBM is not capable of performing its intended function; thus, one channel must also be placed in trip. This initiates a _control rod withdrawal block, thereby ensuring that the RBM function is met. The I hour Completion Time is intended to the time to evaluate and repair any inoperabilities and is acceptable because it minimizes risk while allowing time for restoration or tripping of 1noperable channels. C.I, C.2.I.I, C.2.1.2. and C.2.2 -Wi'th the RWM inoperable* during a reactor startup, the operatcir is still of enforcing the *prescribed cont ro 1 rod. sequence .. -f:lowever, the ov_era 11 rel i ability is reduced because a result in .violati_ng the control rod.sequence. Therefore, control rod movement must be immediately suspended except by scram . . Alternatively, startup inay:continue if at least I2 control* rods have al ready-been_ withdrawn, or a reactor. startup with an inoperable RWM was not pe_rformed i 11 the 1 ast 12 months. -These .requirements minimize the number of reactor startups initiated with the RWM -Required Actions C.2.1.I and. C_.2d.2 require of the$e conditions by -review_ QT plant *Togs and c.ontrol room _indications. Once Require:<J Action C.2.Ll or C.2.1.2 _is satisfactorily Ccontiriued) *s 3.3-sr Revision'* 3 . i BASES ACTIONS PBAPS UN IT. 3 Control Rod Block Instrumentation B 3.3.2.1 C.l. C.2.1.1. C.2.1.2. and C.2.2 {continued} completed, control rod withdrawal may proceed in accordance with the restrictions imposed by Required Action C.2.2. Required Action C.2.2 allows for the RWM Function to be performed manually and requires a double check of compliance with the prescribed rod sequence by a second licensed operator {Reactor Operator or Senior Reactor Operator} or other qual Hied member of the technical staff.* The RWM may be bypassed under these c.onditions to allow continued -operations. In addition, Required Actions of LCO 3.1.3 and LCO 3.1.6 may require bypassing the RWM, during which time the RWM must be considered inoperable with Condition C entered and its Required Actionstaken. With the RWM inoperable during a reactor shutdown, the operator is still capable of enforcing the prescribed control rod sequence. Required Action. D.l allows for the RWM Function to be performed manually and requires a double check of comp 1 i ance with the prescribed rod sequence by a
• second licensed operator {Reactor Operator or Senior Reactor Operator} or other qualified member of* the technical staff. The RWM may be bypassed under these conditions to allow the reactor shutdown to continue. E. l and E. 2 *
• With one-Reactor Mode Switch-Shutdown Position control rod withdrawal block channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod withdrawal black function. However, since the Actions are consistent with the normal action of an OPERABLE Reactor Mode Switch -Shutdown Position Function {i.e., ma i nta i ni ng . all control rods inserted}, there is no distinction between having one or two channels inoperable.* In both cases {one or both channels inoperable}, suspending all control rod withdrawal and initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies will ensure that the core is
• subcritical with adequate SDM ensured by LCO 3.1.1. Control rods in core containing no fuel assemblies do not * (continued) B 3.3-.52 Revision 3 *.

BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS. UNIT 3 E.1 and E.2 (continued) Control Rod Block Instrumentation B 3.3.2.1 affect the reactivity of the core and are therefore not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. As noted at the beginning of the SRs, the SRs for each Control Rod Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1. The Surveillances are modified by a Note to indicate that when an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains control rod block capability. Upon tompletion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 8, 9, & 10) assumptions of the average time required to perform channel surveillances. That analysis demonstrated that the 6 hour testing all.owance does not significantly reduce the probability that a control rod block will be initiated wheD necessary. -SR 3.3.2.1.1 A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will perform the intended . Ariy setpoint adjustment shall the assumpti ems .of the* current pl ant speCi fi c set point The Surveillance Frequency.is controlled under -.. I t he S u r v e i'l l a n c e F r e q u en cy Co n t r o l . P r o g r am . conti hued B 3 .. 3-53 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 3 Control Rod Block Instrumentation B 3.3.2.1 SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform the intended function. The CHANNEL FUNCTIONAL TEST for the RWM is performed by withdraw1ng a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs. It is permissible to simulate the withdrawn control rod condition into the RWM in order to verify a control rod block occurs. SR 3.3.2.1.2 is performed during a startup and SR 3.3.2.1.3 is performed during a shutdown (or power reduction to s 10% RTP). As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until 1 hour after any control rod is withdrawn at s 10% RTP in MODE 2. As noted, SR 3.3.2.1.3 is not required to be performed until 1 hour after THERMAL POWER is s 10% RTP in MODE 1. This allows entry at$ 10% RTP in MODE 2 for SR 3.3.2.1.2 and entry into MODE 1 when THERMAL POWER s 10% RTP for SR 3.3.2.1.3 to perform the required Surveillance if the Frequency is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete SRs. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.2.1.4 The RBM setpoints are automatically varied as a function of power. Three Allowable Values are in the COLR, each within a specific power range. The power at which the control rod block Allowable Values automatically change are based on the APRM signal's input to each RBM channel. Bel ow the minimum power setpoint, the RBM is automatically bypassed. These power Allowable Values must be verified using a simulated or actual signal periodically to be less than or equal to the specified values. If any power range setpoint is nonconservative, then the affected RBM channel is considered inoperable. Alternatively, the power range continued B 3.3-54 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS -...

• PBAPS UNIT J -" .. SR 3.3.2.1.4 (continued) Control Rod Block Instrumentation B 3.3.2.1 c h a n n e l ca n b e p l a c e d i n th e co n s e r v a t i v e con d i t i o n ( i . e . , enabling the proper RBM setpoint). If placed in this condition, the SR is met and the RBM channel is not considered inoperable. As noted, neutron detectors are excluded from the Surveillance because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.2.1.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account fo( instrument drifts between successive calibrations consistent.with the specific setpoint methodology. As noted, neutron detectors are excluded from the CHANNEL CALIBRATION bec.ause they are passive devices, with minimal drift, the di1ficulty of simulating a meaningful signal. -Neutron detectors are adequately tested *in SR J:j.1;1:2 and SR 3.3.1.1.8. *The Surveillance controlled under the Surveillance Frequency Control-Program.** continued *' -*. ,*, .. **, . -:._. _; , .. :* *B 3. 3-55 Revision No .. 87 I BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 3 SR 3.3.2.1.6 Control Rod Block Instrumentation B 3.3.2.1 The RWM is automatically bypassed when power is above a specified This automatic action can itself be bypassed to allow for control rod sequence enforcement up to 100% RTP. The power level is determined from feedwater flow and steam flow signals. The automatic bypass setpoint must be verified periodically to be> 10% RTP. If the RWM low power setpoint is nonconservative, then the RWM is considered inoperable. Alternately, the low power setpoint channel can be placed in the conservative condition Cnonbypass). If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable. The Surveillance Frequency is under the Frequency Control Program. SR 3.3.2.1.7 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switth-Shutdown Position Function to ensure.that the entire channel will perform the intended function. The CHANNEL FUNCTIONAL TEST for the Reactor Switch-Shutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown positibn and veriiying a control rod block occurs. As noted in the SR, the Surveillance is not required to be performed until 1 hour after reactor mode switch is in the shutdbwn position,. since testing of this interlock with the reactor mode switch*in any other cannot be using jumpers, lifted leads, or movable This allows entry into MODES 3 and 4 *if the Frequency is not per SR 3.0.t'. Jhe l hour allowance is based on operating experience and '.iri' consideration of providing a reasbnabl e time in whi*ch Jo complete the s*R.
• continued . :** *-*'. Revis.ion No. 87 I BASES SURVEILLANCE REQUIREMENTS . REFERENCES PBAPS UN IT 3 Control Rod Block .Instrumentation B 3.3.2.1 SR 3.3.2.1.7 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.2.1.8 The RWM wi 11 oril y enforce the proper control rod sequence if the rod sequence is properly input into the RWM computer. This SR ensures that the proper sequence is loaded into the RWM so that it can perform its intended function. The Surveillance is performed once prior to declaring RWM OPERABLE following loading of sequence into RWM, since this is when rod sequence input errors are possible. 1. NEDC-32162-P, "Maximum Extended Load Line Limit and ARTS Improvement Program Analysis for Peach Bottom Atomic Power Station, Units 2 and 3," Revision 1, February 1993 .. 2. UFSAR, 7.10.3.4.8 and 7.1&.3. 3. NEDE-24011-P-A, "General Electric Standard Application *for Reactor Fuel," latest approved revision. 4. "Modifications to the Requirements for*control Rod Drop Accident Mitigating Systems," BWR Owners' Group, *Julyl986 .. . 5. NED0-21231, "Banked Position Withdrawal Sequence," *.January 1977. 6. NRC SER, "Acceptance of Referencing of Licensing Top i ca l Rep o rt N ED E -24 011 -P -A , " " Gen e r a 1 E l e ct r i c Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 1987. continued B 3.3-57 Revision No. 87* I BASES REFERENCES * (continued) I PBAPS UNIT 3. 7. Control Rod Block Instrumentation B 3.3.2.1 NEDC-30851-P-A, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation," October 1988. 8. GENE-770-06-1, "Addendum to Bases for Changes ta* Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991. 9. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function", March 1995. 10. NEDC-32410P Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function, Supplement 1", November 1997. 11. NED0-33091-A, "Improved BPWS Control Rod Insertion Process," Revision 2, July 2004 . B 3.3-58 Revision No:. 62 ___ ___J

. , ---:: ' .. ". ------------------Feedwater and Main Turbine High Level Trip Instrumentation B 3.3.2.2 B 3.3 INSTRUMENTATION B Feedwater and Main Turbine High Water Level Trip Instrumentation BASES BACKGROUND ... PBAPS UNIT 3 .* The feedwater and main turbine high water level trip instrumentation is designed to detect a potential failure of the Feedwater Level Control System that causes excessive feedwater fl ow. With excessive feedwater flow, the water level in the reactor vessel rises toward the high water level setpoint, causing the trip of the three feedwater pump turbines and

• the main turbine. Digital Feedwater Control System (DFCS} high water level *signalS are provided by six level sensors. However, only
• three narrow range level sensors are required to perform the function with sufficient redundancy. The three level sensors sense.the difference between the pressure due to a . constant column of water (reference leg} and the pressure due to the actual water level in the reactor vessel (variable leg}. The three level signals are input into two redundant digital control computers. Any one of the three signals is automatically selected (by the digital control computer} as the signal to be used for the high level trip. Each digital control computer has two redundant digital outputs (channels) to provide redundant to an associated trip system .. Each* digital control computer processes input signals and compares them to pre-established setpoints. When the setpoint is exceeded, the two digital outputs actuate two contacts arranged in parallel so that either digital output can trip the associated trip system. The tripping of both digital computer trip systems will initiate a trip of the feedwater pump turbines and the main turbine.
• A trip of the feedwater pump turbines limits further . increase in reactor vessel water level by limiting further addition ot feedwater to the reactor vessel. A trip of the 'main tLlrbine and closure of the stop valves protects the turbine from damage due to water entering the turbine. (continued} B 3 .. 3-59 . Revision No. 3 Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES (continued) APPLICABLE SAFETY ANALYSES The feedwater and main turbine high water level trip instrumentation is assumed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1). The high water level trip indirectly initiates a reactor scram from the main turbine trip (above 26.7% RTP) and trips the feedwater pumps, thereby terminating the event. The reactor scram mitigates the reduction in MCPR. LCO PBAPS UNIT 3. Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy Statement.* The LCO requires two DFCS channels per trip system of high water level trip instrumentation to be OPERABLE to ensure the feedwater pump turbines and main turbine will trip on a v a l i d reactor v es s e:1 hi g h w ate r l eve l s i g n a l . Two D F CS channels (one per trip system) are needed to provide trip in order for the feedwater and main turbine trips to occur. Two level signals are required to ensure a single sensbr failure will not prevent the trips of the feedwater and turbine when reaitor vessel water level i*s at the* high water level reference point. Each channel musf have its setpoint se_t within the speci.fied Allowable. Va-lue of SR. 3.3.2.2.3. The Allowable Value is set to ensure that the thermal limits are not exceeded during the. everit, The actual setpoi nt Js calibrated to be consistent the methodology assumpti ans .. Trip* setpoi.nts a re specified i°n the setpoi nt * ** selected to ensure ... . *that the setpoi rits do not exceed _the Allowable Value successive. CALIBRATIONS.*. Operation with a* trip_ 'setting less .conservative than the trip setr;>oint, but within its Allowal:i"l.e Value, .is acceptable.
• Trip set poi hts a {e those predetermined values of output at which an 'action. should take place, The setpoints are . compared process .parameter reactor vessel water:: level), and whe_n the measured *output value of .the pr.oce:ss parameter.-exceeds t'he setpoint, the associated ";-device (e.g.*; trip .unit) changes state. Th.e analytic or design __ lfmits are der.ived from the. limiting values of t_he obtained;from the safety analysis:or-* **continued B 3.3-60 Revision No. 119 BASES LCO (continued). APPLICABILITY ACTIONS PBAPS UN°IT 3 *.* Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for calibration, process, and instrument errors. A channel is inoperable if its actual trip setting is not within its required Allowable Value. The trip setpoints are analytical or design limits, corrected for calibration, process and instrument errors, as well as, instrument drift. The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected the environment during the operating time for the associated channels are accounted for. The feedwater and main turbine high water level trip instrumentation is to be OPERABLE at 23% RTP to ensure that the fuel cladding integrity Safety Limit and the 1% plastic strain limit are not violated during the .feedwater controller failurf, maximum demand event. As discussed in the Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)," and LCO 3;2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)," sufficient margin.to these limits exists below 23% RTP; these*requirements only necessary when at or above this power level. A Note been provided t6 modify the ACTIONS related to and main turbine high water level.trip instrumentation channels. Section 1.3, Completion Times, that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the discovered. to.be inoperable or .not within limits', wlll not result. in. separate entry into the Condition. Secti.on l.3 als.o. specifies that Required Actions of theCondition.contiriueto. apply for e*ach addit'ional. failure, with Comp1eti6n Times based on entry into the the* Required Actions for inoperable .fe"edwater.,ahd main turbine high water*levei*.trip compensatory .measures for separate*.inoperable channels .... As sUch*, aNote . has been provided. that allows*separate'.CondH1on entry for* each .inoper.abl e ** feedwater and main turbine hi*gh viater 1 evel *trip instrumentation channel .. continued '_-.. -. *' ,-: *.*. B 3.3--61 Revision No: 119 BASES Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 ACTIONS A.I (continued)
• UNIT 3 .-., With one or more feedwater and main turbine high water level trip channels inoperable, but with feedwater and main turbine high water level trip capability maintained {refer to Required Action B.l Bases), the remaining OPERABLE channels can provide the required trip signal. However, overall instrumentation reliability is reduced because a single active instrument failure in one of the remaining channels may result in the instrumentation not being able to perform its intended function. Therefore, continued operation is only allowed for a limited time with one or more channels inoperable. If the inoperable channels cannot be restored to OPERABLE status within the Completion Time, the channels must be placed in the tripped condition per Required Action A.l. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single active instrument failure, and allow operation to continue with no further Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in the feedwater and main turbine trip); Condition C must be entered and its Required Action taken.
• The Completion Time of 72 hours is based on the low probability of the event occ_urring coincident with a single failure in a remaining OPERABLE channel. Required Action B.l is intended to *ensure that appropriate ictions are taken if multiple, inoperablei untripped result in the High Water Level Function of DFCS not maintaining feedwater and main turbine trip capability. In this condition, the feedwater and main turbine high water level trip cannot perform its design function. Therefore, continued operation is only permitted for a 2 hour period, during which feedwater and main turbine high water level trip capability must be restored. The trip capability is considered maintained when sufficient channels are OPERABLE or in trip such that the feedwater and main turbine high water level trip logic will generate a trip {continued) *,. Revision No .. 3 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UN IT. 3 Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 .8_,_l (continued) signal on a valid signal. This requires one channel per trip system to be OPERABLE or in trip. If the required channels cannot be restored to OPERABLE status or placed in trip, Condition C must be entered and its Required Action taken. The 2 hour Completion Time is sufficient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of feedwater and main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 hour Completion Time provided in LCO 3.2.2 for Required
• Action A.l, since this instrumentation's purpose is to preclude a MCPR violation. C.l and C.2 With any Required Action and associated Completion Time not met, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 23% RTP within 4 hours. Alternatively, the affected feedwater pump(s) and affected main turbine valve(s) may be removed from service since this performs the intended function of the instrumentation. As discussed in the Applicability section of the Bases, operation below 23% RTP results in suffitient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand The allowed . Completion Time o_f 4 _hours is based ori operating experience* to reduce THERMAL POWER to< 23% RTP from full power I conditions iD an orderly manner and without pl ant systems. * : . . Required Action C.l is modified by a Note which states that the Required Action is only applicable if the inoperable .channel is the of an inoperable feedwater pump turbine or main turbine stop valve. The Note clarifies the situations under which the associated Required Action would be the appropriate Required Acti6n. The Surveillances are by a Note to that when a channel is *placed in an inoperable status solely for performance of required Surveillances; entry into
• Conditions and Required Actions may be delayed for up to.
• 6 hours provided the associated Functioh maintains feedwater. and main t0rbi.ne water level' trip capability. Upon completiori of *the Surveillance, or expiratiori of the 6 a l l ow a h c e , t h e c h an *n e l mu s t be
• re t u r n e d t o 0 P ERA B LE s t a tu s : . or.the applicable Condition entered and Required Actions This Note based on the reliability analysis . (Ref. 2) of the average time required to cont 1 riued . ** B 3.3-63 Revision No. 119 BASES SURVEILLANCE REQUIREMENTS (continued)
• PBAPS *UN IT 3 Feedwater and Main Turbine Water Level Trip Instrumentation B 3.3.2.2 channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the feedwater pump turbines and main turbine will trip when necessary. SR 3.3.2.2.1 Performance of the CHANNEL CHECK once every 24 hours ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. The CHANNEL CHECK may be performed by comparing i ndi ca.ti on or by verifying the absence of the DFCS "TROUBLE" alarm in the control room. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drtft in one of the channels, or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limits. The Surveillance Frequency is controlled under the Surveillance FrequenGy Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with the channels required by the LCD. SR 3.3.2.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.3-64 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES "*. ._ ... PBAPS UN IT 3 Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 SR 3.3.2.2.3 CHANNEL CALIBRATION is a complete check of the instrument. loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between calibrations, consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.2.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILiTY of the required trip logic for a. specific channel. The system functional test of the feedwater and main turbine stop valves is included as part of this Surveillance and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete of the assumed safety function. Therefore, if a stop valve.is incapable of operating, the associated instrumentation channe.ls would be inoperable. The Surveillance Frequency is controlled under the Surveillance_ Frequency Control Progra*rri. L-UFSAR, Section 14.5.2.2. 2. GENE-'770-06-1, ;'Bases for Changes to *surveillance Test Intervals.and Allowed Times for .Selected: Instrumentation Technical Specifications," February-1991.* --' -.* .. -. '( B3.3-65 Revision No. 87

-' .PAM Instrumentation B 3.3.3.1 B 3.3* INSTRUMENTATiON B 3.3.3.1 Post Accident Monitoring (PAM} Instrumentation BASES BACKGROUND APPLICABLE The primary purpose of the PAM instrumentation is to display plant variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is *provided and that are required for safety systems to their safety functions for Design Basis Events.

• The instruments that monitor these .variables are designated as Type '.A, Category C and non-Type A, Category I, in accordance with Regulatory Guide 1.97 1). The OPERABILITY of the .accident monitoring instrumentation ensures that there.is sufficient information.available on plant parameters to monitor and assess plant status and behavi6r following accident .. This capability is consistent with the recommendations of Reference 1. . SAFETY: ANALYSES . The. PAM *instrumentation .i.co ensures the .OPERABILITY of Regulatory Guide Type A variables so that the control . room operating* staff can: *'** '* ... **: .... ;*:**-:**
• h * * *' : '*. ,. . : ',. . . -.. --. PBAP_S UN IT 3 * ... **: * .Perform the diagnosis specified in the.Emergency" Operating* Procedures' (EOP_s}. These variables are . * .. restr.i cted to. prepl anried act ions: for<the primary
• path Basis Accidents .(DBAs}, (e.g.,
• loss of co*o1 ant acddent (LOCA}}, and _ _-* , ..... _* manually controlled* . control is provided,** * '*.***which 'are*required;fri'r *safety. systems to accomplish * ** .*. * * * * * * ** .. , . . PAM:* tco a:l so .ensures OPERABILiTY of . Categciry'.' I,° Type v*ari ab Jes so. that the control room ' opera:t ' * .. * < .* .: .* ' . . . " .. ** ... :-. ne *'whether: systems i to safety are ' per.foririi ng tl:!eir i_ntended furicti ons; '* . . . . *:.* . . *, '. .. . -: ... .-' .. *.:-,..-.*:-: *. , .. , . -... ** , . **.-.-***:* -.. ,.:*'" : . ** ... *,( . . . . . " *.* ... : .. ,* ' ( con't.i nued l .. ,.** ,_, -* * .. --;*-:.

BASES PAM Instrumentation B 3.3.3.l APPLICABLE

• Determine the potential for causing a gross breach of the barriers to radioactivity release; SAFETY ANALYSES (continued) LCO PBAPS UNIT. 3.
• Determine whether a gross breach of a barrier has occurred; and
• Initiate action necessary to protect the public and for an estimate of the magnitude of any impending threat. The plant specific Regulatory Guide 1.97 Analysis (Refs. 2, 3, and 4) documents the process that identified Type A and Category I, non-Type A, variables.
• Accident monitoring instrumentation that satisfies definition of Type A in Regulatory Guide 1.97 meets Criterion 3 of the NRC Policy Statement. Category I, non-Type A, instrumentation is retained in Technical Specifications (TS) because they are intended to assist operators in minimizing the consequences of accidents. Therefore, these Category I variabl.es are important for *reducing public risk. LCO 3.3.3.l requires two OPERABLE channels for all but one Function.to ensure that.no single failure prevents the operators from being presented with the information *necessary to determine the status of the plant and to bring the plant to, and maintain it in, a safe condition following that accident. Furthermore, provision of two channels* allows a CHANNEL CHECK during the post accident to confirm the validity of c:lisplayed information.
• The exception to the two channel requi_rement is primary containment isolation valve (PCIV) position. In this case,
• the important information is the status of the primary containment penetrations. The LCO requires one position indicator for each active PCIV. This is sufficient to *redundantly verify the isolation status of each isolable penetration either via status of the active valve and prior knowledge of passive valve or via system boundary status. If* a normally active PCIV is known to be closed and deactivated, position indication is not needed to determine status. Therefore, the position indication for valves in this state is not required to be OPERABLE. . {continued) ...
• B 3 "3-.67 Revision 3* . *'

r -------------------------------------------I BASES LCO {continued) PBAPS UNIT 3 PAM Instrumentation B 3.3.3.1 The following list is a discussion of the specified instrument Functions listed in Table 3.3.3.1-1 in the accompanying LCO. 1. Reactor Pressure Instruinents: PR-3-2-3-404 A, B Reactor pressure is a Category I variable provided to support monitoring of Reactor Coolant System {RCS) integrity and to verify operation of the Emergency Core Cooling Systems {ECCS). Two independent pressure transmitters with a range of 0 psig to 1500 psig monitor pressure and associated independent wide range recorders are the primary indication used by the operator during an acci_dent. Therefore, the PAM Specification deals specifically with this portion of the instrument channel. 2. 3. Reactor Vessel Water Level (Wide Range and Fuel Zone) Instruments: Wide Range: LR-3-2-3-110 A, B {Green Pen) Fuel Zone: LR-3-2-3-110 A, B (Blue Pen) Reactor vessel water level is a Category I variable provided to support.monitoring of core cooling and to verify operation of the ECCS.. The wide range and fuel zone water level channels provide the PAM Reactor Vessel Water Level Functions. The ranges of the wide range water level channels and the fuel zone water level channels overlap.to cover a range of inches {just below the bottom of the active fuel) to +50 inches {above the normal water level). Reactor vessel water level is measured by separate. differential pressure*transmitters. The output from these channels is recorded on two independentpen*recorders, which is the primary .indication used by the operator during an accident. . Each recorder .has two channels, one for wide. range reactor vessel water level and one for fuel zone reactor vessel water .level. Therefore, the PAM Specification deals specifically with these portions of the

• instrument charinels .. {continued) B 3.3-68 Revision No. 7 BASES LCO {continued) PBAPS UNIT 3 PAM Instrumentation B 3.3.3.1 4. Suppression Chamber Water Level CWide Range) Instruments: LR-9123 A, B Suppression chamber water level is a Category I variable provided to detect a breach in the reactor coolant pressure boundary {RCPB). This variable is also used to verify and provide long term surveillance of ECCS function. The wide range suppression chamber water level measurement provides the operator with sufficient information to assess the status of both the RCPB and the water supply to the ECCS. The wide range water level recorders monitor the suppression
• chamber water level from the bottom of the ECCS suction lines to five feet above normal water level. Two wide range suppression chamber water level signals are transmitted from separate differential pressure transmitters and are continuously recorded on two recorders in the control room. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel. 5, 6. Drywell Pressure (Wide Range and Subatmospheric Range) Instruments: Wide Range: PR-9102 A, B {Red Pen) Subatmospheric Range: A, B {Green Pen) Drywell pressure is a Category I variable provided to detect breach of the RCPB and to verify ECCS functions that operate to maintain RCS integrity. The wide range and subatmospheric range drywell pressure channels provide the PAM Drywell Pressure Functions. The wide range and subatmospheric range drywell pressure channels overlap to cover a range of 5 psia to 225 psig (in excess of four times the design pressure of the drywell). Drywell pressure signals are transmitted from separate pressure transmitters and are continuously recorded and displayed on two independent control room recorders. Each recorder has two channels, one for wide range drywell pressure and one for subatmospheric range drywell pressure. These recorders are .. the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with these portions of the instrument channels. (continued) B 3.3-69 Revision No. 3 BASES LCO (continued) PBAPS UN tr*3 7. Drywell High Range Radiation Instruments: RR-9103 A, B (Green Pen) PAM Instrumentation B 3.3.3.1 Drywell high range radiation is a Category I variable provided to monitor the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. Post accident drywell radiation levels are monitored by four instrument channels each with a range of 1 to lxl08 R/hr. These radiation monitors drive two dual channel recorders located in the control room. Each recorder and the two associated channels are in a separate division. As such, two recorders and two channels of radiation monitoring instrumentation (one per recorder) are required to be OPERABLE for compliance with this Therefore, the PAM Specification deals specifically with these portions of the instrument channels. 8. Primary Containment Isolation. Valve CPCIV) Position PCIV position is a Category I variable provided for verification of containment integrity. In the case of PCIV positiori, the information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be ORERABLE for each active PCIV in a containment penetratibn flow path, i.e., two fatal channels of PCIV . positibn indicatiori for a penetration flow path with two active. valves.* For containment penetrations with only one active PCIV having c6ntrol room indication, Note Cb) . single channel of valve position indication to be This is sufficient to redundantly verify the isolation itatus of each isolable penetration via indicated status 9f the active valve, as ahd prior
• knowledge of passive valve or system boundary .status. If a pe}1etr9tion flow path is isol.ated*, position indication for the iri the associated penetratiori flow path is not needed; to .determine status ... Therefore,* the position
• indication for v.alve.s in.an isolated penetration flow path is ncit required to be OPERABLE. The *PCIV position PAM i on consists of position switches, *associated wiring* and control room i ndi ca ting 1 amps for* active PCiVs *.. (qheck valves ahi;I manual valves .are hot required to have. *position ihdication). Therefore, the PAM Specificatfon deals specifically with these instrument channels. . Each p e*n et rat i on i s 't re a t e d s e p a r a t e 1 y a n d e a c h pen et r a ti on flow patn i:*s consi d.ered a .. sepa,rate function.* *Therefore,* -separate"'condition entry is allowed for* each inoperable penetration flow path. * * .... -* 83.3-70. Revision No .. 58 BASES LCO (continued) PBAPS UNIT 3 9. 10. Deleted PAM Instrumentation B 3.3.3.1 11. Suppression Chamber Water Temperature Instruments: TR-9123 A, B TIS-3-2-71 *A, B Recorders Suppression chamber water temperature is a I variable provided to detect a condition that could potentially lead to coniainment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression chamber water temperature allows operators to detect trends in suppresiion chamber water temperature in sufficient time to take action to prevent quenching in the chamber water temperature is monitored by twq redundant Each is -as.signed to a. s*e*par9te:s*ateguard power-division. Each channel of. ll {RTDs) mbunted in chamber. shell .tiel ow the mini mum water level-. a processor' and control room recorders.
• The RTDs a re mounted in each of .* 13 o.f the 16 segments of the suppression The RTD * (continued} *Revision No. 56 BASES LCD (continued) APPUCAB I LITY ACTIONS PBAPS UN IT 3 PAM Instrumentation B 3.3.3.l inputs are averaged by the processor to provide a bulk average temperature output to the associated control room The allowance that only 10 RTDs are required to be OPERABLE for a channel to be considered OPERABLE provided no 2 adjacent RTDs are inoperable is acceptable based on engineering judgement considering the temperature response profile of the chamber water volume for previously analyzed events and the most challenging RTDs inoperable .. These recorders are the primary indication.used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channels. recorders are provided. A
• recorder in each division is required to be OPERABLE to satisfy the LCD. The PAM instrumentation LCD is applicable in MODES 1 and 2. These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1 and 2. In MODES 3, 4, and 5, plant conditions are such th-at the likelihood of an event that would require PAM instrumentation is extremely low; therefore, PAM instrumentation is not required to be OPERABLE in these MODES. . A Note has been provided to modify the ACTIONS related to PAM instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, compcihents, or expressed in the Condition to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion based on initial entry int6 the Condition. However, the Required Actions for continued B 3,3-72 *Revision No. 53* .***
• .*.: BASES Actions (continued) PBAPS UNIT. 3
• PAM Instrumentation B 3.3.3.1 inoperable PAM instrumentation channels provide appropriate compensatory measures for separate Functions. As such, a Note has been provided that allows separate Condition entry for each inoperable PAM Function. When one or more Functions have one required channel that is inoperable, the required inoperable channel must be restored to OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channels (or, in the case of a Function that has only one required channel, other non-Regulatory Guide 1. 97 instrument channels to monitor the Function), the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval. If a channel hasnot been restored to OPERABLE status in 30 days, this Required Action specifies initiation of action in accordance with Specification 5.6.6, which requires a written report to be submitted to the NRC. This report discusses results of the root cause evaluation of the inoperability and identifies restorative actions: This acti-0n is appropriate in lieu-of a requirement, since alternative actions are identified before loss of functional capability, and given the likelihood of plant conditions that would require information provided by this instrumentation. When one or more Functions have two required channels that are inoperable ( i . e.' two channels i nopera:b le in the same . . Function), one channel in the Fun.ct ion should be restored to
• OPERABLE status within 7 days .. The Coinplet ion Time of
• 7 days is based on the relatively low probability of *an* event requiring PAM operation and.the *
• availability of alternate means to obtain the required
• information. Continuous operation with two required {continued). 3.3-73 Revision No. 3 BASES Actions PBAPS UNIT 3 C.l (continued) PAM Instrumentation B 3.3.3.l channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM . instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur. This Required Action directs entry into the appropriate Condition referenced in Table 3.3.3.1-1. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met the Required Action of Condition C and the associated Completion Time has expired, Condition-D is entered for that channel and provides for transfer to the appropriate subsequent Condition. For the majority of Functions in Table 3.3.3.1-1, if.the Required Action and associated Completion Time of Condition C is not met, the plant must be brought to a MODE in which the LCO not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. F.l Since alternate means of monitoring drywell high range radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels. (continued) B 3.3-74 Revision No. 3 PAM Instrumentation B 3.3.3.1 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 SR 3.3.3.1.1 Performance of the CHANNEL CHECK once 31 days ensures that. a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant d*viations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross chanriel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar plant instruments located throughout the plant. Agreement criteria are determined by the plant. staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a . channel is outside the crite(ia, it may be an indicatiOn that the sensor or the signal processing equipment has its The Surveillance Frequency-is controlled under the Surveillarice Frequency Control The CHANNEL CHECK supplements less_ formal, but more* frequent, -checks of riormal operational use of those displays associated with the required *by the LCO. -SR. 3.3.3.1.2 Deleted SR-* 3 . 3 . 3-. 1. 3 -These SRs CHANNEL CALI BRATIONs -_to be* performed. A --_ CHANNEL"CAlI BRAflON is:_ a comp l e_te check-. of t_he .. i n_s t rument --loop, including the sensor .. The-test verHi es the channel responds to parameter* wi-th the necessary-range and accuracy: For the PCIV. Position Function, the CHANNEL CALIBRATION-consists* of *verifying the' remote i ndi ca ti on cOnforms "to* actual -valve pos i t1 on . . *." (continued) -.... B Revis.ion No. 87 I, BASES SURVEILLANCE REQUIREMENTS REFERENCES -PBAP.S UN IT 3 PAM Instrumentation B 3.3.3.1 SR 3.3.3.1.3 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," Revision 3, May 2. NRC .Safety Evaluation Report, "Peach Bottom Atomic Power Station, Unit Nos. 2 and 3, Conformance to Regulatory Guide 1.97," January 15, 1988. 3. Letter from G. Y. Suh CNRC) to G. J. Beck CPECo) dated February 13, 1991 concerning "Conformance to Regulatory Guide 1.9? for Peach Bottom Atomic Power Station, Units 2 and 3". 4. Letter from S. Dembek (NRC) to G. A. Hunger (PECO *Energy) dated March 7, 1994 concerning "Regulatory Guide -Boiling Water Reactor Neutron Flux Monitoring, Peach Bottom Atomic Power Station (PKAPS), Units 2 and 3". B 3. 3'*:76 *. Revis.i6n No. 87 I Remote Shutdown System B 3.3.3.2 B 3.3 INSTRUMENTATION B 3.3.3.2 Remote Shutdown System BASES BACKGROUND A P P LI c'A B LE SAFETY ANALYSES PBAPS UN IT 3 The Remote Shutdown System provides the control room operator with sufficient instrumentation and controls to maintain the plant in a safe shutdown condition from a location other than the control room for at least one hour. This capability is necessary to protect against the possibility of the control room becoming inaccessible. *A safe shutdown condition is defined as MODE 3. With the plant in MODE 3, the Reactor Core Isolation Cooling (RCIC) System and the safety/relief valves can be used to remove cqre decay heat and meet all safety requirements. The long term supply of water for the RCIC and the ability to control reactor pressure and level from outside the control room allow extended operation in MODE 3. In the event that the control room must be abandoned, a reactor trip and MSIV is assumed to have been initiated from the control room prior to aband6nment. For the design event, it is assumed the loss of feedwater (as a result of MSIV closure) causes an automatic start of RCIC due to low reactor level. Although HPCI also tYpically initiates on low reactor level, it is conservatively assumed that it does not start for the design event due to damage in the control room. No LOOP, accident condition or other failures are assumed. At the remote shutdowri panel, reactor level and . maintained with RCIC and operation of SRVs E and L. SRV operation maintains pressure below the SRV lift setpoint and transfers decay heat to the suppression pool. This can be maintained for at least one hour without suppression pool cooling. If control room access cannot be regained in one hour, procedures provide direction to bring the plant to cold shutdown.
• The OPERABILITY of the Remote Shutdown System ensures there are sufficient controls and information available for those plant parameters necessary to maintain the plant in MODE 3 for at* least one hour. Other controls and indication on the remote shutdown panel are provided, but they are not required for OPERABILITY. The Remote Shutdown System is required to provide instrumentation and coritrols at appropriate locations outside the control .room with a design capability to contr.ol reactor *pressure and level, including the necessary and to maintain the plant in a in MODE 3. . . . continued Revision No. 134 BASES APPLICABLE SAFETY ANALYSES (continued) LCO APPLICABILITY PBAPS UNIT 3. Remote Shutdown System B 3.3.3.2 The criteria governing the design and the specific system requirements of the Remote Shutdown System are located in the UFSAR (Refs. 1 and 2). The Remote Shutdown System is considered an important contributor to reducing the risk of accidents; as such, it meets Criterion 4 of the NRC Policy Statement. The Remote Shutdown System LCO provides the requirements for the OPERABILITY of the instrumentation and 'controls necessary to maintain the plant in MODE 3 from a .location than the control room. The instrumentation and controls required are listed in Table B 3.3.3.2-1. The controls, instrumentation, and transfer switches are those required for:
• Reactor pressure vessel CRPV) pressure control;
• Decay heat removal ; a.nd
• RPV inventory control The Remote Shutdown System is OPERABLE if all instrument and *control channels needed to support the remote shutdown function are OPERABLE. The Shutdown System instruments and control covered by this LCO do not need to. be energized to be OPERABLE. This LCO is tci ensure the instruments and control circuits wi.ll be OPERABLE ,if conditions require that the Remote Shutdown System be *placed in . . . The Remote Shutdown System LCO is. appl i cable in MODES 1 and. 2. This is required so that the plant can be maintained in MODE 3 for an extended period of time from a location other than the control room. continued B 3.3-78 Revision No. 134 ..

BASES APPLICABILITY (continued) ACTIONS . PBAPS UN IT 3 Remote Shutdown System B 3.3.3.2 This LCD is not applicable in MODES 3, 4, and 5. In these MODES, the plant is already subcritical and in a condition of reduced Reactor Coolant System energy. Under these conditions, considerable time is available to restore necessary instrument control Functions if control room instruments or control becomes unavailable. Consequently, the TS do not require OPERABILITY in MODES 3, 4, and 5. A Note has been provided to modify the ACTIONS related to Remrite Shutdown System Functions. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable Remote Shutdown System Functions provide appropriate compensatory measures for separate Functions. As such, a Note has been provided that allows separate Condition entry for each inoperable Remote Shutdown System Function. Condition A addresses the situation where one or more required Functions of the Remote Shutdown System is i n o p e r a b l e . Th i s i n c l u d e s t h e c on t r o l a n d t r a n s f e r s w i t c h e s for any required function. The Required Action is to restore the Function (all channels) to OPERABLE status within 30 days. The Completion Time is based on operating experience and the low probability of an event that would require evacuation of the confro l room. continued B 3.3-79 Revision No. 53 BASES ACTIONS (continued) SURV E'ILLANCE REQUIREMENTS REFERENcES ' PBAPS UN*IT 3 Remote Shutdown System B 3.3.3.2 If the Required Action and associated Completion Time of Condition A are not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time is reasonable, based on operating experience, to reach the required MODE from full power conditions in an orderly manner and without challenging plant systems. SR 3.3.3.2.1 SR 3.3.3.2.1 verifies that each instrument and control circuit in Table B 3.3.3.2-1 performs the intended function. This verification is performed from the remote shutdown panel and locally, as appropriate. Operation of equipment from the remote shutdown panel is not necessary. The Surveillance can be satisfied by performance of a continuity check of the circuitry. This will ensure that if the control room becomes. the plant can be maintained in MODE 3 from the remote shutdown. Each requifed transfer switch and circuit is limited to those that are necessary to maintain reactor level and pressure from the remote.shutdown* panel during operation in .Mode 3. The controlled under the Survei 11 a.nee Frequency Control Program. SR 3.3.3.2.2 CHA.NNEL CALIBRATION is* a.complete *check of the instrument _ loop an,d .the sensor ... The test verifies the channel responds .*.to parameter values with the necessary range and. The surveillance *i.s *controlled under:the . . Survei l larice Frequenc*y* Control Program. 1 _-: UFSAR,' sect j. on 1.5.1. " 2. UFSAR, Section 7.18. ', 4. -IR 2556042. * *B j. 3-80 Re v i s i on No .

• 13 4 Remote Shutdown System B 3.3.3.2 Table B 3.3.3.2-1 (page 1 of 2) Shutdown System Instrumentation FUNCTION Instrument Parameter 1. Reactor Pressure 2. Reactor Level (Wide Range) 3. Torus Temperature 4. Torus Level 5. Condensate Storage Tank Level 6. RCIC Fl ow 7. RCIC Turbine Speed 8. RCIC Pump Suction .Pressure 9. RCIC Pump Discharge Pressure 10. RCIC Turbine Supply* Pr*es sure 11. RCIC Turbine Exhaust Pressure 12. *Drywell Pressure Transfer/Control Parameter 13. RCIC Pump _ Flow 14. Rcrc-Drain I sol ati on-to Radwa.ste 15. RCIC Steam Pot Dra ;'n Steam Trap Bypass* 16. -RCI C Drain I sol at ion -to *Main* Condenser_ 17. RCIC Exhaust Line Drain-Isolation 18. RC*I C Steam I sol ati on PBAPS UNIT '.r -REQUIRED NUMBER OF CHANNELS 2 2 2 1 1 1 1 1 1 *1 1 1 -1 1 -2 *cl/valve') 2 (l/val ve) conli nued Revision N6. 134 I I I ,. Remote ShDtdown System B 3.3.3.2 Table B 1.3.3.2-1 (page 2 of 2) Remote Shutdown System Instrumentation FUNCTION REQUIRED NUMBER OF CHANNELS Transfer/Control Parameter (continued) 19. RCIC Suction from Condensate Storage Tank 20. RCIC Pump
• 21. RCIC Minimum Flow 22. RC IC Pump Di sch a rge to Full Fl ow Test Line 23. RCIC Suction from Torus 24. RCIC Steam Supply 25. RCIC Lube Oil Cooler Valve Z6. RCIC Trip Throttle Valve Operator Position 27.-RCIC Trip Throttle Valve Position 28 ... RCIC Vacuum Breaker
• 29. RCIC Condensate Pump 30. RCIC Vacuum Pwmp 31. Safety/Relief Valves CS/RVs) 32. Auto Isolation Reset 33. Instrument Transfer PBAPS UN IT 3 B 3.3-_82 1 2 (1/valve) 1 1 2 (1/va 1 ve) 1 1 1 1 1 1 1 3 (1/valve) 2 (1/division) 5 Cl/transfer switch) Revision No. 134 THIS PAGE INTENTIONALLY LEFT BLANK
• PBAPS UNIT 3
• B 3.3-83* Revision No. 134 I I I ATWS-RPT Instrumentation B 3.3.4.1 B 3.3 INSTRUMENTATION B 3.3.4.1 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation BASES BACKGROUND APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UN IT. 3 The ATWS-RPT System initiates an RPT, adding negative. reactivity, following events in which a scram does not (but should) occur, to lessen the effects of an ATWS event. Tripping the recirculation pumps adds negative reactivity from the increase in steam voiding in the core area as core flow decreases. When Reactor Vessel Water Level -Low Low (Level 2) or Reactor Pressure-High setpoint is reached, the recirculation pump drive motor breakers trip. The ATWS-RPT System includes sensors, relays, and switches that are necessary to cause initiation of an RPT. The channels include electronic equipment that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs an ATWS-RPT signal to the trip logic. The ATWS-RPT consists of two trip systems. There are two ATWS-RPT Functions: Reactor Pressure -High and Reactor Vessel Water Level -Low Low (Level 2). Each trip system has two channels of Reactor Pressure -High and two channels of Reactor Vessel Water Level -Low Low (Level 2). Each ATWS-RPT tr*ip system is a one-out-of-two logic for each Function. Thus, one Reactor Water Level -Low Low (Level 2) or one Reactor Pressure -High signal is needed to trip a
• trip system. Both trip systems must be in a tripped condition to initiate the trip of both recirculation pumps (by tripping the respective recirculation pump drive motor breakers). There is one recirculation pump drive motor breaker provided for each of the two recirculation pumps for a total of two breakers. The ATWS-RPT is not assumed in the safety analysis. The ATWS-RPT initiates an RPT to aid in preserving the integrity *of the fuel cladding following events in which a scram does not, but should, occur. Based on its contribution to the reduction of overall plant risk, however, the instrumentation meets Criterion 4 of the NRC Policy Statement. (continued} B 3.3-84 Revision No. 3

... **: * . .. -. .. I; . .-... : ' **-* *._.!.'"> BASES APPLICABLE SAFETY ANALYSES, LCO, and -APPLICABILITY * (continued) . . . ; ' _,,.* *:-:--: . "-ATWS-RPT Instrumentation B 3.3.4.1 The OPERABILITY of the ATWS-RPT is dependent on the OPERABILITY of the individual instrumentation channel funttions. Each function must have a required number of OPERABLE channels in each trip system, with their setpofnts within the specified Allowable Value of SR 3.3.4.1.3. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Channel OPERABILITY also includes the associated recirculation pump drive motor breakers. A channel is inoperable if its actual trip setting is not within its required Allowable Value. Allowable Values are specified for each ATWS-RPT Function specifjed in the LCO. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that *the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting . less. conserv*tive than the trip setpoint, but within its Allowable Value, is acceptable. Trip setpoints are predetermined values of output at which an action should take*place. The setpoints are compared to the actual process parameter (e.g.,. reactor vessel water level h and. the measured. C>Utput val Ue of the process parameter exceeds the setpoint, the .associated device changes state. *The analytic or design l are* derived from the limiting values of the process parameters obta.ined from the safety -' -analysis. *The Allowable Values are derived from*the .. analytic or* design limits,_ corrected for calibration,_ _ and *instrument errors as well as iristrument drifL lr:i selected. cases,. -the Allowable *values and trip setpoints -are deterrni ned by eng:ineeri ng judgenien'I; or :,hi stori ca l]y acCepfafrJ 'practite relative to the intended_ function of the h-The -trip setpoj nts determined-in this manner --* . provide*adequate. protection* by as.suri ng instrument and proce,ss 'tmcertai.nt1es 'expected for the environments -the operating'tim.e of'.t,he.assqciated* <;harinels are --* :_ -----.--*-*-.-.--*.-"* _.: '.: ,._,. ,._., -.,... . . ' : . *. '-The. _a,re to .. *oPERABLE *in,_-. :: _. :,MODE t tq "pt7ote'ct a:gainst common .modecfailUre*s, of the .. _._-. Reactor. P.rotect i ()ri -*system by* prpvi ding a di verse trip to *: mitigate; the,, consequences* of:* a* postulated ATWS event. * -l:ligh* and-Reactor Vessel Water Level -low -Low (Leve 1-2) Functions are reqti ired to be. OPERABLE i 11 : -.. , .. MOQ.E I :,slrice, the >Si fi power and . -*. :-_, ... (continued} ., : .,.* -: '. -' -. ,, .. * : . . ... '.*' . **** *= t;:',. *: -.. --*'; PBAPS UtHT 3 8 3.3-ss* .*,. ___ __J BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS-UNIT 3 ATWS-RPT Instrumentation B 3.3.4.1 the recirculation system could be at high flow. During this MODE, the potential exists for pressure increases or low water level, assuming an ATWS event. In MODE 2, the reactor is at low power and the recirculation system is at low flow; thus; the potential is low for a pressure increase or low water level, assuming an ATWS event. Therefore, the ATWS-RPT is not necessary. In MODES 3 and 4, the reactor is shut down with all control rods inserted; thus; an ATWS event is not significant and the possibility of a significant pressure increase or low water level is negligible. In MODE 5, the one rod out interlock ensures that the reactor remains subcritical; thus, an ATWS event is not significant. In addition, the reactor pressure vessel (RPV) head is not fully tensioned and no pressure transient threat to the reactor coolant pressure boundary (RCPB) exists. The specific Applicable Safety Analyses and LCO discussions are listed below on a Function by Function basis. -a. _ Reactor Vessel Water Level -Low Low <Level 2) Low RPV water level indicates that a reactor scram should have and the capability to coo 1 the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The ATWS-RPT System is initiated at Level 2 to assist in the mitigation of the ATWS event. The resultant -reduction of flow reduces the neutron flux and THERMAL POWER and, therefore, the rate of coolant boil off . . Reactor vessei water level signals are initiated from four ,level transmitters that sense the difference -the to a of water (reference 1 eg) and *_the_ pressure due to the actual -\,/ater level (variable leg) in_the ---channels of_ Vessel Water Level.:,;,, Low Low -:(Level 2), with two channels trip are -.a"Vai l able and -required to_ be OPERABLE to ensure that -no single instrument failure can preClude an ATWS-RPT from this Function on*a valid The-Reactor -Ye_ssel Water Level (Level 2) Allowable Value -(continued)

• B -Revision No. 3 *

,1-.:* ;* -. . , *. " ,:* .. BASES ATWS-RPT. Instrumentation B 3.3.4.1 APPLICABLE a. Reactor Vessel Water Level-Low Low (Level 2) . (continued} SAFETY-ANALYSES, LCO, and APPLICABILITY . ,. *.:*,* ACTIONS-* '.' -_--. *PQAPS *uNiT.3.* -is chosen so. that the system will not be initiated _ after a Level 3 scram with feedwater still available,. and for with the reactor core isolation cooling .initiatibn. b. Reactor Pressure-High Excessively high RPV pressure may rupture the RCPB. * . An increase in the RPV pressure during reactor operation comprisses the voids and results in a positive reactivity insertion. This increases *flux and THERMAL POWER, which could potentially result in fuel failure and The Reactor* Pressure-High Function initiates an RPT for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core power generatfon. For the overpressurization event, the RPT aids in the termination of the ATWS event and, along with the safety/relief valves, limits the peak RPV pressure to less than_ the ASME Section III Code . * * * . * *The:Reactor Pressure-High signals are initiated from *_four' pressure transmitters that monitor reactor steam Four* channels of Reactor Pressure -. High, with two channeJs in each trip system, are

• available and are required to be OPERABLE to ensure *, that no single instrument failure preclude an ATws:...RPT from this Function on* a *valid signal. The **Reactor Pressure.--High Allowable _Value is chosen to . provide an adequite margin to the ASME Section III
• Go.de limits.
• A*Note has .been*provided to modify the ACTIONS related to ATWS-RPT instrumentation ch-anne ls. Section I. 3, Completion Times, that.ohce a has been entered, subsequent divisions; subsystems, components, or variables expressed in the discovered to be inoperable or . not within limits, will not result in separate entry into Condition. Section also specifies that Required Actibns of the Cotidition cQntinue to apply for each (continued) . .. -. .: .: *' R 3 Re_vision .3 . ' :; **.*.

. i :. ' ,,-,-BASES ACTIONS (continued) ,. . ' PBAPS UNIT 3 * .. *-._**. ATWS-RPT Instrumentati.on B 3.3.4.I additional failure, with Completion Times based on iriitial. entry'into the Condition. However, the Required Actions for inoperable ATWS-RPT instrumentation channels provide appropriate compensatory measures for separate inoperable. channels. As such, a Note has been provided that allows separate Condition entry for each inoperable ATWS-RPT instrumentation channel.

• A.I and A.2 . With one or more channels inoperable, but with .ATWS-RPT trip capabiljty for each Function maintained (refer to Required Actions B.I and C.I Bases); the ATWS-RPT System is capable of performing the intended function. However, the . . reliability and redundancy *Of the ATWS-RPT instrumentation is reduced, such that a single failure in the remaining trip . system could resu.l t in the inability of the ATWS-RPT System *
• to. perform the intended function. Therefore, only a limited time is allowed to restore the inoperable channels to* OPERABLE status.
• Because of the diversity of sensors available to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse* Functions, and the low probability of an event the. initiation of ATWS-RPT, I4 days is provided to restore the* inoperable channel (Required Action A. I). .Alternatel,.Y, the* inoperable channel may be placed in trip (Required * ... *.. . Action A.2), sirice this would *
• the inoperabil ity, restore capability to accommodate a
• si11gle failure,* a_nd allo.w operation to co_ntinue; As noted, . placing the channel in trip with no* further restrictions is if the is.the result of an* ino.perable breaker, since this may not adequately ctjrilpensate .. for the inoperable breaker *-ce.g., the breaker may be-. . inoperable. such that it will not open) . If it. is not . . . , . to place the channel in trip as in where placing the inoperable channel woul_d: res*u1t in a*n .. RPT), or if the inoperable channel is the result of an
• inoperable breaker, Condition D must be 'entered and * * * :: Actions taken .. ** B.l . Required Action is intended to appropriate: * . actions *are taken *ff multiple, untri pped : . *. * . channels with.in the same .Fun*ct ion result in the Functi orr not ' . . " . ' ..... *' , '. ' (continued) * * : :* . ., ' B **Revision No. 3 *::-*:.* . . . .

BASES ACTIONS PBAPS UNIT 3 B. l (continued) ATWS-RPT Instrumentation B 3.3.4.1 maintaining ATWS-RPT trip capability. A Function is considered to be maintaining ATWS-RPT trip capability when sufficient channels are OPERABLE or in trip such that the ATWS-RPT System will generate a trip signal from the given Function on a valid signal, and both recirculation pumps can be tripped. This requires one channel of the Function in each trip system to be OPERABLE or in trip, and the recirculation pump drive motor breakers to be OPERABLE or in trip. The 72 hour Completion Time is sufficient for the operator to take corrective action (e.g., restoration or tripping of channels) and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during

• this period and that one Function is still maintaining ATWS-RPT trip capability. Required Action C.l is intended to ensure that appropriate Actions are taken if multiple, inoperable, untripped channels within both functions result in both Functions not maintaining ATWS-RPT trip capability. The description of a Function maintaining ATWS-RPT trip capability is discussed in the Bases for Required Action B.l above. The I hour Completion Time is sufficient for the operator to take corrective action and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during this period. 0.1 and 0.2 With any Required Action and associated Completion Time not met, the plant must be brought to a MODE or other specified condition in which the LCD does not apply. To achieve this status, the plant must be brought to at least MODE 2 within 6 hours (Required Action D.2). Alternately, the associated recirculation pump may be removed from service since this performs the intended function of the instrumentation (Required Action D.l). The allowed Completion Time of (continued) B 3.3-89 Revision No. 3 BASES ACTIONS SURVEILLANCE REQUIREMENts* PBAPS UNIT *3 0.1 and 0.2 (continued) ATWS-RPT Instrumentation B 3.3.4.1 6 hours is reasonable, based on operating experience, both to reach MODE 2 from full power conditions and to remove a recirculation pump from service in an orderly manner and without challenging plant systems. Required Action 0.1 is modified by a Note which states that the Required Action is only applicable if the inoperable channel is the result of an inoperable RPT breaker. The Note clarifies the situations under which the associated Required Action would be the appropriate Required Action. The Surveillances are modified by a Note to indicate that* when a
• ch an n el i s pl aced i n an i nope r ab l e stat u-s sol el y for Of required Surveillances, entry into the associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains ATWS-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be to OPERABLE status or the
• applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 1) assumption of the average time required to perform channel That analysis demonstrated that the 6 hour testtrig allowance does* not significantly reduce the
• probability' that the, reci rcul at ion pumps will trip when necessa:ry. SR 3.3.4.Ll Performance of the CHANNEL CHECK .. ensures that. a gross of instrumentation has ntit occurred.* A CHANNEL CHECK is .n6rmallY'.a:comparison o(the parameter indicated on one channel to a similar parameter on other channels. It is based on. the assumption that instrument channels monitoring the* sam:e. parameter should approximately the same value. between the could* be an 'indication of excessi:ve instrument drift in one 'of .the _.. channels or !:iom*ethi n*g>even more. seri'ous: A. CHANNEL CHECK will detect gross channel failure; thus, it is key tp verifying the continues to operate properly. betweeri each CHANNEL CALIBRATION, Agreerii*en.Lcri teri a are .determi .. ned by th.e pl ant staff based on a =corrib1 nation of the chanhe l. instrument* u.ncerta inti es, including ihdicati.on'and readability. If.a channel is outside the criteria, it may be an indication that the instruinerit has drifted outside its limit. continued B *3.3-90 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS :PBAPS UN.IT 3 ATWS-RPT Instrumentation B 3.3.4.1 SR 3.3.4.1.l (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. *The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of ihe displays associated with the required channels of this LCO. SR 3.3.4.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel .to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.4.1.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies channel responds'.to the measured parameter with1n necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted*to acco.unt for instrument drifts .between successive calibrations, consistent with the of the current plant specific setpoint methodology. _The Frequenty is controlled under the Survei}lanoe Freqµency Control Program. SR -3.3.4>1.4 LciGtt demonstrates the OPERAB}ti'ry of the required trip for a specific channei.--The funct:iona T test of the pump brea_kers is included as part of th1s Surveillance and"overlaps the LOGIC TEST.to prcivide of thi -assumed safety function. Therefore, if'abreaker is incapable of operating, the associated instrument channel Cs) '.would * -continued . B 3.3-91 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS REFERENCES . '"*-,* P,BAPS '.LJN IT 3 ATWS-RPT Instrumentation B 3.3.4.1 SR 3.3.4.1.4 (cont1nued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. "Bases for Changes To Surveillance Test Intervals and Allowed Out-of-Service Times For Selected Instrumentation Technical Specifications," February 1991. B 3.3-92 **Revision No. 87 . I EOC-RPT Instrumentation B 3.3.4.2 B 3.3 INSTRUMENTATION B 3.3.4.2 End of Cycle Recirculation Pump Trip CEOC-RPT) Instrumentation BASES BACKGROUND PBAPS UN IT 3 . The EOC-RPT instrumentation initiates a recirculation pump trip CRPT) to reduce the peak reactor pressure and power resulting from turbine trip or generator load rejection transients and to minimize the decrease in core MCPR during these transients. The benefit of the additional negative reactivity in excess of that normally inserted on a scram reflects end of cycle reactivity considerations. Flux shapes at the end of cycle are sµch that the control rods insert only a small amount of negative reactivity during the first few feet of rod travel upon a scram caused by Turbine Control Valve (TCV) Fast Closure. Trip Oil Pressure-Low or Turbine Stop Valve CTSV)-Closure. The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive at a faster rate than the control rods can add negative reactivity. The EOC-RPT instrumentation, as shown in Reference 1, is composed of sensors that detect initiation of closure of TSVs or fast closure of the TCVs, combined with relays, logic circuits, and fast acting circuit breakers that . interrupt power from the recirculation pump Adjustable Speed Drfves (ASDs) to each of the recirculation motors. When the setpoint is exceeded, the chanhel output relay. which then outputs an EOC-RPT signal to the trip lpgic. When the RPT breakers open, the recirculation 'pumps coast down under their own inertia .. The EOC-RPT has two idehtical iystems, either of .can actuate an* RPT. -Each trip system a tw6-out-of-two logic for each Function; thus, either two TSV-C-losure or two TCV Fast _ .-_.*,* Closure, Trip Oil Press0re-Low signals are for a trip system to actuate. lf either trip system actuates, b6th pumps will trip. There are two EOC-RPT
• breakers iTI series per recirculation pump. One trip system trips one of the two EOC-RPT breakers for each recirculatjon cont i'nued .* B3.3-92a -Revision 118.

BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES, LCO, arid APPLICABILITY PBAPS .UNIT 3

• EOC-RPT Instrumentation B 3.3.4.2 pump, and the second trip system trips the other EOC-RPT breaker for each recifculation pump. The TSV-Closure and the TCV Fast Closure, Trip Oil Pressure-Low Functions are designed to trip the recirculation pumps in the event of a turbine trip or generator load rejection to mitigate the neutron flux, heat flux, and pressurization transients, and to minimize the decrease in MCPR. The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection, as well as other safety analyses that utilize EOC-RPT, are summarized in References 2, 3, and 4. To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of closure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a scram alone so that the Safety Limit MCPR is not exceeded. Alternatively, APLHGR operating limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), the MCPR operating limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and the LHGR operating limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)") for an inoperable EOC-RPT, as specified in the COLR, are sufficient to allow this LCO to be met. The RPT function is automatically disabled when turbine first stage pressure is< 26.7% RTP. EOC-RPT instrumentation satisfies Criterion 3 of the NRC Policy Statement. The OPERABILITY of the EOC-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions, i.e., the TSV-Closure and the TCV Fast Closure, Trip Oil Pressure-Low Functions. Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of SR 3.3.4.2.3. Channel OPERABILITY also includes the associated EOC-RPT breakers. Each channel (including the associated EOC-RPT breakers) must also respond within its assumed response time. Allowable Values are specified for each EOC-RPT Function specified in.the LCO. Trip setpoints are specified in the plant design documentation. The trip setpoints are selected continued B 3.3-nb Revision No. 119 BASES APP LI CAB LE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) EOC-RPT Instrumentation B 3.3.4.2 to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setting is not within its required Allowable Value. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process. parameters (e.g. TSV position), and the measured output value of the process parameter exceeds the setpoint, the device (e.g., limit switch) changes state. The analytic limit for the TCV Fast Closure, Trip Oil Pressure-Low Function determined based on the TCV hydraulic oil circuit design. The Allowable Value is derived from the analytic limit, corrected for and instrument errors. The trip setpoint is determined from the analytical limit corrected for calibration, process, *and instrumentation errors .. dS well as instrument drift, as applicable. The Allowable Value and trip setpoint for the TSV-Closure Function was determined by engineefing judgment and historically practice for similar trip functioris.
• The specific Applicable Safety LCD, and Applicabi'lity discuss.ions are listed below on a Function.by Function basis, Alternatiyely, since the instrumentation a
• MCPR with tbe iristrumentation inoperab1e, to the AP[HGR limits (LCD 3.2.l, "AVERAGE P.LANA.R LINEAR HEAT GENERATION RATE CAPLHGR)"), the MCPR limits C[CO "MINIMUM CRITICAL POWER RAT IO ( MC P R) " ) , a n d t he L HG R o p e r a ti n g l i mi t s ( LC 0 3 . 2 . 3 , "LI.NEAR HEAT. GENERATION .RAT[ C LHGR)") niay .be applied _to LCO to be met. The MCPR limits and thermal limit adjustments for the inopera.?le ccinditiori are. spec1_fied in the COLR. * .. ..
• Closure of. the TS\ls'and amain turbinetr_ip-resuit in the.* loss*of a* that produces reactor flux, and heat flux'-transients that must be limited. Therefor*e,<an RPT H initiated on TSV-Closure in .... anticipation .of theiransi,ents.that would *result from *._*:clos[Jre of.*these. valves .. E'.OC-RPT reactor PBAPS UNIT 3
• reactors.cram.in ensuring that the MCPR SL is*not exceeded. during*'.the worst cas.e transient. (continued) B 3.3-92c*** .. Revision No. 50 BASES APPLICABLE SAFETY ANALYSIS, LCD, and APPLICABILITY . :-: PBAPS UNIT. 3
• EOC-RPT Instrumentation B 3.3.4.2 Turbine Stop Valve-Closure (continued) Closure of the TSVs is determined by measuring the position of each valve. There are position switches associated with each stop valve, the signal from each switch being assigned t o a s e p a r a t e t r i p c h a* n n e 1 . Th e 1 o g i c f o r t h e Ts V -C 1 o s u re Function is such that two or more TSVs must be closed to produce.an EOC-RPT. This Function must be enabled at THERMAL 26.7% RTP as measured at the turbine first stage pressure. This is normally accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function. Four channels of TSV-Cl osure, with two channels tn each trip system, are available and required to be OPERABLE to ensure that no single instrument.failure will preclude an from Function on a valid signal. The TSV-Closure Allowable Value is selected to detect imminent TSV.closure. This EOC-RPT Function is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is 26:7% RTP. Below 26.7% RTP, the Reactor Pressure-High and the Average Power Range Monitor CAPRM) Clamp Functions of the Reactor Protection System CRPS) are adequate to maintain the necessary safety margins. Turbine Control Valve* Fast Closure. Trip Oi 1 Pressure-Low Fast of the TCVs a generator load rejection results in the loss of a heat sink that produces reactor pressure; neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TCV Fast Closure," Trip Oil Pressure-Low in anticipation of the transients that result. from the closure.of these valves. The EOC-RPT decreases peak reactor power and a, ids the reactor scram fn ensuring that the MCPR SL is not exceeded*durin9 the wcirst.case transient. , .. :.:.** clbsure of measuring the** electrohydraulic control fluid pressure at .each control . valve.'* There is one pressure* switch* associated with. each controt and the .from each switch is *to a channel. The logic for* the TCV. Fast Closure, Trip Oil Pressu*r_e_-:-Low Function is such that two or more TC Vs *must be closed C pressure switch trips) continued **. :" Rev i s i on No-. 119 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY ACTIONS PBAPS UN IT -3 . EOC-RPT *Instrumentation B 3.3.4.2 Turbine Control Valve Fast Closure. Trip Oil Pressure-Low (continued) to produce an EOC-RPT. This Function must be enabled at THERMAL 26.7% RTP as measured at the turbine first stage pressure. This is normally accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function. Four channels of TCV Fast Closure, Trip Oil Pressure-Low, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TCV Fast Closure, Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure. This protection is required consistent with the analysis whenever THERMAL POWER 26.7% RTP. Below 26.7% RTP, the Reactor Pressure-High and the APRM Scram Clamp Functions of the RPS are adequate to maintain the necessary safety margins. A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation Section l.J, Completion Times, that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not .w i th i n l i mi ts , w i l l not res u l t i n s e pa rate en t r y i n to the Condition. Section 1.3 also specifies that Required Actions of the Condition cbntinue to apply fof each additional failure, with Completion Times based on entry into the Condition. However, the Required Actions for inoperable EOC-RPT instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable instrumentation channel. continued _B3.3-.92e-Revision No. 119 BASES ACTIONS (continued) PBAPS UNIT-3 A. 1 ___ fl_mL.A_, __ 2 EOC-RPT Instrumentation B 3.3.4.2. With one or more required channels inoperable, but with EOC-RPT trip capability maintained (refer to Required Action B.1 Bases), the EOC-RPT System is capable of performing the intended function. However, the reliability and redundancy of the EOC-RPT instrumentation is reduced such that a single failure in the remaining trip system could result in the inability of the EOC-RPT System to perform the intended function. Therefore, only a limited time is allowed to restore compliance with the LCO. Because of the diversity of sensors available to provide trip the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of an EOC-RPT, 72 hours is provided to restore the inoperable channels (Required Action A.l). Alternately, the inoperable channels may be placed in trip (Required Action A.2) since this would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. As noted in Required Action A.2, placing the channel in trip with no further restrictions not allowed if the inoperable channel js the result of an inoperable breaker, since this may not adequately compensate for the inoperable breaker (e.g., the breaker may be inoperable such that it will not open} .. If* it is not desired to place the channel in trip (e.g., as in the tase where placing the inoperable channel in trip would result in an RPTi or if the inoperable channel is the result of iri inoperable breakeF), Condition C must be entered and ;*ts Required taken. **Required Action B;l is intended to ensure appropriate are taken if multiple, untripped channels within the same Function result in the Function not* maihtaining EOC-RPT capability .. A Function is considered to be mairitaining EOC-RPT capability when . channels are OPERABLE or trip, such that
• EOC-RPT System generate a trip signal from the given
• Function on a valid sighal and both recirculation pumps can
• be tripped. This re qui res two channe 1 s of the Function in *the same trip system, to each_ be OPERABLE or in trip, and the associated breakers to be' OPERABLE. continued B 3.3-92f Revision No. 58 I I. BASES ACTIONS SU RV EI LLANCE . REQUIREMENTS
• PBAPS *UNIT 3 Ll (continued) EOC-RPT Instrumentation B 3.3.4.2 The 2 hour Completion Time is sufficient time for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of the EOC-RPT instrumentation during this period. It is also consistent with the 2 hour Completion Time provided in LCO 3.2.1 and 3.2.2 for Required Action A.l, since this instrumentation's purpose is to preclude a thermal limit violation. C.l and C.2 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to< 26.7% RTP within 4 hours. Alternately, for an inoperable breaker (e.g., the breaker may be inoperable such that it will not open) the associated recirculation pump may be removed from service, since this performs the intended function of the instrumentation. The allowed Completion Time of 4 hours is reasonable, based on operating experience, to reduce THERMAL POWER to< 26.7% RTP from full power conditions in an orderly manner and without *challenging plant systems. Required Action C.l is modified by a Note which states that the Required Action is only applicable if the inoperable channel is the result of an inoperable RPT breaker. The NOTE clarifies the situations under which the Required Action would be the appropriate Required Actfon. The Surveillances are modified by a Note to indicate that when i channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains EOC-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis 5) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does. not significantly reduce the probability that the recirculation pumps will trip when necessary. continued B 3.3-92g Revision No. 119 BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 3 SR 3.3.4.2.1 EOC-RPT Instrumentation B 3.3.4.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.4.2.2 CHANNEL tALIBRATION is a complete check of the instrument loop and the sensor .. This test verifies the channel resp6nds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The LOGIC SYSTtM TEST demonstrates the OPERABIUTY of the required trip logic a speci_fi c
• channel .. system functional test of the pump breakers is jncluded as a part of*this 'test, overlapping the LOGIC SYSTEM FUNCTIONAL TEST, to provide ccimp1ete testing of the safety function. Therefore, if *a breaker is . incapabl"e of operating, the assac.iated i.nstrument channel(s) be -* * -. -. . . The 1s under the .Surve i 11 a nee Frequency Control Prag ram; . ;. (continued) . -* ,. ,.':
• B 3.3-92h Revision No. 87 .. * ; .

BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UNlT 3 EOC-RPT Instrumentation B 3.3.4.2 SR 3.3.4.2.4 This SR ensures that an EOC-RPT initiated from the TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER 26.7% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from first stage pressure) the main turbine bypass valves must remain closed during the calibration at THERMAL POWER 26.7% RTP to ensure that .the calibration remains valid. If any bypass channel's setpoint is nonconservative Ci .e., the Functions ari bypassed at 26.7% RTP, either due to open main turbine bypass valves or other reasons), the affected TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions ar_e 'considered i.noperable. Alternatively, the bypass channel can* be placed in the conservative condition Cnonbypass). If placed in the nonbypass condition, this SR is met with the channel considered OPERABLE. -The Surveiliance Frequency is controlled under the Frequency Control Program. SR 3.3.4.2.5 This SR that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. the EOC-RPT SYSTEM TIME .* acceptarce criterion is included in Reference .. 6. A N o t e -t o t h e S u r v e i l la n c.e s t a t e s t h at b r e a k e r i n t e r r up t i o ri time may be. assum-ed from the most recent performance of SR 3.3.4.2.6. This is .allowed since the time. to open the contacts-.after energlzatron "of'the trip coil. and the suppression time are short.and do .not appreciably.change, design of the. opening device and the fact that the,b.reaker-is not-routinely cycled.*.: continued . B 3. 3 _:9 2 i . BASES SURVEILLANCE REQUIREMENTS REFERENCES Pi3APS UN IT 3 SR 3.3.4.2.5 (continued) EOC-RPT Instrumentation B ,3.3.4.2 Response times cannot be determined at power because operation of final actuated devices is The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.* SR 3.3.4 .. 2.6 This SR ensures that the RPT .breaker interruption time (arc suppression time plus time to open the contacts) is provided to the EOC-RPT SYSTEM RESPONSE TIME test. The Surveillance Frequency is controlled under the Surveillance Frequency Cb n t r o l P r o g r am . 1. UFSAR, Figure 7.9.4A, Sheet 3 of 3 (EOC-RPT logic diagram). 2. UFSAR, Section 7.9.4.4.3. 3. UFSAR, Section 14.5.1.2.4. 4. "General Electric Standar*d Application for Reactor Fuel," latest approved version. 5. GENE-770-06-1-A, "Bases for Changes to Sur*veillance Tesi Intervals and Allowed Out-Of-Service Times for Sel etted Instrumentation Technical* Speci fi cations," December 1992. 6: Core Operating Limits Report. B 3.3.-92j Re.vision No. 87

*' ::*: .. . :*: .. **: 1.,-' . * .. * ... >>* . '-.:. * .::**. '. ;_ .... . . . ECCS Instrumentation B B 3.3 INSTRUMENTATION B 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation BASES BACKGROUND The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that the fuel is adequately cooled in the event of a design basis. accident or transient.

• For most abnormal operational transients.and.Design Basis Accidents (DBAs), a wide range of dependent and independent parameters are monitored. The ECCS instrumentation actuates core spray(CS), low pressure coolant injection (LPCl), high pressure coolant injection (HPCI), Automatic Depressurization System {ADS), and the diesel generators {DGs). The equipment involved .. with each of these systems is described in the Bases for
• Lto 3. 5 .1, 11 ECCS -Operating. 11 Core Spray System The CS System may be initiated by automatic means. . . . Automatic initiation occurs for cond it iOns of Reactor Vesse t . Water. Level -Low Low Low {Level 1). or Drywel 1 Pressure-:-High with a Reactor Pressure-Low permissive .. The reactor vessel water and the reactor pressure variables are monit6red. by four redundant transmitters, which .are,* in turn,
• conriected to fo(Jr* pressure compensation. fostruments. The . drywell pressure V,ariable is nionit9red by four redundant transin'itters, which are, 'i.n turn, connec:ted to four_'trip
• The outputs of.the.pressure compensation instriiments 'and. :the trip .units are. co.nnected to relays*:whtch send ... ** . ,, signals*to two trip systems, with .each trip system arrangecl in a. twice logic. (each trip* unit *sends .. a s i gna 1 to b{)th trip systems.)
• Each trip-system i ni ti ates * ; *Of: four .. CS. , *., * * * * *._. *<: .... .... receipt of an inittaticin sigrial, if normal AC available, CS p*umps A and C start after a time delay of. . approximately 13 seconds and CS pumps B and D start after a *. tfme delay of approximately 23 seconds: If normal AC power . **. is not the.four cs pumps start_simultan.eously ..
• after a time* de] ai 6f approximately 6 seconds after the
• respecti_ve DG. i.s ready to lOad. , ** .. . . (continued) " .. . ' . .* . *. B
• Revis'ion No.*3 PBAPS UNIT* 3 * ..
• _*, _: .. ****** *,_ .. *..: *-*:

BASES BACKGROUND PBAPS UNIT 3 Core Spray System (continued) ECCS Instrumentation B 3.3.5.l The CS test line isolation valve, which is also a primary containment isolation valve (PCIV), is closed on a CS initiation signal to allow full system flow assumed in the accident analyses and maintain primary containment isolated in the event CS is not operating. The CS pump discharge flow is monitored by a differential pressure indicating switch. When the pump is running and discharge flow is low enough so that pump overheating may the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint to allow the full system flow assumed in the acc1dent analysis. The CS System also monitors the pressure in the reactor to ensure that, before the injection valves open, the reactor pressure has fallen to a value below the CS System's maximum design pressure. The variable is monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instruments. The outputs of the pressure compensation instruments are* connected to relays whose contacts are arranged in a one-out-of-two taken twice logic. Low Pressure Coolant Injection System The LPCI is an operating mode of the Residual Heat Removal (RHR) System, with two LPCI subsystems. The LPCI subsystems may be initiated by automatic means. Automatic initiation occurs for conditions of Reactor Vessel Water Level -Low Low Low (Level I); Drywell Pressure-High with a Reactor Pressure-Low (Injection Permissive). The drywell pressure variable is monitored by four redundant. transmitters, which, in turn, are connected to four trip units. The reactor vessel water level and the reactor pressure variables are monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instruments. The outputs of the trip units and pressure compensation instruments are connected to relays which send signals to two trip systems, with each trip system arranged in a out-of-two taken twice logic {each trip unit sends a signal to both trip systems). Each trip system can initiate all four LPCI pumps. * (continued) B. 3.3-94 Revision No. 3 i ' i ,.* . '* : .. .*' BASES BACKGROUND '*;:* -:* ... *, .. * . , *. ECCS Instrumentation B 3.3.5.1 Low Pressure Coolant System (continued) Upon receipt of an initiation signal if normal AC power is available, the LPCI A and B pumps start after a delay of approximately 2 seconds. The LPCI C and D pumps are started after a delay of approximately 8 seconds. If normal AC power is not available, the four LPCI pumps start simultaneously with no delay as soon as the standby power source is availabla. Each LPCI subsystem's discharge fl ow is monitored by a differen_tial pressure indicating switch. When a pump is running and discharge flow is low enough so that pump overheating may occur, the respective minimum flow return *1ine valve is If flow is* above the minimum flow setpoint, the valve ls automatically closed to allow the full system flow in the analyses. -The.RHR test lifle suppression pool cooling isolation valve, suppression pool spray isolation valves, and conta.i nment . spray isolation valve.s (wh.ich are also PCIVs) are also .... closed o.n a LPCI initiation s_ignal to allow the full system flow*assumed in the analyses and maintain primary containment isolated in the event LPCI is not . . . . . . * .. *The *LPCI System monitors:: the. pressure. in the reactor to ** ensure that*, . before* an** injecti 011 . valve opens, the reactor . press1.rre has .fallen'lo a value .below the lPtl System's .* maximum design pressure. The variable is monitored by four . redundant t'ransmitters, *which are*, in turn, connected to ..

• four pressure compeilsat ion instruments> The outputs of the .. pressure .compensatio.n are comietted t.o relays . . ' whose contacts' are. arranged in *a.-one-out..;of-two taken twice. ', . logic: -**Additionally; fnstruments. are -prchiided to tlos*e the 'recirculation*pump-disc_harge valves to_ ensure that LPCI.flow _ does not bypass the when* it injects into the .-* -* _ *
• _* -_ * .:*. recirculation**lines.* The variable is monitored.by foµr *" * -* in t.urn,**connected*fo: -*,, '-.: .. *.**. *:** .: -.; . -. . *.* .. . **-__ . *.--'*.'..-. -. PBAPS-UNIT*3* .. : Jour: pressure. :cqmpen:s-at i ori\ i nstrunients. 'ou.tputs .. of the *.
• coriipensatiOn
• i nstrumehts are*_ connected* to rel a.Ys whose contacts'-.a_re* arranged _in a one..:out-of-two taken twice **;, .. . ' -* l og i ' *,o: . . -. -.*_ . . __ ,-*.:_ ' .-_: -.* ' -.* .. ' , .. __ y; *<continued) . ;-. -': -,**, * .. **\ : *, -... , ... . ":.

.. . -' . . -BASES BACKGROUND . , . ,.* -----.. ,, .*.*::.*' ".* ..

• PBAPS ,UNIT 3 *,. ECCS Instrumentation B 3.3.5.1 Low Pressure Coolant Injection System (continued) Low reactor water.level in* the shroud is detected by two additional in_struments. When the level is greater than the low level setpoint LPCI may no .longer be required, therefore other modes of RHR (e.g., suppression pool cooling) are allowed. Manual overrides for the isolations below the low level setpoint are provided. High Pressure Coolant Injection System The. HPCI-*system may be initiated by automatic means. initiation occurs for conditions of Reactor Vessel *water Le.vel.;.;Low Low (Level 2) or Drywell.Pressure-High. The reactor vessel water level variable is monitored by four redundant transmitters, which are, in turn, connected to four *pressure compensation instruments. The drywel 1 pressure variable is.monitored by four redundant transmitters, which are, in turn, connected to four tr1p units.* The .outputs of the pressure compens.ation instruments .and. trip units are connected to relays 'whose contacts are arranged in a one-out-pf-two taken twice logic for each * ' * *
• The HPCl pump discharge. flow is monitored.by a flow swjtch. When the pump is running and discharge *flow is low enough so* that' pu'mp overheating may pccur, the* mini muin fl ow return .
• 1 ine valve is opened. 'The valve is automatically closed if flow Js above the ininimuni flow setpoint to allow the full flow assumed in the safety analysis.** * * . The llPCitest line isoiatiof1valve (which is also a PCIV) is closed 2upon receipt _o_f HPCI. il'liti_ation signal to allo,w .the full system flowass*umed::in the and
• mai ntair( primary: containment isolated irl .the event HPCI is* ' . not i ng. ' .,. . . . ' . . . . *.* .*The-_HPCf System. monitors the wa_terlevels. in the.*** ... condensate storage :tank (CST) *'arid the s_uppressjon pool . . because these are the 'two sources of water HPCI . . *. ** -, oper.atTon.. Reactor. grade water. in. the C.ST is :the normal .
• source. Upon receipt of* a HPCI initiation* -sig.nal, the CST >.' ' ........ -._:.* . . '. '. *. '* " ' .. * .. ':*-* ----*:**.*. . ;* . -.. _ _. .. .. :' ' *B 3.3...:96 ;1*;-_*:. ,** . ...... ' '* . * . RevisionNo. 3 *_ .. _.

BASES BACKGROUND PBAPS UNIT 3 ECCS Instrumentation B 3.3.5.1 High Pressure Coolant Injection System tcontinued) suction valve is automatically signaled to open (it is normally in the open position) unless both suppression pool suction valves are open. If the water level in the CST falls below a preselected level, first the suppression pool suction valves automatically open, and then the CST suction valve automatically closes. Two level switches are used to detect low water level in the CST. Either switch can cause the suppression pool suction valves to open and the CST suction valve to close. The suppression pool suction valves also automatically open and the CST suction valve closes if high water level is detected in the suppression pool. To prevent losing suction to the pump, the suction valves are interlocked so that one suction path must be open before the other automatically closes. The HPCI provides makeup water to the reactor until the -reactor vessel water level reaches the Reactor Vessel Water Level -High (Level 8) trip, at which time the HPCI turbine trips, which causes the turbine's stop valve and the control valves to close. The logic ;-s two-out-of-two to provide high reliability of the HPCI System. The HPCI System automatically restarts if a Reactor Vessel Water Level -Low Low (Level 2) signal is subsequently received. Automatic Depressurization System The AQS may be initiated by automatic means. Automatic initiation_ occurs when signals indicating Reactor Vessel Water Level -Low Low Low (Level l); Drywell Pressure-High or ADS Bypass Low Water Level Actuation Timer; Reactor Vessel Water Confirmatory Level -Low (Level 4); *and CS or LPCI.Pump Discharge Pressure-High are all present and the ADS Initiation Timer has timed out. There are two transmitters each for Reactor Vessel Water Level -Low Low Low (Level 1) and Drywe 11 Pressure -High, and one transmitter for Reactor Vessel Water Confirmatory Level -Low (Level 4) in each of the two ADS trip systems. Each of these transmitters connects to a trip unit, which then drives a relay whose contacts form the initiation logic. Each ADS :trip system includes a time delay between satisfying the initiation logic and the actuation of the ADS val ve*s. The ADS I nit i at ion Timer time delay set point chosen is long enough the HPCI has sufficient operating time (continued) B 3.3:-97 Revision No. 3 BASES. BACKGROUND -/ I_

• __ ... *. .* i , . . -. . . -PBA'.PS UNIT_3 * *'--,: ECCS Instrumentation B 3.3.5.1 Automatic Depressurization System to recover to a level Level 1, yet riot long that -the LPCI and CS Systems are unable to adequately cool the fuel if the HPCI fails to maintain that level. An alarm in the control room is annunciated.when either of the timers is timing. Resetting ADS initiation signals resets the ADS Initiation Timers. The ADS al so mo.nitors the discharge pressures of the four LPCI pumps and the four CS pumps. Each ADS trip system includes two discharge pressure permissive switches from.all four LPCI pumps and one discharge pressure* permissive switch from all four CS pumps. The signals are used as a permissive for ADS actuation, indicating that there is a source of core available once the ADS has depressurized the vessel. -Two CS pumps in proper combination (C or D and A or B) or any one of the four lPCI -pumps is sufficient to permit automatic depressuri zat ion. .. The ADS* logic in each trip system is arranged in two -strings. Each string has a contact from each of the f o 11 owing variables: -Reactor Vessel Water Level -Low Low _
• Low (Level l); Drywell Pressure-High; Low Water Level* Actuation Timer; and Reactor Vessel Water Level -Low *Low Low (Level 1) Permissive. One of the two strings in each trip *system must also have a Reactor Vessel Water Confirmatory Level -Low {Level 4) . After the contacts for the --signal from either drywe_l_l pressur*e.or react.or vessel level '{ahd the timer vessel level timing out) the fol fowing must be pfe:s*ent to initiate an ADS trip . system: all other; conta_cts in-both logic strings mu-st close, the 'ADS timer must time; out, and a. CS or _ LPGI pump discharge pressure signal must be present. Either the A or -B trip system will cause all the ADS relief valves to open.: Once th_e Drywell Pressure""'.High signal,-the.ADS _ -Lqw Water 'Level Actuatiqn limer, or tne ADS initi-atjon
• signal is present, it is.'iridividually sealed ill until manually reset:__ -* * .... *:*: -. . -. . -.Manual inhibit* provided in the control room for* . the ADS; _however,* their functii:m is*.not required for ADS OPERABILITY {pr:ovided ADS is not inhibited when required. to* be OPERABLE). . -----CcontiHnued)--.***,, . .. . ; *".*-* .. ::**** ---:B 3.3-98-Revis i'on No*. -3 ,.** ..
• BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT .3 Diesel Generators ECCS Instrumentation B 3.3.5.1 The DGs may be initiated by automatic means. Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low (Level 1) or Drywell Pressure-High. The DGs are also initiated upon loss of voltage signals. (Refer to the Bases for LCD 3.3.8.1, "Loss of Power (LOP) Instrumentation," for a discussion of these signals.) The reactor vessel water level variable is monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instruments. The drywell pressure variable is monitored by four redundant transmitters, which are, in turn, connected to four trip units. The outputs of the four pressure compensation instruments and the trip units are connected to relays which send signals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic (each trip unit sends a signal to both trip systems). The B trip system initiates all four DGs, and the A trip system initiates all four DGs. The DGs receive their initiation *signals from the CS System initiation logic. The DGs can also be started manually from the control room and locally from the associated DG room. Upon receipt of a loss of coolant accident (LOCA) initiation signal, each DG is automatically started,, is ready to load in approximately 10 seconds, and will run in standby conditions (rated voltage and speed, with the DG output breaker open). The DGs will only energize their respective Engineered Safety Feature buses if a loss of offsite power occurs. (Refer to Bases for LCD 3.3.8.1.) The actions of the ECCS are explicitly assumed in the safety analyses of References 1, 2, and 3. The ECCS is initiated to preserve the integrity of the fuel cladding by limiting the post LOCA peak cladding temperature to less than the 10 CFR 50.46 limits. . ECCS instrumentation satisfies Criterion 3 of the NRC Policy Statement. Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion. The OPERABILITY of the ECCS instrumentation is dependent . upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.1-1. Each Function must have a required number of OPERABLE channels, (continued) B 3.3-99 Revision No. 23 BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY (continued) PBAPS*UNIT-3 ECCS Instrumentation B 3.3.5.1 with their setpoints within the specified Allowable Values, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Table 3.3.5.1-1 is modified by two footnotes. Footnote (a) is added to clarify that the associated functions are required to be OPERABLE in MODES 4 and 5 only when their supported ECCS are required to be OPERABLE per LCD 3.5.2, ECCS-Shutdown. Footnote (b) is added to show that certain ECCS instrumentation Functions also perform DG initiation. Allowable Values are specified for each ECCS Function specified in the Table. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the settings do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g:, reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device trip unit) changes state. The design limits are derived from the limiting values of the process parameters obtained from the safetj analysis*or _other appropriate documents. The Allowable Values derived from the analytic or design limits, corrected for c!libration, and instrument errors. The trip setpcints are determined from analytical or design limits, cqrrected for.calibration, process, .and instrument errors;* as well as, instrument drift.* In s_elected cases, the Allowable Values;and trip setpoints. *are determined from engineering judgement historically accepted practice rel atiite to the intended fI:Jncti oris of the channe_l. lhe trip setpo.i nts determined in this manner provi d_e_ adequate_ protection by assum1rig instrument and:process uricertainties envirohments during the operating time of the a s*s*oci a ted ch an ne l's a re: accounted -far. -For the Co re -Spray *Pump *start-lime .Del aY R.e*1 ays, adequate margins-for applicable setpoint are -incorporated fn-to t;he A 11 owab:l e Values and actual setpoi nts . . * :_-. *, . . --. -. . .. -. *. ' , . In general; the individual Functions are required to.be* __ OPERABLE in th-e MODES or other specified con di ti ans that may require ECCS Car DG) initiation* to mitigate the consequences o_f basi*s transient or *To ensure .reliable ECCS and DG. function; a ccirnbination of Functions is required to provide primary.and second<H'Y initiati_on signals. (continued) B 3.3-100 Revision No. 58 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UN IT 3 ECCS Instrumentation B 3.3.5.l The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis. Core Spray and Low Pressure Coolant Injection Systems l.a. 2.a. Reactor Vessel Water Level-Low Low Low (Level 1) reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The low pressure ECCS and associated DGs are initiated at Reactor Vessel Water Level -Low Low Low (Level 1) to ensure that core spray and flooding functions are available to prevent or minimize fuel damage. The DGs are initiated from Function l.a signals. This Function, in conjunction with a Reactor Pressure-Low (Injection Permissive) signal, also initiates the closure of the Recirculation Discharge Valves to the LPCI subsystems inject into the proper RPV location. The Reactor Vessel Water Level -Low Low Low (Level 1) is one of the Functions assumed to be OPERABLE and of initiating the ECCS during the transients analyzed in References 1 and 3. In addition, the Reactor Vessel Water Level -Low Low Low (Level 1) Function is directly assumed in the analysis of the recirculation line break (Ref. 4) and the control rod drop accident CCRDA) analysis. core cabling function of the ECCS, with the scram action of the Reactor Protection-System (RPS), ensures that the fuel peak cladding temperature_ remains below the limits-of 10 CfR 50.46. Reacto_r Vessel Water Level -Low Low Low (Level 1) signals from fdur Yevel that sense the_ difference between the pressur_e_ due to a constant column of ana:+/-he pressure to actual water 1 eve i ( v a ri a b 1 e l e g) -i_ n th e v e s s e l , The Reactor Vessel Water Level -.Low Low Low -(Level 1) Allowabfe Value is chosen to al,low t.ime for-the low pressure core systems tb activate and adequate -cooling;_ ---. . *. ' --Four channels of Reactor Vessel Water Level -Low Low Low _(Level 'l) Function are *on-ly. required to be OPE-RABLE when the *ECCS are.required to be-OPERABLE to erisure that no sing.le , __ _ instrument failure_ can precJ ude ECCS (continued) B Revi $ion No. 58 J BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY PBAPS. UN IT 3 ECCS Instrumentation B 3.3.5.1 1.a, 2.a. Reactor Vessel Water Level-Low Low Low (Level 1) (continued) Per Footnote (a) to Table 3.3.5.1-1, this ECCS Function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCD 3.5.2. Refer to LCD 3.5.l and LCD 3.5.2, Shutdown," for Applicability Bases for the low pressure ECCS subsystems; LCD 3.8.1, "AC Sources-Operating"; and LCD 3!8.2, "AC Sources-Shutdown," for Applicability Bases for the DGs. 1.b. 2.b. Drywell Pressure-High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary CRCPB). The low pressure ECCS associated DGs are initiated upon receipt of the Drywel 1 Pressure-High FunCti on with a Reactor Pressure-Low (Injection Permissive) in order to minimize the possibility of fuel damage. The DGs are initiated from Function 1.b
• signals. This Function also initiates the closure of the .recirculation discharge valves to ensure the LPCI subsystems inject into the proper RPV location. The Drywell Pressure-High Function with a Rea,ctor Pressure-Low (Injection Permissive), along with the Reactor Water Level-Low Low Low (Level 1) Function, is directly assumed in the analysis of the recitculation line break (Ref. 4). core cooling function of the ECCS, along the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. . . High drywell pressure signals are initiated from four pressure that sense drywel.l pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment. The Drywell Pressure-High is required to be OPERABLE when the ECCS or DG is required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. four channels of the CS and LPCI Drywell Pressure-High Function are required to be OPERABLE in MODES 1, 2, and 3 to ensure that no single instrument failure can preclude ECCS and DG initiation. In MODES 4 and 5, the Drywell Pressure-High Function is not required, since there is insufficient energy in the reactor to pressurize the primary containment to Drywell High setpoint. Refer to LCD 3.5.1 for AppJicability Bases for the low ECCS subsystems and to LC0.3.8.1 for for the DGs. (continued) B 3. 3-102 No. 58
• .. ,_-BASES APPLICABLE -SAFETY ANALYSES, LCD, and APPLICABILITY (continued) PBAPS UNIT 3 _ -ECCS Instrumentation B 3.3.5.1_ l.c, 2.c. Reactor Pressure-Low (Injection Permissive) Low reactor pressure signals are used as permissives for the low pressure ECCS subsystems. This ensures that, prior to opening the injection valves of the low pressure ECCS subsystems or initiating the low pressure ECCS subsystems -0n a Drywell Pressure-High signal, the reactor pressure has fallen to a value below these subsystems' maximum design pressure and a break inside the RCPB has occurred respectively. This Function also provides permissive for the closure of the recirculation discharge valves to ensure the LPCI subsystems inject into the proper RPV location. The Reactor Pressure-Low is one of the Functions assumed to be OPERABLE and capable of permitting initiation of ECCS during the transients analyzed in References 1 and 3. In addition, the Reactor Pressure-Low Function is di*rectly assumed in the analysis of the recirculation line break (Ref. 4). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CfR 50.46. The Reactor Pressure-Low signals are initiated from four pressure that Sense the reactor dome pressure. The-Allowable Value is low enough to prevent overpressuring -the equipment in the low pressure ECCS, but high enough to ensure that the ECCS injection prevents the fuel cladding from exceeding the limits of 10 CFR 50.46. -Four channels* of Reactor.Pressure-Low Function are only required to be OPERABLE when the ECCS ts required to be OPERABLE to ensure that no single failure can preclude ECCS Per fqotnote {a). to Table 3.3.5.1-1, this ECCS Function is only required to be OPERABLE . *in MODES 4 and 5 associated ECCS is required to -be OPERABLE per LCO 3.5.2. Refer to LCD 3.5.1 and LCD* 3.5.2 for Bases for the low ECCS subsystems.
• l.d. 2.g. Core Spray and Low Pressure Injection 'Pump Discharge (Bypass) The minimom flow are provided to the associated low pump frofu when the pump is and the associated injection valve is n-0t fully open. minimum flow line valve is opened When low flow_is sensed, and the is automatically closed when the fl ow rate is adequate to protect the pump. The LPCI and ( con ti n u d ) B. 3.3-103 Revision 58 BASES APPLICABLE SAFETY ANALYSES LCD, and APPLICABILITY PBAPS UN IT 3 ECCS Instrumentation B 3.3.5.l l.d. 2.g. Core Spray and Low Pressure Coolant Injection Pump Discharge Flow-Low (Bypass) (continued) CS Pump Discharge Flow-Low Functions are assumed to be OPERABLE and capable of closing the minimum flow valves to ensure that the low pressure ECCS flows assumed during the transients and accidents analyzed in References 1, 2, and 3 are met. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. One differential pressure switch per ECCS pump is used to detect the associated subsystems' flow rates. The logic is arranged such that each switch causes its associated minimum flow valve to open. The logic will close the minimum flow valve once the closure setpoint is exceeded. The LPCI minimum flow valves are time delayed such that the valves will not open for 10 seconds after the switches detect low flow. The time delay is provided to limit reactor vessel inventory loss during the startup of the RHR shutdown cooling mode. The Pump Discharge Flow-Low All.owable Values are high enough to ensure that the pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core. Each channel of Pump Discharge Flow-Low Function (four CS channels and four LPCI channels) only required to be OPERABLE when the associated ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude the ECCS function. Per footnote (a) to Table 3.3.5.1-1, this ECCS Function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems. l.e. l.f. Core Spray Pump Start-Time Delay Relay The purpose of this time delay is to stagger the start of the CS pumps that are in each of Divisions I and II to prevent overloading the power source. This Function is necessary when power is being supplied from the offsite sources or the standby power sources COG). The CS Pump Delay Relays are* assumed to be OPERABLE in the accident and transient analyses requiring ECCS initiation. That is, the analyses assume that the pumps will initiate when required and excess loading will not cause failure of the power sources. continued B 3.3-104 Revision No. 58 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 3 ECCS Instrumentation B 3.3.5.1 l.e. l.f. Core Spray Pump Start-Time Delay Relay (continued) There are eight Core Spray Pump Start-Time Delay Relays, two in each of the CS pump start logic circuits (one for when offsite power is available and one for when offsite power is not available). One of each type of time delay relay is dedicated to a single pump start logic, such that a single failure of a Core Spray Pump Start-Time Delay Relay will not result in the failure of more than one CS pump. In this condition, three of the four CS pumps will remain OPERABLE; thus, the single failure criterion is met (i.e., loss of one instrument does not preclude ECCS initiation). The Allowable Value for the Core Spray Pump Start-Time Delay Relays is chosen to be long enough so that the. power source will _riot be overloaded and short enough so that ECCS operation is not degraded. Each channel of Core Spray Pump Start-Time Relay Function is required to be OPERABLE only when the associated CS subsystem is required to .be OPERABLE. Per footnote (a) to Table 3.3.5.1-1, this ECCS Function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for* the CS subsystems. 2.d. Pressure-Low Low (Recirculation Discharge Valve Permissive) Low reactor pressure signals are used as permissives for valve closure. This ensures that the LPCI subsystems-inject into the proper RPV location assumed in the .safety analysis.* The Reactor Pressure-Low Low is _one of :the Functi ans assumed to be OPERABLE and capable of closing the valve duri"ng the tr.ansien:ts an*alyzed in References 1 .and 3. *The core cool_ing function of the. ECCS, along with the scram attiori cif the RPS,*ensures that -the fuel peak c"laddi.ng temp_erature the limits . of CFR 50 .46'., The_ Reactor Pressure-:--Low L'ow Function is 'di:rectly assumed' in the analysis of the "recirculation line break (Ref. 4). _: .-The Reactor-Pressure-Low Low signals' are* initiated from*. four pressure transmitters that the .*.,-;: ,. . -* . -. The-Allowable Value is chosen to: ensure that the valves* close prior to commencement of LPCI injection flow into the co"re,":as assurned in the safety analysis .. *(continued) B 3.3-105 Revision No. 58

.. -BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY "..;1 .-:--_;_.-.** -,-***.* ... f**,*' . * .* ',*,. .*_--: * .. PBAPS -UN IT 3 .-ECCS Instrumentation B 3.3.5.1 2.d. Reactor Pressure-Low Low <Recirculation Discharge Valve Permissive) (continued} Fo.ur channels of the Reactor Pressure-:-Low Low Function are only requfred to be OPERABLE in MODES 1, 2, and 3 with the associated recirculation:pump valve open. With the valve(s} closed, the function of the instrumentation has been performed; thus, the Function is not required. In MODES .4 and 5, the loop injection location is not critical -since LPCI injection through the recirculation loop in either direction will still ensure that LPCI flow reaches the core ( i . e. , there , is no_ significant reactor back pressure). * . 2. e.. Reactor Vessel Shroud Level -Level 0 The Reactor Vessel Shroud Level -Level o Function is provided .as a. permissive to allow the RHR System to be manually aligned.from the LPCI mode to the suppression pool cooling/spray or drywell spray modes. The reactor vessel shroud *level permissive. -ensures that water in the vessel is approximately :two thfrds core height before_ the manual transfer is allowed. This ensures that LPCI is available to prevent .. or minim1ze fuel damage. T_hi s function may be .overridden during accident conditions as allowed by plant* procedures. __ Reactor Vessel Shr,oud Level -Level o Function --is iinplic:itly assumed* in the analys_is of the recirculation line break (Ref. *4) *since,* the *analysis that nolPCI flow diversion occurs when rea*ctor water level is below -Level o> .. : .* . Reactor Vessel Shro.ud .Level -Level O signals are initiate_d *.

• from-.'level --transniitters that sense the difference between_the pressure _to a-const_ant column of water (reference .Jeg} .. and du_e tp the actual water * ]evel*-(Variable )e'g) in vessel.* The Reactor Vessel _ * -*Shroud-Level:.... Level -0 ATlowabl e Value is chosen to allow the 'Jaw p_ressure core flooding systems fa activate and provide': adequate-cooling bef.ore**_allowing a inanual -transfer. _ * * -*. *. . ... .. . . .. . .. -. **-. . . ' ' ' . , .. _ .-. *. . . -* .. ---; .** -----**:. *:: ' ,_ . : . *, :** . ' ' . **':'.**.\* ... * .. ... .. _ .. . 8 =3.3".:l06 . . :: .. ---.... :*,*.** 3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS' UN IT 3 .-.,: ECCS Instrumentation B 3.3.5.1 2.e. Reactor Vessel Shroud Level-Level 0 (coritinued) Two channels of the Reactor Vessel Shroud Level -Level 0 Function are only required to be OPERABLE in MODES 1, 2, and 3. In MODES 4 and 5, the specified initiation time of the LPCI subsystems is not assumed, and other administrative controls are adequate to control the valves associated with this Function (since the systems that the valves are opened for are not required to be OPERABLE in MODES 4 and 5 and are normally not .used). 2.f. Low Pressure Coolant In,jection Pump Start-Time Delay .Rtlll The purpose of this time delay is to stagger the start of the LPCI pumps that are in each of Divisions I and II, to prevent overloading the power source. This Function is only when power is being supplied from offsite sources. The LPCI pumps start simultaneously with no time delay as soon as the standby source is available. The LPCI Pump Start-Time Delay Relays are assumed to be OPERABLE in the accident and transient analyses requiring ECCS initiation. That is, the analyses assume that the pumps will initiate when required and excess loading will not cause failure of the power sources. There are eight LPC.I Pump Start-Time Delay Relays, two in ea6h of the RHR pump start logic circuits. Two time delay relays are dedicated to a single start logic. Both timers in the RHR pump start logic would have to fail to prevent an RHR pump from starting within the required time; the low pressure ECCS pumps will remain OPERABLE; thus, the s.ingle failure criterion is met (i.e., loss of one. does not preclude ECCS initiatirin) .. lhe Allowable Values for the LPCI Pump Start-Time Delay Relays are chosen to be 16ng enough so that most of the starting transient of the first pump is complete before starting the second pump on the same 4 k.V emergency bus and short enough so that ECCS operation is not degraded. Each channel of LPCI Pump Start-Time Delay Relay Function is required to be OPERABLE only when the associated LPCI subsystem is required to be OPERABLE. Per footnote (a) to Table 3.3.5.1-1, this ECCS Function is only required to be DPERABLE in MODES 4 and 5 whenever the associated ECCS i.s required to be .OPERABLE per LCD 3.5.2. Refer to LCD 3.5.1 and LCD 3.5.2 for Applicability Bases for the LPCI subsystems. continued B 3.3-107 Revision-No. 58 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued} PBAPS UNIT 3
• ECCS Instrumentation B 3.3.5.1 High Pressure Coolant Injection CHPCI) System 3.a. Reactor Vessel Water Level -Low Low (Level 2) Low RPV water level indicates that the capability to cool the fuel may be threatened. Should .RPV water level decrease too far, fuel damage could result. Therefore, the HPCI System is initiated at Level 2 to maintain level above the top of the active fue 1 . The Reactor Vesse 1 Water Level -Low Low (Level 2} is one of the Functions assumed to be OPERABLE and capable of initiating HPCI during the transients analyzed in References 1 and 3. Additionally, the Reactor Vessel Water Level -Low Low (Level 2} Function associated with HPCI is credited as a backup to the Drywell Pressure-High Function for initiating HPCI in the analysis of the recirculation line break. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Reactor Vessel Water Level -Low Low (Level 2} signals are initiated from four level transmitters that sense the ' difference between the pressure due to a constant column of *water (reference leg) and the pressure due to the actual water level (variable leg} in the vessel. The Reactor Vessel Water Level -Low Low (Level 2) Allowable Value is high enough such that for complete loss of feedwater flow, the Reactor Core Isolation Cooling (RCIC} System flow with HPCI assumed to fail will be sufficient to avciid initiation of low pressure ECCS at Reactor Vessel Water l -Low Low Low (Leve 1 1) . Four channels of Reactor Vessel Water Level -Low Low (Level 2) Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure cari initiation. Refer to LCO 3.5.1 for .HPCI Applicability Bases.* 3.b. Drywell Pressure,;,..Hiqh High pressure in the drywell could indicate a break in the RCPB. The HPCI System is initiated upon receipt of the . Drywell Pressure-High Function in order to minimiz'e the possibility .of fuel damage. The Drywell Pressure.-High Function is directly assumed in the analysis of the * (continued r . . . -. B 3 .. 3-:108 Revision No.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APP LI CAB IL ITV
• PBAPS UNIT 3 ECCS Instrumentation B 3.3.5.l 3.b. Drywell Pressure-High (continued) . recirculation line break (Ref. 4). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible to be indicative of a LOCA inside primary containment. Four channels of the Drywell Pressure -High Function are required to be OPERABLE when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.l for the Applicability Bases for the HPCI System. 3. c. Reactor Vesse 1 Water Level -Hi qh {Level 8) High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such that there is no danger to the fuel. Therefore, the Level 8 signal is used to trip the HPCI turbine to prevent overflow into the main steam lines (MSLs). The Reactor Vessel Water Level -High (Level 8) Function is assumed to trip the HPCI turbine in the feedwater controller failure transient analysis if HPCI is initiated. Reactor Vessel Water Level -High (Level 8) signals for HPCI are initiated from two level transmitters from the wide range water level measurement instrumentation. Both Level 8 signals are required in order to trip the HPCI turbine. This ensures that no single instrument failure can preclude HPCI initiation. The Reactor Vessel Water Level -High (Level 8) Allowable Value is chosen to prevent flow from the HPCI System from overflowing into the MSLs. Two channels of Reactor Vessel Water Level -High (Level 8) Function are required to be OPERABLE only when HPCI is required to be OPERABLE. Refer to LCO 3.5.l and LCO 3.5.2 for HPCI Applicability Bases. {continued) B 3.3-109. Revision No. 3

. . *':: < --. ' .... "-:.-. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY -(cont1nued} .,-* .. *. *, 3 .d. Condensate Storage Tank Level -Low ECCS Instrumentation B 3.3.5.1 Low level in the CST indicates the unavailability of an adequate supply of makeup water from this normal source. Normally the suction valves between HPCI and the CST are open and, _upon receiving a HPCI initiation signal, water for HPCI injection would be taken from the CST. However, if the water level in the CST falls below a preselected level, first the suppression pool suction valves automatically open, and then the CST suction valve automatically closes. This ensures that an adequate supply of makeup water is . _available to the HPCI pump. To prevent losing suction to the punip, the suction valves are interlocked so that the pool suction valves must be open before the CST suction valve automatically closes. The Function is

• implicitly assumed the accident-and transient analyses (which take credit for HPCI} since the analyses assume that the HPCI suction source is the suppression Condensat*e Storage Tank Level -Low signals are initiated _ from two 1eve1 swi tc;hes .. the 1 ogi c is arranged such that either 1evel switch can cause the suppressi-0n pool suction Valves to open and the CST suction valve to -The Condensate Storage Tank Low Function Allowable Value is high enough to ensure adequate pump suction head while -'
• water is. being taken from_ .the CST. -* Two charinels of the' Condensate st_orage Tank -Low -* Func:tlon are. required* to be OPE'.RABLE only when *HPCL is _required to be OPERABLE to ensure that no single instr.(Jment can preclude HPCI swap to suppression pool source. to . LCO 3 5 .1 for HPC I Appl i Bases. -3 , Poor: water Level ::. High: --. . *.:* .*'*. . ,*.;* . _. --. '.. . *>,I * * *. *' . ,*. ,': .... -,_,,' .. -... : '"'** -' .. ;.::-:: ->'*:. *: * ... : ' . , : . -... _ ....... *-PBAPS-UNIT 3* ... * .. Excessively high su:ppres:sion pool-water could result in the _ loads--on'the::soppressie>n pool exceeding desJgn values *:there )e: a:-b 1 c;>wdowi{ pf 'the.. reactor vess_e l pres.sure *
• ___ the /reli'E!f va1 ves. \ .indi eating. _. * -high suppre_ssion: pool water .1 e.Vel are used to *.transfer -*suction so_uf'.ce*_of HPCI from the CST to the suppression -pool to elimjnale the possi.bil ity Of "HPCJ continuing to .provide' additional watEfr from a .source outside containment.. To -)reven'f Josi ng_ the the suction valves are '-interlot:;ked -:so *that the i>e>ol *suction be.-.-0pen before-the CST suction_-valve-automatically -. -... ... -* . ,., ... ' .. _.*, *.--. -'_ .. _. *" : . .£ ---< conli riuedl. _ : . ,*** :Revision -No. _3' BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY ECCS Instrumentation B 3.3.5.I 3.e. Suppression Pool Water Level -High. (continued) This Function is implicitly assumed in the accident and transient (whith take credit for HPCI) since the analyses assume that the HPCI suction source is the suppression pool. *
• Suppressibn Pool Water Level -High signals are initiated from two .1 eve l switches. The 1 ogi c is arranged such that either switch can suppression pool suction valves to open*and the CST suction valve to close. The Allowable Value_ for the Suppression Pool Water Lev'el -High Function is chosen_t6 ensure that'HPCI will be aligned for suction from the pool to pfevent HPCI from contributing to any further increase in the *suppressi-0n pool level. *
• Two of Suppression Pool Water Level .... High Function are required'to be OPERABLE only when HPCI is required to be OPERABLE to* ensure that no single instrument failure tan preclud¢ HPCI swap t6 suppression pool source. Refer to LCD HPCI AppliC:ability Bases. 3.f. lnjectirin Discharge Fl ow.;:,; Low (Bypass) -The min-imum flow instrument is provided *to* protect the HPCI
• pump 'from overheating when operating reduced -flow. The minimum flow line valve is opened when low flow is sensed, arid valve is wheh the -flow rate is adequate to protect the pump.* Th_e High _-Pressure Cool ant -lnjecti on Pump Discharge -Flow-Low Furict i ori -is assumed to be OPERABLE and. capable of closing the minimum fl ow :valve to ensure' that the ECCS fl ow a:ssumed during the 'trans;'en:tsan'alyzed is The core cooling *aron-9 .wfth* the _scram acticin of the RPS-; ensures that. the',fuel peak Cladd1ng temperature remains *below the lim_itsof]O CFR.50.46. * ,,,. :." .--. -* ' -* ....... -* *-, --*One flbw:switc'h_ HPti --* rate.* l:he logic js arranged such that_ the transmitter ---,c;auses: minimun:i flow vµlve to* open*.* .The :logic will . the mi_niirium :fl ow valve, once the cl setpoi nt is *. * ------* * --* -.., _\ -* .-, ... :*, . . *.*:.,-' __ ,._*. (Continued}-* -' ,* ,***. ._. -*. -*-.* '.: : ."'-.... -. ' PBAPS.UN-IT _ 3 -. '. __ , 3 -.-.. ' *.

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILIT-Y PBAPS UN IT .3 ECCS Instrumentation B 3.3.5.1 3.f. High Pressure Coolant Injection Pump Discharge Flow-Low (Bypass) (continued) The High Pressure Cciolant Injection Pump Flow-Low Allowable Value is high enough to ensure that pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core. One channel is required to be OPERABLE when the HPCI is required to be OPERABLE. Refer to LCO 3.5.1 for HPCI Applicability Bases. Automatic Depressurization System 4.a. 5.a. Reactor Vessel Water Level-Low Low-Low (Level ll Low RPV water level indicates that the capability to cool the fuel may be Should RPV water level decrease too far, fuel damage could result. Therefore, ADS receives one of the signals necessary for initiation from this Function. This signal_ actuates the Function 4.h, 5.h timer. I_ The Reactor Vessel Water -Level -Low Low Low (Level 1) i.s one of the Functions assumed to be OPERABLE and capable of initiating the ADS during the accident analyzed in 'Reference 4. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature below the limits of 10 CFR 50.46. Reactor Vessel Water Low Low Low (Level 1) signals are initiated from four level transmitters that sense the difference between -the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the Four channels of Reactor Vessel Water Level-Low Low Low (Level 1) Function are required to be OPERABLE only when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A, while the other two channeJs input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases. The Reactor Vessel Water Level -Low Low Low (Level 1) Allowable Value is chosen to allow time for the low pressure core flooding systems to initiate and adequate cooling. continue B 3.3-112 Revisi_on No. 79 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS LI.NIT 3 4.b. 5.b. Drywell Pressure-High ECCS Instrumentation B 3.3.5.1 High pressure in the drywell could indicate a break in the RCPB. Therefore, ADS receives one of the signals necessary for initiation from this Function in order to minimize the possibility of fuel damage. The Drywell Pressure-High is assumed to be OPERABLE and capable of initiating the ADS during the accidents analyzed in Reference 4. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Drywell Pressure-High signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible .and *be indicative of a LOCA inside primary containment. Four channels of Drywell Pressure-High Function are only required to be OPERABLE when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A, while the other two channels input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases. 4.c, 5.c. Automatic Depressurization System Initiation Timer The purpose of the Automatic Depressurization System Initiation Timer is to delay depressurization of the reactor vessel to allow the HPCI System time to ma.intain reactor* water level. the rapid caused by ADS operation is one of the most severe transients on the reattor vessel ,-its occurrence should be l iini ted. By del'aying initiation of the ADS Function, *the operator is gtven the thance to.monitor the success or failure of the HPCI System to maintain water 1 eve.l, and then to decfde whether or not to allow ADS* to initiate, to delay initiation* further by recycling the.timer, or to inhibit initiation

• permanently. The Automatic Depressuri zat ion System *. * ... Initiation Timer Function is ass1,1med to be.OPERABLE for :the accident analysis of Reference 4 that requires ECCS initiation and assumes failure of the HPCI System. {continued) B 3.3-113 *Revision No. 3 _J BASES APPLICABLE SAFETY ANALYSES, LCO, and . APPLICABILITY PBAPS UNIT 3 ECCS Instrumentation B 3.3.5.1 4.c. 5.c. Automatic Depressurization Svstem Initiation Timer (continued) There are two Automatic Depressurization System Initiation Timer relays, one in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Initiation Timer is chosen so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling. Two channels of the Automatic Depressurization System Initiation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases. 4.d. 5.d. Reactor Vessel Water Level -Low Low Low (Level 1) (Permissive) Low reactor water level signals are used as permissives in the ADS trip systems. This ensures after a high drywell pressure signal or a low reactor water level signal (Level 1) is received and the timer times out that a low reactor water level (Level 1), signal is present to allow the ADS initiation (after a confirmatory Level 4 signal, see Bases for Functions 4.e, 5.e, Reactor Vessel Water Confirmatory Level -Low (Level 4). Reactor Vessel Water Level-Low Low Low (Level 1), signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure doe to the actual water level (variable leg) in the vessel. The Reactor Vessel Water Level-Low Low Low (Level 1) Allowable Value is chosen to allow time for the low pressure core flooding system to initiate and provide adequate cooling. Four channels of the Reactor Vessel Water Level -Low Low Low (Level 1) Function are required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A while the other two channels input to ADS trip system B. Refer to LCD 3.5.1 for ADS Applicability Bases. (continued) B 3 .3-114 Revision No. 3 BASES APPLICABLE *SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS UNIT 3-. ECCS Instrumentation B 3.3.5.1 4. e, 5. e. Reactor Vesse 1 Water Confirmatory Leve 1 -Low {Level 4) The Reactor Vessel Water Confirmatory Level -Low (Level 4) Function is used by the ADS only as a confirmatory low water level signal. ADS receives one of the signals necessary for i nit i at ion from Reactor Vesse 1 Water Leve 1 -Low Low Low (Level 1) signals. In order to prevent spurious initiation of the ADS due to spurious Level 1 signals, a Level 4 signal must also be received before ADS initiation commences . . Reactor Vessel Water Confirmatory Level -Low (Level 4) signals are initiated from two level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Allowable Value for Reactor Vesse 1 Water Confirmatory Leve 1 -Low (Level 4) is selected to be above the RPS Level 3 scram Allowable Value for convenience. Two channe 1 s of Reactor Vesse 1 Water Confirmatory Leve 1 -Low (Level 4) Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. One channel inputs to ADS trip system A, while the other channel inputs *to ADS trip system B. Refer to LCO 3.5.1 for ADS App 1 i cab,i 1 ity 4.f, S.f, 5.g. Core Spray and.Low Pressure Coolant . Injection Pump Discharge Pressure-High The Pump Discharge .P.ressure -High s igna 1 s from th_e CS and LPCI pumps are as permissives for ADS initiation, indicating that there is a source of.low pressure cooling water. available once the ADS has depressurized the vessel. Pump Discharge Pressure:-High is one:of the Functions * . assumed to be OPERABLL and capable of permitting ADS .. in it i on dur.i ng the events analyzed in Reference 4 *with an .. assumed .HPCI failure. For: these events the ADS reactor so that*the'low pressure .ECCS can perform the core cooling functions. This core cooling.function of the ECCS, along with the scram acti.on of .the RPS, that the fuel peak cladding temperature remafos be lOw the limits of 10 CFR 50. 46. . (cont i-ni.Jed) . . B 3 .3.,-115 . Revision No .. -3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 3 ECCS Instrumentation B 3.3.5.1 4.f, 4.g, 5.f, 5.g. Core Spray and Low Pressure Coolant Injection Pump Discharge Pressure-High {continued) Pump discharge pressure signals are initiated from twelve pressure transmitters, two on the discharge side of each of the four LPCI pumps and one on the discharge side of each CS pump. There are two ADS low pressure ECCS pump permissives in each trip system. Each of the permissives receives inputs from all four LPCI pumps {different signals for each *permissive) and two CS pumps, one from each subsystem {different pumps for each permissive). In order to generate an ADS permissive in one trip system, it is necessary that only one LPCI pump or two CS pumps in proper combination (C or D and A or 8) indicate the high discharge pressure condition in each of the two permissives. The Pump Discharge Pressure-High Allowable Value is less than the pump discharge pressure when the pump is operating in a full flow mode and high enough to avoid any condition that results in a discharge pressure permissive when the CS and LPCI. pumps are aligned for injection and the pumps are not running .. The actual operating point of this function is not assµmed in any transient or accident analysis. However, this Function is indirectly assumed to operate (in Reference 4) to provide the ADS permissive to depressurize the RCS to .allow the ECCS low pressure systems to operate. -. . . Twelve channels of Core Spray and Low Pressure Coolant lnjectf<:m Pump Discharge Pressure-High Function are only required to be OPERABLE .when the ADS is required to be OPERABLE to ensure that n*o single instrument failure can preclude ADS initiation. Four CS channels associated with CS pumps A through D and eight LPCI channels associated with LPCI*pumps.A through Dare required for both trip systems. Refer to LCO 3.5.1 for ADS Applicability Bases.
• 4.h. 5.h.
• Depressurization *system Lc:iw Water Level Actuation Timer
• One cJ"f'the signals.:requi.red for ADS. initiation is Drywell Pressure...:.High .. *However, .if the event requiring ADS .. initiafion occurs outs.ide the drywell (e.g., main steam line, br*eak outside containment),* *a high drywell pressure signal may never be present. Therefore, *the Automatic . *Depressurization System Low Water Level ,ACtuation Timer is.* used to bypass the Orywell.Pressure""'."High Function after a. -**. (continued) B 3,3-'116 Revi sioir* No.. 3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY ACTIONS PBAPS UNIT 3 ECCS Instrumentation . B 3.3.5.1 4.h, 5.h. Automatic Depressurization System Low Water Level Actuation Timer (continued) certain time period has elapsed. Operation of the Automatic Depressurization System Low Water Level Actuation Timer Function is assumed in the accident analysis of Reference 4 that requires ECCS initiation and assumes failure of the HPCI system. The.re are four Automatic Depressuri zat ion System Low Water Level Actuation Timer relays, two in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Low Water Level Actuation Timer is chosen to ensure there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling. four channels of the Automatic System Low Water Level Actuation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Refer to LCO 3.5.1 for ADS Applicability Bases. A Note has been provided to modify the ACTIONS related to *Eccs instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within 1 imits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions . of the Condition continue to apply for each additional . failure, with Completion Times based on initial entry* into the Condition. *However,* the Required Actions for inoperable ECCS instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable ECCS instrumentation channel. Required Action A.I directs entry into the appropriate Condition referenced in Table 3.3.5.1-1. The applicable referenced in the table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequerit Condition. <continued) B 3.3-117 Revision No*. 3.

BASES ACTIONS (continued} PBAPS UNIT 3 B.I. B.2. and B.3 ECCS Instrumentation B 3.3.5.I Required Actions B.I and B.2 are intended to ensure that

• appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic initiation capability being lost for the feature(s}. Required Action B.1 features would be those that are initiated by Functions I.a, I.b, 2.a, and 2.b (e.g., low pressure ECCS). The Required Action system would be HPCI. For Required Action B.I, redundant automatic initiation capability is lost if (a) two or more Function I.a channels are inoperable and untripped such that both trip systems lose initiation capability, (b) two or more Function 2.a channels are inoperable and untripped such that both trip lose initiation capability, (c} two or more Function I.b channels are inoperable and untripped such that both trip systems lose initiation capability, or (d} two or more Function 2.b channels are inoperable and *
• untripped such that both trip systems lose initiation capability. For low pressure ECCS, s i nee each inoperable .. thannel would have Required Action B.I applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system of low pressure ECCS and DGs to be declared inoperable. However, since channels in both associated low pressure ECCS
• subsystems (e.g., both CS subsystems) are inoperable untripped, and the Completion Times started concurrently for the in both subsystems, this results in the . affected portions in the associated low pressure ECCS and
• DGs being concurrently declared inoperable. For Required Action B.1, redundant. automatic HPCI initiation capabil i ti is lost if two or more Function 3. a or two . Fuhction 3.b channels are inoperable and untripped such that the trip system loses capability. *in this situation (loss of redundant automatic initiation
• the 24 hour a 11 owance of Required Act idn B. 3 is not appropriate*and the HPCI System must be declared inoperable within l hoor. As noted 1 to -* :Acticih B.I), Required Action B.1 is only in 1, 2, and 3. In MODES 4 and 5, specific initiation time of the low pressure ICCS not assumed and the probability. of a LOCA is lower. Thus. a total loss. of *. (continued) B 3.3-118 Revision 3 BASES ACTIONS PBAPS UN IT 3. B.l. B.2. and B.3 (continued) ECCS Instrumentation B 3.3.5.1 initiation capability for 24 hours (as allowed by Required Action B.3) is allowed during MODES 4 and 5. There is no similar Note provided for Required Action B.2 since HPCI instrumentation is not required in MODES 4 and 5; thus, a Note is not necessary. Notes are also provided (Note 2 to Required Action B.l and the Note to Required Action B.2) to delineate which Required Action is applicable for each Function that requires entry into Condition B if an associated channel is inoperable. This ensures that the proper loss of initiation capability check is performed. Required Action B.l (the Required Action for certain inoperable channels in the low pressure ECCS subsystems) is not applicable to Function 2.e, since this Function provides backup to administrative controls ensuring that operators do not divert LPCI flow from injecting into the core when needed. Thus, a total loss of Function 2.e capability for 24 hours is allowed, since the LPCI subsystems remain capable of performing their intended function. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action B.l, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable; untripped channels within the same Function as described in the paragraph above. For Required Action B.2, the Completion Time only begins upon discovery that the HPCI System cannot be automatically initiated due to two inoperable, untripped channels for the associated Function in the same trip system. The l hour Completion_ Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the (continued) B 3 .3-119 .. Revision No. 3 BASES ACTIONS .-*.:* .. PBAPS UNIT 3* B.l, B.2. and B.3 (continued) ECCS Instrumentation B 3.3.5.1 allowable out of service time, the channel must be placed in the tripped condition per Required Action B.3. Placing the inoperable channel in trip would conservatively .compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken. C. l and C. 2 Required Action C.l is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function result in redundant automatic initiation capability being lost for the feature(s). Required Action C.l features would be those that are initiated by Functions l.c, l.f, 2.c, 2.d, and 2.f (i.e., low pressure ECCS). Redundant automatic initiation capability is lost if either (a} two or more Function l.c channels are inoperable i.n the same trip system suC:h that the trip system loses initiation capability, *(b) two*or more Function 1.-e * *channels are inoperable affecting CS in different (c) or more Function l.f channels are . inoperable affecting CS pumps:in different-subsystems, (d) two or more Function are inoperable the same trip system such that the trip system l-0ses initiation capability, (e} two or more Function 2.d channels are* inoperable in the same trip system sucn that.the trip system lOses initiation_ capability, or.(f} .three.or more FunctiiJn 2. f chan'f1e ls are inoperable. . In this situation of*redundant automatic ihitiatibn.capability}, the 24 hriur allowance of Required C.2 is not *appropriate and the the inoperable channels must be declar.ed inoperable within 1 hqur. *Since each inoperable channel would have-Required Action* C.1 applied * (refef to ACTIONS Nbte}, each inoperable channel would the affected portirih of the associated *system to be declared inoperable. However, since channels .for Qoth low pressure ECCS subsystems are inpperable (e.g., .both CSsubsystems), and the*.completion Tim.es started **.-cohcurrentlyfor the chanri.els -in both subsystems,* this* results in the portions* in b()th-subsystems being (continued). B 3.3:-120 Revision No*. 3

,.*. BASES *ACTIONS (continued)* *-:. D.I. D.2.li and D.2.2 ECCS Instrumentation B 3.3.5.1 Required Action D.l is intended to ensure that appropriate acticms are t_aken if multiple, inoperable,* untripped channels within the same Function result in a complete loss of automatic component initiation capability for the HPCI System. Automatic component initiation capability is lost if two Function 3.d channels or two Function 3.e channels *are inoperable and untripped. In this situation (loss of *automatic suction swap), the 24 hour allowance of Required .Actions Il;2.l and D.2.2 is not appropriate and the HPCI System must be declared inoperable within 1 hour after discovery of loss of HPCI initiation capability. As noted, Required Action D.l is only applicable if _the HPCI suction is not aligned to the suppression pool, since, if al i gned, 'the Function. is al ready performed. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Comp l et ibn Ti me al so a 11 ows for an except ion to the normal * "time zeron for beginning the allowed outag.e time "clock .. " For. Required Action 0; I, :'the Completion Time only *begins upon discovery that the HPCI System cannot be automatically tb the suppression pool due to two inoperable, untripped channels in the* same Function. The l hour CmnpJetion Time from d1scovery of *loss of initiation

• capability is acceptable ;because it minimizes risk while tjme for rest6ration or tripping,of channels .. * . *, '
• Becat.fs*e-of the.diversity sensors available to provide.
• initi.ation signals and the redundancy of the ECCS design, an ... allowabJe out of service .time of 24_ hours has been show.n to. *be acceptable (ReL 5) to pe_rmit restoration of any ... *
• irioperaple channel* to.OPE.RABLE status. If the inoperable. channel _cannot*:be restofed*. tcf OPERABLE .. within the
• allowable *out of :s*e*rvi.c;e* time;; the channel must: be placed in *.the tri_pped conditic:m* per*Requtred Action* i**_or ... * 'sticti cirr s,ource must. be aligned to the suppression pool per .*.* . . Required*Adion *Placlng the*inoperable channel 'in* . trip performs 'the/intended funcfio11--of the channel (snifting-. the . su(t ion source to the. s1,1ppress ion pool)'. Performance of . *. * *
• either of* these.two Required Actions *will allow operation to ._
• continue. If Required Action D. 2 .1 or D 2. 2 is performed, meas,ures should .be. taken to ensure that the HPCl.*System . . :.= ' .' . -" ** ... *-*.,.' PBAPS.* UN IT 3 .... :**,' . ... * .. ' ... . . ' ; .. *.* . (continued) ,,.*

BASES ACTIONS . ' . *. *. ,.-*.-.. ,-*. .-*-_ I *. UNIT 3 . *, h *1., *, * ,*. ,. ' ' . ,*_ -. D.l. D.2.1. and (continued) **

• ECCS Instrumentation B 3.3.5.1 piping remains filled wiih water *. Alternately, if it is not desired to perform Required Actions *o.2.1 and 0.2 *. 2 (e.g., as in the case where shifting the suction.source could.drain down the HPCI suction piping), Condition H must be entered and. its Required Action taken. E. l and E.2 Required Action E.l is intended to ensure* that appropriate actions are taken if multiple, inoperable channels within the Core Spray and Low Pressure Cool ant Iriject ion Pump, Discharge Flow -Low (Bypass) Functions result in redundant automatic initiation capability being lost for the ' feature(s). For Required Action E.l, .the features would be those that are .initiated by Functions l.d and 2.g (e.g., low pressure ECCS). Redundant automatic initiation capability is lost if (a) two or more Function l.d channels are
• affecting CS pumps in different or* (b) three or more Function 2.g channels are inoperable. Since each inoperable channel would have Required Action E.l applied separately (refer to ACTIONS Note), each inoperable would only require the affected low pressure ECCS
• pump to be . dee la red
• inoperable.
• However, s i nee chanrie ls for . mo.re th_an one low pressure ECCS pump are*. inoperable, and the Comp let i ()n Ti mes started concurrently for the .cha:nne ls of the low pressure ECCS pumps, this .ih the affected low pressure Eccs* pumps being concurrently declared inoperable. * * * * *In .this s*ituation (loss of redundant automatic* initia*t_ion . capability), .the 7 day allowance of Action E.2 is not. appropriate and the subsystem associated with each inoperable channel must be: declared inoperable within 1 hour.* As noted (Note 1 to Required Action E.l), Required Action E.l is only applicable in MODES 1, 2, and 3 .. In
• MODES 4 and 5, the specific initiatiOn time. of the ECCS is not assumed and the probability of a LOCA is lower. *Thus, a total loss of initiation capability for 7 days (as allowed by Required Action E.2) is allowed during MODES 4 and 5. A . . Note is .also provided (Note 2 to Required Action E.l) to delineate that Required Action E.lisonly applicable to low *.(continued) .. * ---.-**:-:. . *. '. -: :* . . 3.3:_123 ... . ' : ' * * * . 3 .** **. ,. .*' .. :.* . ,, . I BASES ACTIONS PBAPS UNIT. 3 -* E. l and E. 2 (continued) ECCS Instrumentation B 3.3.5.1 pressure ECCS Functions. Required Action E.l is not applicable to HPCI Function 3.f since the loss of one channel results in a loss of function (one-out-of-one logic). This loss was considered during the development of Reference 5 and considered acceptable for the 7 days allowed by Required Action E.2. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal 11time zero" for beginning the allowed outage time 11clock. 11 For Required Action E.l, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels. If the instrumentation that controls the pump minimum flow valve is inoperable, such that the valve will not automatically open, extended pump operation with no injection path available could lead to pump overheating arid fa i1 ure. If there were a fa i 1 ure of the instrumentation, such that the would not automatically close, a portion
• of the pump flow could be*diverted from the reactor vessel injection path, causing insufficient core cooling. These consequences can be averted by the operator's manual control .of the valve, which would be adequate to maintain ECCS pump protection and required flow. Furthermore, other ECCS pumps be sufficient to the assumed safety furiction . if no additional single failure were to occur. The 7 day Completion-Time of Required .Action E.2 to restore the .inoperable channel to OPERABLE status is reasonable based on *the remaining capability of the associated ECCS subsystems, the available in the ECCS design, and the lciw probability of a OBA occurring during the allowed out of service time. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, -Condition H must be entered and its Required Action taken. --The Required Actions do not allow placing the channel in trip _since this action would not necessarily result in a* safe for the channel in all events. --(continued) B 3.3-124 . Revision. No. 3.
• BASES ACTIONS (continued) PBAPS UNIT 3 F.1 and F.2 ECCS Instrumentation B 3.3.5.1 Required Action F.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within similar ADS trip system A and B Functions result in redundant automatic initiation capability being lost for the ADS. For example, redundant automatic initiation capability is lost if either (a) one or more Function 4.a channel and one or more Function 5.a channel are inoperable and untripped, (b) one or more Function 4.b channel and one or more Functiorr 5.b channel are inoperable and untripped, (c) one or more Function 4.d channel and one or more Function 5.d channel are inoperable and untripped, or (d) one Function 4.e channel and one Function 5.e channel are-inoperable and untripped. In this situation (loss of automatic initiation capability), the 96 hour or 8 day allowance, as applicable, of Required Action F.2 is not appropriate and all ADS valves must be declared inoperable within 1 hour after discovery of loss of ADS initiation capability. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" beginning the allowed outage time "clock." For Required Action F.l, the Completion Time only begins upon discovery that the ADS cannot _be automatically initiated due to inoperable, untripped channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE. If either HPCI or RCIC is inoperable, the time is shortened to 96 hours. If the status of HPCI or RCIC changes such that the Completion Time changes from 8 days to 96 hours, the 96 hours begins upon discovery of HPCI or RCIC inoperability. However, the total time for an inoperable, untripped channel cannot exceed 8 days. If the status of (continued B 3.3-125 Revision No. 59 BASES ACTIONS *"'* :.*'. PBAPS. UN IT 3 F.l and F.2 (continued) ECCS Instrumentation B 3.3.5.1 HPCI or RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable, untripped channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condit{on per Required Action F.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result. i.n an initiation), Condition H must be entered and its Required Action taken. G.l and G.2 Required Action G.l is intended to ensure that appropriate actions are taken if multiple; inoperable channels within similar ADS trip system Functions result in automatic initiation* capability being lost for the ADS. For example, automatic initiation capability is lost if either (a) one *. functfon 4.c channel and one Function 5.c channel are lb) a of 4.f, 4.g, 5.f,. and 5.g £tiannels such that
• five or more low pressure ECCS pumps are inoperable, or (c) one or Funttion 4.h channels and one or 5.h channels are IA this situation of automatic.initiation capability),.* the 96.hour or a* da}' allowance, as appiicaole, of Required Action. G.2 is not appropr.iate, and all ADS va.lves must be declared i hour after.discovery of.loss of* . ADS-initiat1on capapility. . . *1 . . . The Completion :Timefs *inte'nded to a*llow the operator time tO evaluate a'nd. repair any* di sc6vered i noperabil it i es. Thi. s allows for an to the "time Zero". for beginning.the allowed outage time "clock." For Requ_ired Act1on_G.l, the Completion Time_.o.nly begins ,*,*-. -. *ccontiriued). ,-.-.. B 3. 3-126 .
• Revision No; 84 BASES ACTIONS PBAPS UNIT. 3 L_ __ G.l and G.2 (continued} ECCS Instrumentation B 3.3.5.1 upon discovery that the ADS cannot be automatically initiated due to inoperable channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. *Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE (Required Action G.2). If either HPCI or RCIC is inoperable, the time shortens to 96 hours. If the status of HPCI *or RCIC changes such that the Completion Time changes from 8 days to 96 hours, the 96 hours begins upon discovery of HPCI or*RCIC inoperability. However, the total time for an inoperable channel .cannot exceed 8 days. If the status of HPCI or RCIC changes such that the Completion Time changes from 96 hours to.a days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable channel. If the inoperable channel cannot be *restored to OPERABLE status within the allowable out of service time, Condition H must be and its Required Action .taken. The Required Actions do not allow placing the channel. in trip since this action would not necessarily result in a safe state for the channel in all events. With :any Required Action,and Completion Time not met, the associated feature(s) may .be incapable of
• performing the intended function, and the supported . associated with inoperable untripped channels must -t>e declared ,inoperable immediately_. ---(continued) B 3.3:.,..127 Revision No. 3 BASES (continued) SURVEILLANCE .REQUIREMENTS P.BAPS UN IT 3 ECCS Instrumentation B 3.3.5.l As noted in the beginning of the SRs, the SRs for each ECCS instrumentation Function are found in the SRs column of Table 3.3.5.1-1. The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely f6r performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours follows: (a) for Functions 3.c and J.f; and (b) for Functions other than 3.c and 3.f provided the* associated Function or thi redundant Function maintains ECCS initiation capability.* Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE or the applicab1e Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 5) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the ECCS will initiate when necessary. SR 3.3.5.1.1 Performance of the CHANNEL CHECK ensures that a gross failure bf ihstrumentation not occurred. A CHANNEL CHECK is n o rm a 11 y a co mp a r i s o n of t h e p a ram et e r i n d i ca t e d o n o n e channel to a similar parameter on other channels. It is based bn the assumption that instrument monitoring the same parameter should read approximately the value. deviaticins the instrument channels could .be indlcation of excessive instrument drift one of channels or something even more A CHANNEL CHtCK guarantees that undetected outright channel failure is thus, it is key to verifying the instr0mentation continues to operate properly between each CHANNEL CALIBRATION. Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a thannel is outside the criteria, it may be an indication that the has drifted outside its limit. continued B 3.3d28 Revision No. 87*

BASES SURVEILLANCE REQUIREMENTS PBAPS 'UN IT 3 .. SR 3.3.5.1.l (continued) ECCS Instrumentatiun B 3.3.5.1 The Survei 11 ance Frequency is controlled under the

• 1
• Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCD. SR 3.3.5.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequehcy is contrcilled under the Surveillance Control Program. SR 3.3.5.1.3 and SR 3.3.5.1.4 A CHANNEL CALIBRATION is a complete of the instrument and the sensor. This test verifies the channel to fhe measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent.with the assUmpti*ons of the specific setpoint The. 11 anc.e Frequency is controlled* under the Survei 11 ance Frequency Control Program. continued B 3.3-129 Revision No. 87 I I BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UN IT 3 SR 3.3.5.1.5 ECCS Instrumentation B 3.3.5.1 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 6.5. 2. UFSAR, Section 7.4. 3. UFSAR, Chapter 14. 4. NEDC-32163-P, "Peach Bottom Atomic Power Station Units 2 and 3, SAFER/GESTR-LOCA, Loss-of-Coolant Accident Analysis," January 1993. 5. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988. B 3.3-130 Revision No. 87
• RCIC System Instrumentation B 3.3.5.2 B 3.3 INSTRUMENTATION B 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation BASES BACKGROUND PBAPS UN IT 3 -The purpose of the RCIC System instrumentation is to initiate actions to ensure *adequate core cooling when the reactor vessel is isolated from its primary heat sink (the main condenser} and normal coolant makeup flow from the Reactor Feedwater System is insufficient or unavailable, . such that RCIC System initiation occurs and maintains reactor water level such that an initiation of the low pressure Emergency Core Cooling Systems (ECCS} pumps does not .occur. A more complete discussion of RCIC System operation is provided in the Bases of LCO 3.5.3, "RCIC System." The.RCIC System may be initiated by automatic means. Automatic initiation occurs for conditions of Reactor Vessel . Water Level -Low Low (Level 2). The variable is monitored by four transmitters that are connected to four pressure compensation instruments. The outputs of the pres.sure compensation instruments are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic * .. Once initiated, the RCIC logic seals in and can be reset.by the operator only when the reactor vessel waterJevel signals have cleared. lhe RCIC test line isolation valve is closed on a RCIC initiatidn signal to allow full system flow and maintain primary containment;isoliited in the event RCIC is not bperating. * *rhe RCICSystem also monitors the water level in the condensate storage tank.(CST} since this the .initial , .source of water *for RCJC operation.
• Reactor grade water in -the. est is the normal sour_ce. -Upon .receipt of. a RCIC .. -* *Jnitiatit>n s*ignal, 'the CST suction *valve i's automatically signaled .to open (it is normally in the open positiOn}
• unless t.he pump suction from the suppression pool valves -i,s open. If _the water level in the CST falls below a . preselected 1eve1 , . first the* suppression po_ol suet ion va 1 ves open, and then the CST.suction valve* _ *
• automat teal l y closes. Two level switches are used to deteC:t . 1 ow water level in the CST. E_i ther switch can cause the -suppression s_uction valves *to open. The opening of the ... ' {continued) -. . . B 3.3-131 Revision No. -3 I -------------------------------------BASES BACKGROUND * (continued) . -. . . . APPLICABLE RCIC System Instrumentation B 3.3.5.2 suppression pool suctiori valves the CST suction valve to close. This prevents losing suction to the pump when
• automatically transferring suction from the CST to the suppression pool on low CST level. *
• The RCIC System provides makeup water to the reactor until the reactor vessel water reaches the high water level _(Le_vel 8) setting (two-out-of-two logic}, at which time the RCIC steam supply valve c:loses. The RCIC System restarts if vessel level again drops to the low level initiation point (Level . 2). . SAFETY ANALYSES, LCO, _and The of-the RCIC System is respond to transient events by producing makeup coolant to the reactor. The RCIC is not an Engineered Safeguard System and no credit : APPLICABILITY : *:' --*. ' ... -* .. . . ; . . *, -is taken in the safety analyses for RCIC System operation. Based oh to the reduction of overall plant risk, however, the system, -and therefore its instrumentation meets' Criterion 4 *of NRC pol icy Statement. The OPERABILITY of the RC.le i nstrumen.tat ion is dependent *upon the OPERABILITY of the individual instrumentation channel .. FLlnctions specified in -* -Table. '3.3.5.2:...l. Each Funct*ion must have a required number of _OPERABLE channels wiJh their setpointswithin the .. specified Allowable Values, A chanrie 1 is inoper:ao]e if its actual trip setting is not within its ' required Allowable Value._ The actual setpoint is calibrated 'consistent'with applicable setpoint methodology assumptions. * -. Ali .Values fi for e'ach RCIC System * -.-.. instrumentation _F_unc;tjo.n,-:spec_i_fied in the.Table. Trip_ setpoints_.are s-pecified in._the setpo_int_caJ<:;ulations. The setpoints are selected -io e'nsure that the :settings do not -exceed . the All ow ab 1 Value:. between CHANNEL CALI BRAT IONS. dpe.ratipn.with a trip seiting. less than the_ .trip -setpo-int; _but*, within -;ts is.*. _. -owa,bl_e -Va Tue speci ffed .:accounts .-for _ -* uncertainties approprTate to _the -Function: -. These -uncertainties are described in the_ s.etpoint.methodology . . *, . .. :.:*" __ -* .-:,_ ... '*'** . -(continued) *--*" ; ,** *- . ..... -. .' ... . -.. --:*, ... . .. *; . . . . . 3 BASES APPLICABLE SAFETY ANALYSES, LCO, and . APPLICABILITY (continued) P13APS UN IT 3 RCIC System Instrumentation B 3.3.5.2 The individual Functions are required to be OPERABLE in MODE 1, and in MODES 2 and 3 with reactor steam dome pressure > 150 psig since this is when RCIC is required to be OPERABLE. (Refer to LCO 3.5.3 for Applicability Bases for the RCIC System.) The specific Applicable Safety Analyses, LCO, and Applicability discussions are .listed below on a Function by Function basis. 1. Reactor Vessel Water Level -Low Low {Level 2) Low reactor pressure vessel (RPV) water level indicates that normal feedwater flow is insufficient to maintain reactor vessel water l eve 1 and that the capability to coo 1 the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the RCIC System is initiated at Level 2 to assist in maintaining water level above the top of the active fuel. Reactor Vessel Water Level -Low Low (Level 2) signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in. the vessel. The Reactor Vessel Water Level -Low Low (Level 2) Allowable Value is set high enough such that for complete loss of feedwater flow, the RCIC System flow with high pressure coolant fojection assumed:to fail will be sufficient to avoid initiation of low pressure ECCS at Level l. Four channels of Reactor Vessel Water Level -Low Low (Level 2) Function are ava1lable and are required to be OPERABLE when RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC initiation. Refer to LCD 3.5.3 for RCIC Applicability Bases. (continued) B.3.3-133 Revision No ... 3

i. *,'* BASES

• APPLICABLE SAFETY ANALYSES; LCO, and . APPLICABILITY (continued} . :.**, RCIC. System Instrumentation . B 3.3.5.2 . 2*. Reactor Vessel Water Level -High (Level Bl High RPV water 1evel indicates that*sufficient cooling water inventory exists in the reactor vessel such that there is no . danger to the fuel. Therefore, the Level 8 is used to close the RCIC steam supply valve to prevent overflow
• into the main steam lines (MS Ls}. Reactor Vessel Water Level -High (Level 8} signals for RCIC are initiated from four level transmitters, which sense the difference between the.pressure due to a constant column of water {reference leg} and the pressure due to the actual water level {variable leg} in the vessel.* These four level transmitters are connected to two pressure compensation instruments {channels}.
• The Reactor Vessel Water Level -High {Level 8} All owabl_e Value is high enough to preclude isolating the injection valVe of the RCIC during normal operation, yet low enough to trip the RCIC System prior to. water overflowing into the: MSLs. . . . . Two channels of Reactor Vessel Water Level -High (Level 8) Function are available and are required to be OPERABLE when *
• RCIC is required to be OPERABLE to ensure that no single. * *instrument failure can preclude RCIC initiation. Refer to LCO 3.5.3 fe>r: RCICApplic.ability Bases.. . . 3. Condensate Storage. Tank. Level;_ Low * .tow level in" the.tsi fndicatesthe unav.ailability" of an ..
• supply of makeup* water from this normal source>. ***Normally, the *suction valve: l?etween .the RCIC pump and*the **. . CST *is open and, upon receiving a initiation signal,* ' water .for RCIC .injection would be taken from the CSJ. * . if the.water.lev'el in the CST falls below a . . . preselectecl lev.el, ,first the suppression*** pool automatically open,. and then the CST suction valve * * . .
• automatically closes. This ensures that. an adequate supply. of makeup water is*available to the RCIC pump. To prevent losing suction t_Q the pump, the suction.valves are** ... * .... . interlocked so.that the suppression *pool suction valves.must . ** . *be open before the CST . suet ion valve automatically . * ... (continued) -:**. . PB!\PS *UNIT* 3 B *3.3-'i34 . Revision: No. 3 * *. .,_
  • -.** BASES APPLICABLE SAFETY ANALYSES, LCO, and . APPLICABILITY ACTIONS .1* . : ... ; :. *.' PBAPS .* RCIC System Instrumentation B 3.3.5.2 3. Condensate Storage Tank Level ,;_Low (continued) Two level switches are used to detect low water level in the CST. The Condensate Storage Tank Level Function Allowable Value is set high enough to ensure adequate pump suction head while water is taken from the CST. Two channels of the CST Level -Low Function are available and are required to. be OPERABLE when RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC swap to suppression pool source. Refer to LCO 3.5.3 for RCIC Applicability Bases. A Note has been provided to modify the ACTIONS related to .RCIC System instrumentation channels. Section I.3, Completion Times, that once a Condition has been entered, subsequent divisions, subsystems; components, or vatiables expressed in the Condition to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that* Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial *entry into the Condition. However, the Required Actions for inoperable RCIC System instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable RCIC System instrumentatinn channel.
• A. I Required Action A.I directs entry into the appropriate Condition referenced in Table The applicable *Condition referehced in the Table is Function dependent. Each time a channel is distovered to be .Condition A is entered for that channel and provides for . transfet tci the appropriate subsequent Condition. * (continued) B 3.3-I35 . Revision No. 3 . I . I I '

i I .. , ; -. , ... *. :* ., . ---.* . , *'  !.,, ..... *-.* -* ;, -.-'. .BASES RCIC System Instrumentation B ACTIONS (continued) B.l and B.2 is intended to ensure that appropriate* actions' are taken if multiple, inoperable, untripped within the same Function.result iri a complete loss of automatic initiation capability for the RCIC System. In this automatic initiation capability is lost if two Function I channels in the same trip system are inoperable and untripped. In this.situation {loss of automatic initiation capability}, the 24 *hour allowance of '*. \. -* ... *** Action Bp2 is not appropriate, and the RCIC System must be declared* inoperable within*! hour after discovery of loss of RCIC capability. The Time is: intended to allow the operator time to evalua.te and repair .any discovered inoperabilities .. This , Completion' Time also allows for an exception to the normal tjnie zero11 for.beginning the allowed outage time 11clock.11 For Required Attion the Time onli begins . upon that the RCIC* System cannot be automatically iriHiated* due to twp .cir m()re inoperable, untripped Reactor Water Level-Low .Low (Level 2) c,hannel s such that: the .. tr)p system loses initiaticil'r-capability. The I hour .** *. Time from discovery of Joss *of initiation**. .. capabi-litYis acceptable because it infnimizes .risk while .. a)l for re$torati.on: or tripping* of channe 1 s. *** ** .. * .. ,*. . . . .... ": ..* , ... '**.:*:. . ' . ** .*

• the reerund'ancy. o/ sensors .*avai 1 able to provide. . i n'it i afi'.on *5 i g'na ls and' the fact that RC IC System is not . *. assumed:*'in' any acc,ident or transiiant analysi$,' an allowable out of sedfre time of *24: hours.bas been; shown to be * .atceptijbl e .. l) restoration, of .any, i,noperable .'. * , .. channel status.. If the inoperable c;:hannel ** ... * ** *. * ** caririot: be" restored;to OPIRABLE .. status. within<the* allowable: out of ice .ti me:*'the ,:,channel.* must : be pl ac¢d. 1 n . the'. * .. * .* . . . . ,. > : it16n> p¢r Ac ti ori 'B ,, p;lacing , : . * .* * .. *.* ... * .... inoperable chann,el i,n.trip,.would conservativ'ely compensate . '*<for the i n9perallil i ty restore* capability to accommodate a < ,,* single t() ,coritin.ue. *' . ... ,. .. . ' . . **Al ternate,ly, >if it is **not ,des,i red to .pl ace *the channel in* . .*trip in the inoperable* . ... *
• i;:hanne:l .. fTJ would res.ult Jn ari initiati.on), Condition I * .arid its Action , . -** _;*_. .. -.... -: '. ;: __ :,_,_ *-: .;-, :;*. . . *-." . .. .. -.. : *, : . . : , . . ..... **.""*::* . * .. *.* * ... ' * .... **. . . . . . .' /: **.
• Revi siori.No .' 3 * *** 'l,*o** .... B *.3 .3-136**,-: ...... '*:. .*; .. \ .. * ... I BASES RCIC System Instrumentation B 3.3.5.2 ACTIONS C.l (continued) . -*:; .. -*"'-.. . PBAPS UN IT 3 A risk based analysis was performed and. determined that an allowable out of service time of 24 hours (Ref. 1) is acceptable to permit restoration of any inoperable channel to OPERABLE status (Required Action C.l). A Required Action {similar to Required Action B.l) limiting the allowable out -0f service time, if a loss of automatic RCIC initiation capability exists, is not required. This Condition applies to the. Reactor Vessel Water Level -High {Level 8) Function whose logic is arranged such that any inoperable channel will result in* a loss of automatic: RCIC initiation capability (closure of RCIC steam valve). As stated above, this loss of automatic RCIC initiation capability analyzed and determined to be acceptable. The Required Action not allow placing a channel in trip since this action would not necessarily result in a safe state for the chahnel in all events. D.li D.2.1, and D.2.2 .' .. Required Action D.l is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels the Same. Function result=in automatic component initiation-iapability being lost for the
• For Required Action D.l, the RCIC System js the only associated In this case, automatic initiation capability is lost if two Function 3 thannels are inoperable and untripped. In this situation (loss of automatic suction 24 hour allowance -0f Required Actions D.2.1 and D.2.2. is ,anly-appropriate after Action D.l has been performed. Act.ion D. l tequi res that the RCIC System be decla'red inoperable within 1 hour from* discovery of loss of . RCIC initia,tion. *capability. As noted, Required Action D.l *; s *only applicable if th.e
• RCIC pump* suction* is not al i.gned to pool siritei if the Function is al ready:perform,ed .. *** .. . . (continued).** . . . -, .. '
• 1f 3 .3-'137 . Revfsion-No. 3 BASES . ACTIONS **. PBAPS .UNIT* 3 -* . .'*. . .. -.,: / ..
• RCIC System. Instrumentation . B 3.3.5.2 .D.l. D.2.1. (continued) The Completion Time* is intended to allow the time. to evaluate and repair any di scove.red i noperabil it i es.*. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action D.l, the Completion Time only begtns upon discovery that the RCIC System cannot .be automatically aligned to the suppressibn pool.due to two inoperable; . channels in the same *The.I hour Completion Time from discovery of loss of. initiation . capability is acceptable because it minimizes risk while time foi restoration or tripping of channels. . . . .** . . .'. . . . -. . -Because the RCIC System is not assumed in any accident or transient analysis, an allowable out of service time of
• 24 hours has been shown to b.e acceptable (Ref. 1) to permit restoration of any inoperable channel to.OPERABLE status. *If the inoperable channel cannot be re.stored to OPERABLE
• statos within the allowable out of service time, the channel must be placed in the tripped condition per Required Action which the intended functibn of the channel. 'Alternatively, Required Action D.2.2 allows the -. manual*alignment of the RCIC .suction.to whiCh al so the intended. function. *If *Required. J\ction D.2.l or D.2.2 is performed, measures should be taken to ensure that the RCIC System piping remains filled with water .. If it is not desired to perform Required Actions D.2.1 and as in the case where shifting the source could drain down the RCIC __ .* *pip.ing), *Condition [must:be entered. and its Required Action * *
• With.any Required Action and associated Completion Time not met; the RCIC System may be.incapable of performing the intended function, and*the RCIC System must be declared inoperable immediately. (continued) . 13 3 . Revision No.*. 3 -_: . .-.. --. '*:-*:* ..

BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UN IT 3. RCIC System Instrumentation B 3.3.5.2 As noted in the beginning of the SRs, the SRs for each RCIC System Function are found in the SRs column of Table 3.3.5.2-1. The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Function 2 and (b) up to 6 hours for Functions 1 and 3, provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions. taken. This Note is based on the reliability analysis (Ref. 1) assumption of the time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary. SR 3.3.5.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has riot occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a parameter on other similar It based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between co0ld be an fndication. 6f instrument drift in one of the channels or something more serious. *A CHANNEL CHECK will detect gross channel failure; thus, it .. is key to verifying the to operate properly between each CHANNEL CALIBRATION.. . Agreement are determined by staff based on a of the instrument Oncertainties, including indicaticin and readability. If a channel is o0tside the criteria, it may be an indication that the i'nstrument has drifted 6utsi de its limit. continued B 3.3-139 Revision.No. 87 BASES SURVEILLANCE REQUIREMENTS PBAPS.UNIT 3 RCIC System Instrumentation B 3.3.5.2 SR 3.3.5.2.l (continued) The Surveillance Frequency is controlled under the' Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCD. SR 3.3.5.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.5.2.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensof. This test verifies the channel responds to the measured parameter within necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.5.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific *channel. The system functional testing performed in LCO 3.5.3 overlaps this Surveillance to provide complete testing of the safety function. (continued) B 3.3-140 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UN IT 3 RCIC System Instrumentation B 3.3.5.2 SR 3.3.5.2.4 (continued) Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. GENE-770-06-2, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991. ' -B J.3-141 Revision No. 87 Primary Containment Isolation Instrumentation B 3.3.6.1 B 3.3 INSTRUMENTATION B 3.3.6.1 Primary Containment Isolation Instrumentation BASES BACKGROUND PBAPS UNIT 3 The primary containment isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs). The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents CDBAs). Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will 'be. consistent with the assumptions used in the analyses for a OBA. The isolation instrumentation includes the sensbrs, relays, and switches that are necessary to cause initiation of primary contaihment and reactor coolant boundary CRCPB) isolation. Most channels include eleetronic (e.g., trip units) that compares measured input signals with pre-established setpointi. When the setpoint i s ex c e e de d , t he c h a n n e l o ut p u t rel a y a ct u a t e s , w h i c h t h e n outputs a primary.contai*nment isolation signal to the isolation logic. diversity is provided by monitorihg a -wide range of independent parameters. The input,parameters to the isolation logics are (a) reactor vessel water level, ( b)

• reci'ctor pressure, ( c) main steam line CMSL) flow measurement, (d) (deleted); (e) main steam I . line pressure, (f) drywell pressure, (g) high pressure
• cool ant:. -i nj e ct i on ( HP C I ) and reactor core i sol at i on cool i n g iteam line flow, Ch) HPCI and RClC steam line
• pressure,* Ci) wciter* cleanup (RWCU)'flow, (j) Standby Liqu-id Control (SLC) System initiation, *ck) area ambient Cl) 0eactor building ventilation refueling floor vehtiJ(ltion exhaust radiation, and (rn) main stack '*
• Redundant sensor input signals from each provided fot itiitiation of jSolation." . has to the trip logic of the isolation functi-ons listed* below. ' .
• conti riued B 3. 3-J-42 . Rev i s i o t:i. N ci . 119 BASES BACKGROUND (continued) *. PBAPS UNIT *.3 Primary Containment Isolation Instrumentation B 3.3.6.1 1. Steam Line Isolation Most MSL Isolation Functions receive inputs from four . channels. The outputs from these are combined in a one-out-of-two taken twice logic to initiate isolation of the Group I isolation valves (MSIVs and MSL drains, MSL sample lines, and recirculation loop sample line valves). To initiate a Groijp I isolation, both trip systems must be tripped.
• The. exceptions to this arrangement are the Main Steam Line. Flow-High Function and Main Steam Tunnel Temperature-High Functions. The Main Steam Line Fl ow -High Function uses
• 16 flow channels, four for each steam line.* One channel from each steam line inputs to one of the four trip strings. Two trip strings make up each trip system and both trip systems must trip to cause an MSL isolatiori. Each trip string has four inputs (one per MSL), any one of which will trip the trip string. The trip systems are arranged in a one-out-of-two taken twice logic.
• This is effectively a one-out-of-eight taken twtce logic arrangement to initiate a Group I isolation. The .Main Steam Tunnel Temperature-High Function receives input from 16 channels. The logic is arranged similar to the Main Steam Line Flow-High Function except that high temperature on any channel is not related to a specific 2. Containment Isolation Most Primary Containment Isolation Functions receive inputs four* channels. The outputs from these channels are arranged in a one-out-of-two taken twice logic .. Isolation of inboard and outboard primary containment isolation valves occurs when both trip*systems are in trip. The exception to this arrangement is Main Stack Monitor Radiation-High Tuis Function has two channels, outputs are arranged in two trip systems which use a one-out-of-one logic. Each trip system isolates one valve per penetration. The Main Stack Monitor Radiation-High Function will isolate vent and purge valves greater ihan two inch.es in diameter during containment purging (Ref. 2). *
• The valves isolated by each of the Primary Containment Isolation Functions are listed in Reference 1. * ';_' (continued) B Revision 3 *

\ .* BASES BACKGROUND (continued) PBAPS .*UNIT* 3. Primary Containment Isolation Instrumentation B3.3 .. 6.l 3., 4. High Pressure Coolant Injection System Isolation and Reactor Core Isolation Cooling System Isolation Th.e Steam Line Flow-High Functions that isolate HPCI and RCIC receive input from two channels, with each channel comprising one trip system using a one-out-of-one Each of the two trip systems in each isolation group (HPCI and RCIC) is connected to the two valves on each associated penetration. Each HPCI and RCIC Steam Line Flow-High channel has a time delay relay to prevent isolation due.to flow transients during startup.

• The HPCI and RCIC Isolation Functions for Drywell Pressure -High and Steam Supply Line P*ressure -Low receive* inputs from four channels. The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of the associated valves. HPCI and RCIC Compartment and Steam Line Area Temperature-High Functions receive input from 16 channels. The logic is similar to the Main Steam Tunnel Temperature-High Function. The HPCI and RCIC Steam Line Flow-High Functions, Steam Supply Line Pressure-Low Functions, and Compartment. and Steam Line Area Temperature-High Functions isolate the
• associated steam supply arid turbine exhaust valves and pump suction valves. The HPCI and RCIC Drywell Pressure.-High Functions isolate the HPGI and RCIC test return line valves. The HPCI and RCIC Drywell Pressure-High Functions, in conjunction. with the Steam Supply Li he Pressure -Low
• Functions, isolate the HPCI and RCIC turbine exhaust vacuum relief valves. 5. *Reactor Water Cleanup System Isolation *The Reactor Vessel Water Level --Low (Level 3) I sol at ion ... Function receives input from four reactor v.essel water *level
• channels. The outputs from the reactor vessel water level channels are connected into a one-out-:-of-two tak.en twice logic which both the inboard and isolation valves .. The RWCU Fl ow-High Function receives input from .two channels, with each in one trip system a. * .one-out-of-orie logic,. with one channel tripping the .inboard .* one thannel tripping the outboard valves. The SLC (continued} B 3 .3-144 Revision No; 3 I BASES BACKGROUND PBAPS UNIT 3 Primary C-0ntainment Isolation Instrumentation B 3.3.6.1 5. Reactor Water Cleanup System Isolation (continued) System Isolation Function receives input from two channels with each channel *in one trip system using a one-out-of-one logic. When either SLC pump is started remotely, one channel trips the inboard is-0lation valve and one channel isolates the outboard isolation valves. The RWCU Isolation Function isolates the inboard and outboard RWCU pump suction penetration and the outboard valve at the RWCU connection to reactor feedwater. 6. Shutdown Cooling System Isolation The Reactor Vessel Water Level-Low (Level 3) Function receives input from four reactor vessel water level channels. The outputs from the channels are connected to a one-out-of-two taken twice logic, which isolates both valves on the RHR shutdown cooling pump suction penetration. The Reactor Pressure-High Function receives input from two . channels, with each channel in one trip system a one-out-of-one logic. Each trip system is connected to both valves on the*RHR shutdown cooling pump suction penetration. 7. Feedwater Recirculation Isolation The Reactor Pressure-High Function receives inputs from four channels. The outputs from the four channels are connected into a -0ne-out-of-two taken twice logic which isolates the feedwater recirculation valves. _J_r ave e Sys t t i __ QJJ. The Reactor Vessel Water Level-Low, Level 3 Isolation Function receives input from two reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected into one two-out-of-two logic trip system. The Drywell Pressure-High Isolation function receives input from two drywell pressure channels. The outputs from the drywell pressure channels are connected into one two-out-of-two logic trip system. When either Isolation Function actuates, the TIP drive mechanisms will withdraw the TIPs,.if inserted, and close the TIP system isolation valves when the TIPs are fully withdrawn. The redundant TIP system isolation valves are manual shear valves. TIP System Isolation Functions isolate the Group II(D) TIP valves (isolation ball valves). (continued) B 3.3.-145 *Revision No. 58
• *-! *. BASES APP LI C-AB LE SAFETY ANALYSES, LCO, and APPLICABILITY Primary Containment Isolation Instrumentation B 3.3.6.1 The isolation signals generated by the primary containment isolatjon instrumentation are implicitly assumed in the safety analyses of References 1 and 3 to initiate closure of valves to limit offsite doses. Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves CPCIVs)," Applicable Safety Analyses Bases for more detail of the safety Primary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion. The OPERABILITY of the primary containment instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.6.1-1. Each Function must have a required number of OPERABLE thannels; with their setpoints within the specified Allowable Values, where appropriate .. A channel is inoperable if its actual trip setting is not within its required .Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodolqgy assumptions. Values, where applicable, are specified for each Primary. Containment Isola.tion Function specified in the Table. Trip setpoints are specified ih the setpoint calculations. The*trip setpoints are selected to ensure that the setpoints do. not exceed the Allowable Value between CHANNEL Operation with a trip setting less conservative than trip setpoint, but within its .**
• Value, is acceptable .. Trip *setpoints are those predeterrrii ned values of output at which an action should. take place. The setpciints are c6mpared to the actual . reactor vessel level), and *when the measured output value of the proce*ss parameter exceeds the setpoiht, the associated *device Je.g., trip unit) changes state. The analytic or design limits are derived from the limiting values of the.process parameters the safety analysis or other appropriate documents. Tne Allowable Values are derived from the analytic.or design correded for calibration,* process, and* instrument errors. The trip setp.oi nts are .. determined fro.rri analytical or design .limits, corrected for .*calibration, _process:, and instrument errors, as well as .* instrument drifL .. In selected cases, the Allowable Values. and tri:p se:tp6ihts ar.e deter.mined by engineering judgement or historically accepted Pt<fcti.ce relative. to the intended. function .of tne :chan*nel. The trip setpoi nts determined in this manner provide.adequate protection by assuring *
• i nstrume*rit and. process uncertainties expected for the .
• en vi ronmeDts during 'the operating* ti me of the *a*ssociated. channels* are accounted for. * *
• n Emergency cbre Cooling S,Ystenis CECCS) and RCIC-. * * . valves (e.'*g., mihirnum*flow) also serve the.dual function.of auto.rilati c 'PC I Vs.
• The signals that isolate these valves are also* 'with the auto1TJati c i niti atfon, of the ECCS. (continued) *,_" PBAPS UN IT *3 . B 3. 3-146 Revision No. 58 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS. UNIT 3
• Primary Containment Isolation Instrumentation B 3.3.6.1 and RCIC. The instrumentation requiremen.ts and ACTIONS associated with these signals are addressed in LCO 3.3.5.1, "Emergency Core Cooling Systems (ECCS) Instrumentation," and LCO 3.3.5.2, "Reactor Core Isolation Cooling (RCIC) System Instrumentation," and are not included in this LCO. In general, the individual Functions are required to be OPERABLE in MODES 1, 2, and 3 consistent with the Applicability for LCD 3.6.1.1, "Primary Containment." Functions that have different Applicabilities are discussed below in the individual Functions discussion. The specffic Applicable Safety Analyses, LCO, and 'Applicability discussions-are listed below on a Function by Function basis .. Main Steam Line Isolation 1.a.* *Reactor Vessel Water Level-Low Low Low (Level 1) , . Low reactor pressure vessel (RPV) water leveJ indicates that the to cool _the fuel may be threatened. Should RPV water. 1. evel decrease too far,* foel damage could result. Therefbre,* isolation of the MSIVs and other interfaces with ihe reactor vessel to prevent dose limits from being exceeded. The Reactor Vessel .Water Level -Low Low Low (Level 1) Functi.on is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals. The.Reactor Vessel Low Low (Level 1) Function associated with isolation is assumed in the of the line-break (Ref. 1). The isolation of the MSLs on Level .1 supports actions to ensure that offsite dose lfmits are not exceeded for a OBA. Reactor water are initiated from four level the difference between the prei:;sure,-due :to a constarit 'column of water (reference leg) and pressure due. t'o the .actual water ievel (variable leg). iri,-ihe vessel. **.Four channels of Reactor *vessel Water Level-Lqw Low Lo¥J. (Level* 1) Functi cin are available and are required to be OPERABLE to ensure that no single fostrument
• failure *can preclude the isolation function. (continued)' ' . B 3.3-147 Revision .. No. 3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UN IT 3 Primary Containment Isolation B 3.3.6.l l.a. Reactor Vessel Water Level-Low Low Low (Level 1) (continued) The Reactor Vessel Water Level -Low Low Low (Level 1) Allowable Value is chosen to be the same the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite doses from exceeding 10 CFR 50.67 limits. This Function isolates MSIVs, MSL drains, MSL sample lines and recirculation loop sample line valves. l.b. Ma{n Steam Line Pressure-Low Low MSL pressure indicates that there may be a problem with the turbine pressure regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than l00°F/hr if the pressure loss is allowed to continue. The Main Steam Line Pressure-Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 3). For this event, the closure of the MSIVs *ensures that the RPV temperature limit (100°F/hr) is not reached. In addition, this Function supports actions to ensure that Safety Limit is not exceeded. (This *Function doses the MSIVs during the depressurization transient in order to maintain reactor steam dome pressure > 700 psia. The MSIV closure results in a scram, thus reducing power.to< 23% RTP.) The MSL iow pressure signals are initiated from four that are to the MSL header. The
• transmitters are arranged such that, even though physically separated from each other, each transmitter is able to detect low MSL pressure. Four channels of Main Steam Line Pressure-Low Function-are available and are required to be OPERABLE to ensure that no single instrument failure can precl.ude the isolation function. The Allowable Value was selected to be high enough to prevent excessive RPV depressurization. The Main Steam Line Pressure-Low Function is only required to be OPERABLE in MODE 1 since this is when the assumed transient can occur (Ref. 1). This Fuhction MSIVs, MSL drains, MSL sample lines rectrculation loop sample line valves. continued 8 Revision No. 130 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) PBAPS. UNIT 3 Primary Containment Isolation Instrumentation B 3.3.6.l l.c. Main Steam Line Flow-High Main Steam Line Flow-High is provided to detect a break of. the MSL and to initiate closure of the MSIVs. If the were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. If the RPV water level decreases too far, fuel damage could occur.* Therefore, the isolation is initiated on high flow to prevent or minimize core damage. The Main Steam Line Flow-High Function is directly assumed in the analysis of the main steam line break (MSLB) (Ref. 3). The isolatfon action, along with the scram function of the Reactor Protection System (RPS), ensures that the fuel peak claddin.g temperature remains below the limits of 10 CFR 50.46 .and offsite doses do not exceed the 10 CFR 50.67 The MSL flow signals are initiated from 16 transmitters that are connected to the four MSLs .. The transmitters are such that, even though physically separated from other, all. four connected to one MSL would be able to detect the high flow. Four channels of Main Steam Line Flow-High Function for each MSL (two channels per trip* system) are available and are required to be OPERABLE so that no single instrument failure will preclude detecting a break in any individual MSL. The Allowable Value is ch,osen to ensure that offsite. dose 1imits are not due to the break. This Function isolates MSIVs, MSL drains, MSL sample lines. and recirculation Joop sample line valves. l.d. Deleted continued . v,'* B 3.3-149 *Revision No. 119 ..
• BASES APPLICABLE SAFETY ANALYSES, LCO, and *APPLICABILITY (continued) PBAPS -UNIT 3 Primary Containment Isolation Instrumentation B 3.3.6.1 1.e. Main Steam Tunnel Temperature-High The Main Steam Tunnel Temperature Function is provided to detect a break in a main steam line and provides diversity to the high flow instrumentation. Main Steam Tunnel Temperature signals are initiated from resistance temperature detectors (RTDsl located along the main steam line between the drywell wall and the turbine. Sixteen channels of Main Steam Tunnel Temperature-High Function are available are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Allowable Value is chosen to detect a leak equivalent to between 1% and 10% rated steam flow. This Function isolates MSIVs, MSL drains, MSL sample lines and recirculation loop line valves. This Function in Unit 3 combines Unit 2 Functions l.e. and 1. f. Primary Containment Isolat1on 2. a. Reactor Vessel Water Level-Low (Level 3 l Low RPV water level indicates thaf the capability to cool the fuel may be threatened. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products. The isolation of the primary containment on Level 3 supports actions to ensure that offsite dose limits of 10 CFR 50.67 are not exceeded. continued B 3.3-150 Revision No. 119 BASES APPLICABLE . SAFETY ANALYSES, LCD, and APPLICABILITY .*' .. : '.': PBAPS UNIT 3 Primary Containment Isolation Instrumentation B 3.3.6.1 2.a. Reactor Vessel Water Level-Low (Level 3) (continued) The Reactor Vessel Water Level -Low (Level 3) Function associated with isoiation is implicitly assumed in the UFSAR analysis as these leakage paths are assumed to be isolated post LOCA. Reactor Vessel Water Level-Low (Level 3) signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low (Level 3) Function are available and are required to be OPERABLE to ensure that no single instrumeht failure can preclude the isolation function. The Reactor Vessel Water Level-Low (Level 3) Allowable chosen to be the same as the RPS Level 3 scram Value 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown. This Function the Group IICA) valves listed in 1 with the of RWCU isolation valves and RHR cooling pump suction which are in* Functions 5.c and p.b, respectively. 2.b. * . . High drywelf tan indicate a break in the RCPB inside fhe* primary containment. *The isolation of some of the primary contain[llent isolation valves on high drywell . pressure supports ,acti.ons to ensure tbat offsite dose. limits of 10 CFR 50'.67 are not exceeded. *The Drywell Pressure-* I High bsso61aied with i_solation the primary containment_, is impl i.citly as-sumed in the UFSAR accident ilnalysi*s as thes*e le.akage:paths are assumed to be isolated post LUCA. * . . . *' . . --._.. -. . _ .. Hf°gh tlrywell pre.ssure* signa*ls are initiated frbTll pressure* transmifters that sense the pressure in* the drywel 1. Four chanriels are.available and are requi re*d to. be OPERABLE 1to ensur.e that rio single instrument fai 1 ufe Can* preclude* the. i*s o l ati on function: * * * .. -. .. . <cont i riuedJ * , .... -B 3;3-151 .Rev.ision No. 76.

BASES APPLICABLE

• SAFETY ANALYSES, LCO, and APP LI CABI L ITV PBAPS UN IT 3 Primary Containment Isolation* Instrumentation B 3.3.6.1 2.b. Drywell Pressure--High (continued} The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.1}, since this may be indicative of a LOCA inside primary containment. This Function isolates the Group II(B) valves listed in Reference 1 . 2.c. Main Stack Monitor Radiation-High Main stack monitor radiation is an indication that the release .of radioactive material may exceed established limits. Therefore, when Main Stack Monitor.Radiation-High is detected when there is flow through the Standby Gas
• Treatment System, an isolation of primary containment purge and exhaust penetrations is initiated to limit the release of fission products. However, this Function is not assumed in any a.ccident or transient analysis in the UFSAR because other leakage paths (e.g., MSIVs} are more limiting. The drywell radiation signals are initiated from radiation detectors .that isokinetically sample_ the main stack utilizing sample Two thannels of Main Stack Radiation-High Function-are available and are required to be OPERABLE to ensure that no single instrument failure* can preclude the isolation function. The.Allowable Value is set below the maximum allowable* release 1 imit in .accordance with the Offsite Dose Calculation (ODCM). this F:ur1ctron isolates the containment vent and purge valves and other Group J.If(E) valves .listed in Reference 1. * * .* ReadorBuilding Ventilation. and Refueling Floor VentilatiOn Exhaust Radiation-High *. *
• High exhaust an of ptisiible"gtciss failure of the fuel cladding. . The release may have. originated from the primary containment due .to a break in the RCPB.
• When Reactor BuHding or Refueling Floor Ventilation Exhaust Radiation-High is .detected, the, affected verit*ilation pathway_ and primary--' .. *-*, . . ' * (continued) . 8 .3.3-152 -Revision No .. 22
• 1' .. -*" :. If.: . -.. *BASES APPLICABLE SAFETY ANALYSES, LCO, and *. . : .,* .* .. , *-* ,.*. -.*.***. ' '
• I *** .* **. :* .* :* "'-.. . ' *PBAPS UNIT 3 ' -. ' ... **:-, ...... * ... : : Primary 'Containment Isolation Jnstn1mentation
• B 3.3.6.1 2.d .* Reactor Building VentilationandRe;ueling Floor*. . Ventilation Exhaust Radiation ..;High* (contiQlled)
• containment purge supply and exhaust valves* are to limit the release of fission products. Additionally, Ventilation Exhaust Radiation ... High Function initiates Standby* Gas Treatment System. * *
• The Ventilation Exhaust Radiation-High s*ignals are initiated from radiation detectors that are located on the ventilation exhaust piping cQming from. the reactor building and the refue 1 irlg floor zones, respect i vel .Y.
• The signal from eath detector is' input to an individual monitor whose
• trip outputs are assigned to an isolation channel: ** Four.* channels of Reactor Building Ventllation Function and four channels of Refueling.Floor Ventilation Exhaust ... High Function are available and arE! required to be .. OPERABLE to ensure that no single instrument. failure can preCl ude. the i so lat ion *function.* * * -. . ' . ' . . . The *Al 1 owahi e Values are* chosen promptly detect gross .. failure of the fuel cladding a refueling accident. These Functions isolate the lll(C) aridIIl(D) . listed .in . Reference l. High Pressure Coolant lnjedi:on and *Reactor *Core* Isolation
• Coo li nq Systems *I sol ati on *. . -.. HPCI and RCIC Steam Line Flow-'-Hiqh* . and Time.Delay Relays Line are pr_ovided >io detecf*a .* *., break of the RCIC'or.HPCI steam lines'and .initiate closure.** . of the steam 1 i ne ; so 1 ati on valves of the appropriate *system.
• If the* steam is. a.l lowed to continue flowing out of tbe break; the will depressurize arid the core can uncover. Therefore, the isolations are initiated on high flow to.prevent or mtnimize core damage .. The isolation_* action,* along with the scram function of the RPS, ensures* that the fuel peak cladding temperature remains below the *.limits of 10 CFR
• Specific credit *fcir these' Functions:
• is *not assumed in any UFSAR accident analyses since the . I *. *{continued). *. ---::: : .* .*. .... : .,.. ; :: .* .. * **:*-. . ,' '* . -..... *. I
• .. . , .. .,.-_.; .: ., -; :,*._ -*. . . .* -*;, BASES . APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY . Prilllary Containment .Isolation Instrumentation. B 3.a .* 3.b., 4.a .* 4.b. HPCI and RCIC Steam Line Fl ow-High* .and Time Delay Relays (continued) bounding analysis is performed for large breaks such as . and MSL breaks .. these prevent the RCIC or HPCI steam line breaks from becoming bounding.
• The HPCl and RCIC Steam Line signalS are *'initiated from transmitters (two for MPCI and two for RCIC) .. that are connected to the system steam lines. A time delay*.* *is provided to prevent isolation due to high flow .* during startup with one Time Delay Relay channel associated with each Ste.am Line Flow-High channel. Two channels of .both HPCI and RCIC Steam Line Flow-High. Functions and the *associated Time Delay Relays are available and are required to be OPERABLE to ensure that no single instrument failure.* can preclude the isolation*funttion. *
• The Allowable Vaiues for Ste*am Flow-High Function and assoCiated Time Delay Relay .Function are_ .chosen to .be low -enough to ensure that the trip octurs to maintain the MSLB as the bounding event. These Functions isolate the associated HPCi and RCIC steam .. supply and turbine va 1ves and pump* suet ion * ** -. . . . . *. . . . . -.. 4.c.
• HPCl.and RCIC Steam Supply Line Pressure.-Low -.Low .MSL pressure* that the the .steam in . the HPC I or RC IC. turbine may be. too low to continue * *operation of the* associated system's turbine. These isolations prevent gases' and steain -from ¢scaping ... through the p*ump shaft seals' in.to :the *:reactor building but,'.. are primarily for equipment .protection and are *also assum.ed -_-for l Of!g term containment i sol at ion. *-However, they also -* provide a diverse signal :.*to indicate a possible system * * , _-. --"_break:._ These il'lstruments *are included in Technicai : . --. :*: *.*.* .. **-* * .*-.*Specifications (TS)_. becaus.e* of the* potenttal for risk: due to\ . -* pos.s i bl e fail lire *of the instruments prevenfi ng -HPC l and RClC ...... .. ,. .-. '. * .. * --;*_. ' .. . PBAPS' UNIT '3 -*-.. -(Ref.' 4). * .. ----. . . . The HPCI RCIC Steam Supply Line Pressure--Low signah> . are i nittated frdm transmitters (four for and_ four_ for -.RCH:) that are ccinnected* to the *system stearn . Four.: ".' . -,, ....... -. ; -. -. . . . -*-. . . . ... _.** .. *-.. . -, *. :: *.** ... -* .. ' *. _,-**
• a 3.3-Js4 * .... \ c cont ;hued> .. _ '. --.. -. Revi sfbn No /3 : .. *' .. *.-... .,. ' .*.,. .*:*

BASES . APPLICABLE SAFETYANALYSES, LCO, and . APPLICABILITY * ,* '. . : -. . ' Primary Containment Isolation Instrumentation B 3 .c., 4.c. HPCI and RCIC Steam Suppl v Line Pressure-Low (continued} . channels of both HPCI and RCIC Steam Supply Line

• Pressure-Low Functions are available and are required to be OPERABLE to ensure that no single instrument failurecan prec l ude the i sol at i. on function. The Allowable Values are selected to be high enough to
• prevent damage to the system's turbine. These Functions isolate the associated HPCI and RCIC steam supply and turbine valves and pump suction valves. 3.d:.4.d.* Drvwell Pressure-High (Vacuum Breakers) High drywell pressure can indicate a break in the RCPB. The HPCI and RCIC isolation of the turbine exhaust.vacuum breakers is provided to prevent communication with the drywell when high drywel l pressure exists. The HPCI and .RCIC turbine exhaust vacuum breaker isolation occurs . following a permissive from the associated Steam Supply Line. Pressure -Low Function which i nditates that the system is no longer required or capable of performing coolant injection. *. The isolati-On of the HPCI .and RCIC turbine exhaust vacuum breakers by Drywell Pressure...:.High is indirectly assumed in *the UFSAR accident analjsis because the turbine exhaust leakage path is not assumed to contribute to.offsite doses. High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Four channels for both HPCI and RCIC Drywel l Pres.sure -High (Vacuum Breakers) Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function . . The Allowable Value .was selected to be the same as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5.l}, since this.is indicative of aLOCA. inside primary containment. This the HPCI and RCIC vacuum *relief *v*alves and test return line valves. 1 (continued) 8. 3.3-155 .: *
• Revision No.* 3

. ! . *:. .. .'J,. .**--...... : * . * .. -*--.::* BASES APPLICABLE. SAFETY ANALYSES, LCO, APPLICABlLITY (continued_)* Primary Containment Isolation Instrumentation B 3.3.6.1 3.e., 4.e .. HPCI and RCIC* Compartment and Steam Line Area Temperature-High HPCI and RCIC Compartment and Steam Line Area temperatures are provided to a leak ftom the associated steam piping. The isolation occurs when a small leak

• has occurred and is di verse to the high flow instrumentation .. lf the sniall leak is allowed to continue without isolatibn,* offsite dose limits These Functions are not assumed in any UFSAR transient or accident analysis-, si nee bounding ana_l yses are performed for large breaks such as recircu1ation or MSL breaks. HPCI and RCIC and Steam Line Area signals are in1tiated _from resistance* temperature (RTDs) that are.appropriately located to protect 'the system that. is being monitored. The HPCI arid RCIC CQmpartnient and: Steam Lirie. Area Temperature-High*
• Fund:.ibns Lise 16 temperature channels. Sixteen channels* for' each* HPCI .and RCIC Compartment and Steam Line. Function are available are . re'qui red to be OPERABLE to ensure that no single i nstrumenf ....... *'; ' ** .*. fa.ilure can p'req_lude the :isolatiOn function .. ;, . . *-:-*,* . *. i *; '*, -" . Th'e'Alldwable Va),ues are setJa'A'.*EmoLigh:_to-detect a* leak. _ These Fun,stfons i .. associated HPCI and RCIC steam* :suppJy *and turb.irie exl1aust valVes and pump suct1on valves. .,. Reacto'r Cl JRWCU) System I so lat ion . -., : '*.-* -*:-*<.: ._ ... -.. **.' *' *. *,., ' .. .. ':. ; . . ' . -*. .. .-. .*..... The fl o:JJ .s:{gnal; -is *.Cl bfeak, i.n <t.he *
• _. ; *RWCU. System} Should :the _coolant contir1ue to How** ",* ,. ; .,; out of th'e :br.eak_, bf.fsite dose limits -maybe :e*xceeded; : , ' Thyrefofe,:Jsoiat56n initiated.when .. *,.** . *high RWCU __ ... , _This Function Js:not assumed in any UFSAR'J(ansient or _
• __ .. -.. _ .*. accidentClnaiysis*; *s,1nce. bo:undi_ng analyses areperfornied :for-*1 a._r:ge sfrch*'as
• MSLBs.:. * . . -* * .:.'*. ;' ' .. . :. -.. *.. .: ' --.. : -:., '* . . .. . . -.. --. .. * . (continued) -*' .. ';: ... --: ... '.*. . ' .. --. . : .: ' *." -.:: .. -,,., *.,.*. *. __ *.,'-:_-. . PBAPS UNIT 3 ..*,.,_ .. *.: Revision No. . -.. , .. *-... :: .:-*. .

BASES APPLICABLE SAFETY ANALYSES, LCD, and APP LI CAB I LI TY ,*:, _. PBAPS UNIT 3 Primary Containment Isolation Instrumentation B 3.3.6.1 5.a. RWCU Flow-High (continued) The high RWCU flow signals are initiated from transmitters that are connected to the pump suction line of the RWCU System. Two channels of RWCU Flow-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

• The RWCU Flow-High Allowable Value ensures that a break of the RWCU piping is detected. This Function isolates the inboard and outboard RWCU pump suction 'penetration and the outboard valve at the RWCU connection to reactor feedwater. 5,b. Standby Liquid Control CSLC) System Initiation The isolation of ttie RWCU System is required when the SLC System has been ihitiated to prevent dilution and removal of the boron solution by the RWCU System (Ref. 5). SLC System iriitiatibn are iriitiated from the SLC System start *
• There is Allowable Value associated with this Function are actuated .based solely on the position of the SLC.System initiation switch. Foi two of the System Function are available are required to be OPERABLE in MODES 1 and 2*, si*nce these are the only MODES reactor can be tritical. In addition, for accidents involving significant fission product releases, both chahnels are also to be in MOnEs 1, 2, -and 3. The SLC System is designed to maintain suppression pool pH at or above 7 following a LDCA to ensure that i.odine wi 11 be .. retaHied in sµppressicin pool water .. These MODES are co_nststentwith the Applicability for theSLC *System* CLC03:Ln. . . .. . .-* This .Funttton isolates the inboard and RWCU pump -suctiOn.penetration and the outboard valve at the RWCU connecti oh.* to reactor feedwater; . ' . .. . -' -. .-. -5.c.'; Reactor Vessel WaterLev_el...:.Low*(LeveT*3) . . . Low RPV water *t_hat the. capability to. cool th.e fuel may be threatened .. Should RPV .water 1 evel decrease. *too far, fUel *damage could result. Therefore, isolatibnof 'some interfaces with the* reactor vessel occurs to isolate . the potential sources of* a** b.rea k.
• The i so lat ion of the * . . -0n Level J to ensure that the fuel .
• C co.nti nued) . -. -*B.3 .. 3cl5'l .:Revi sicm No-. 76 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 3 .. :.. . Primary Containment Isolation Instrumentation B 3.3.6.1 5.c. Reactor Vessel Water Level-Low (Level 3) (continued) peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Vessel Water Level -Low (level 3) Function associated with RWCU isolation is not directly assumed in the UFSAR safety analyses because the RWCU System line break is bounded by breaks of larger systems (recirculation and MSL breaks are more limiting). Reactor Vessel Water Level""""' Low (Level .3) signals are inttiated from four level transmitters that sense the difference between the pressure due to*a constant column of* water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level -Low (Level 3) Function are available and are required to be OPERABLE to ensure that no single instrument failure preclude the isolation* function.
• The Reactor Vessel Water Level -Low (Level 3) Allowable Value chosen to be the same as the RPS Reactor Vessel Water Level-Low (Level 3) Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened. This Function isolates the inboard and outboard RWCU suction and the outboard at the RWCU ccinnection to reactor Shutdown Cooling Svstem Isolation 6.a. Reactor Pressure-High The Reactor Pressure-High Function is-provided to isolate . the sti0tdown cooling portion of the Residual Heat Removal ( RHR) System. This Function.is provided only for equipment protection to prevent an intersystem LOCA scenario, and credit for the Function is not assumed in. the accident or transient analysis ih the UFSAR. *The Reactor Pressure-High signals are initiated from two driven by trip units associated with pressure ttarismitters that sense RPV pressure at different taps ori the RPV. Two channels of Reactor Pressure-High Function are available and .are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The is only required to be. OPERABLE in continued B 3.3-1.58 Revision No, l.20 i I.*. .-!. . ,* .. . . -**' *.-*.: ' ..... , i -**. -. ' .__ .. , ,,.* ; . *-" BASES
• APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY . ' . . -**,* ,:.*. ,_---Primary Containment Isolatfon Instrumentation B 3.3.6.l 6.a. Reactor Pressure-High (continued). MODES l,*2, and 3, since these are the only MODES in which the reattor can be pressurized; thus,. equipment protection is needed. ,The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization. _ This Function isolates both RHR shutdown cooling pump suction*valves. *
• 6. b.
• Reactor Vessel Water. Level -Lciw (Level 3) . . . . ' -. . -. . . -. Low RPV level indicates that the to cool thE;! fuel may be threatened .. Should RPV water level decrease too far, fuel damage could result. *Therefore, isolation of ' some reactor vessel interfaces occurs to begin isolating the potential sources of a break. The Reactor Vessel Water * . Leve 1 -Low (Level 3) Function associated* with RHR Shutdown Coolfng Sy"stem isolation is not directly .assumed in safety . analyses because a break of the RHR Shutdown Cooling* System. is bounded by of the.recirculation andMSL The RHR _, Shutdown isolation on Level 3 actions to *ensure that the RPV water level does not drop *
• below the top of the active fuel "duririg a vessel draindown event caused by a. leak {e.g., pipe break or inadvertent. *valve opening) in the RHR Shutdown Cooling System. * *
• Reactor Vessel Water Level -Low {Level* 3} sign;ils are'**
• initiated from four level transmiiters that sense the* .** . d.i ffe'rence between the pressure due to 'a constant coi umn. cff .. * .. water {reference* 1 eg) .. and* the pressure due to' the. actual.: . water ::1 eve l {variable leg) in the l . Fc>ur chan_ne'l s . '{two channels per trip system) of the Rea'cto.r Vessel Water level .;:,. Low {Level 3)
• Functian .are ava.i l able and are . . to be, OPERABLE to ensure that no *single* instrument failure .... can preclude the-isolation.function. As rioted {footnote (a). to e :f. 3*. 6. t-1), only a*ne
• C:hanne l per trip system. '(with * ._ an. isolation signal available* to one shutdown_ .cooling pump** * .sucticm fsol atfon valve} .of the :Reactor .Vessel Water * . <:. > *Level {Level3) Function are required.to be OPERABLL'iil ,MODES 4 and 5, 'prpvided the RHR Shutdo.wn Cooling Sy.stem. -integrity is maintained. System 1ntegrity is_ mai11tained .. providedtbe piping iS int.act and no maintenance be.ing .-** .. perf9:rmed that has the potential for draining the reactor** . vessel through* the system.. . . . . . _ .... -** * .. . * * * ., . .. q. * * .. ,* .--. ' ... ".' . .
• PBAPS VNIT-: 3 * ..
• B 3.3.-:-159 I BASES APPLICABLE SAFETY ANALYSES, LCO, and . APPLICABILITY PBAPS UN IT 3
• Primary Containment Isolation Instrumentation B 3.3.6.1 6.b. Reactor Vessel Water Level-Low (Level 3) (continued) The Reactor Vessel Water Level-Low (Level 3) Allowable Value was chosen to be the same as .the RPS Reactor Vessel Water Level -low (Level 3) Allowable Value CLCO 3.3.1.1), since the capability to cool the fuel may be threatened. The Reactor Vessel Water Level-Low (Level 3) Function is only to be OPERABLE in MODES 3, 4, and 5 to prevent this potential flow path from lowering the reactor vessel level to the top of .the fuel. In MODES 1 and 2, another isolation (i.e., Reactor Pressure-High) and administrative controls ensure that this flow path remains isolated to prevent unexpected loss of inventory via this flow path. This function isolates both RHR shutdown cooling pump suction valves. Feedwater Recirculation Isolation 7.a. Reactor Pressure-High The Reactor Pressure-High Function is provided to isolate the feedwater recirculation line. This interlock is provided only for equipment protection to prevent an intersystem LOCA scenario, and credit for the interlock is not assumed in the accident or transient analysis in the U FSAR. * . **The Reactor Pressure-High signals are initiated from four transmitters that are connected to different taps on the RPV. Four channels of Reactor Pressure-High Function are available and are requifed to be OPERABLE to ensure that no instrument failure can preclude the isolation function. The Function is only required to .be OPERABLE in MODES 1, 2, and 3, since these are the only MODES in which *the reactor can be pressurized; thus, equipment protection is The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization. This Function isolates the feedwater recirculation valves. __ Jn!;:_g_r_g ___ P.r.Q[l_g ___ __ J_$_QJ__9_:U_Qn __ , ______ ___ ___ _ _. __ Low RPV water level indicates that the capability to cool the fuel may be threatened. The valves whose penetrations with the primary containment isolated to (continued) I B 3.3:.160 Revision No. 58 BASES APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY (continued) ' .. PBAPS UN IT 3 Primary Containment Isolation Instrumentation B 3.3.6.1 f:3.a. Reactfil _ (continued). limit the release of fission products. The isolation of the primary containment on Level 3 supports actions to ensure that -0ffsite dose limits of 10 CFR 100 are not exceeded. The Reactor Vessel Water Level-Low, Level 3 Function associated *with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isblated post LOCA. Reactor Vessel Water Level-Low, Level 3 signals are initiated from level transmitters that sense the difference between the. pressure due to a constant column of water (refere.nce leg) and the pressure due to the actual water l.evel (variable leg) in the vessel: Two channels of Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent isolation actuation. The isolation function is by the manual shear valve in each penetration. The Reactor Vessel. Water Level 3 Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO since isdlation of valves is not critical to orderlY plant This Function isolates the Group Il(O) TIP valves.* . . . 8.b. Drywen *Pressure-High .. High drywell pressure can indicate a break in the RCPB inside. . the primary containment. The isolation of some of the primary containment isolation Dn high drywell pressure supports_ actions to* ehsµre that off site dose limits of 10 CFR 100 are not The Drywell Pressure7High Function, associated with isolation of the primary containment, :js *implicitly assumed jn the* FSAR 'acti dent analysis as these leakage paths are assumed to be isolated .
• High*d,rywell pres-sure si*gnal-s a-re .from pressure transmitters that sense the* pressure in the drywe 11. Two ..
• charrnels.-.of Drywell Pressure-High per F_unGt-jon :are available* and'. are requ0ired to be. OPERABLE to:ensure that no: single. instrument fai l_ure can initiate an i nadverten_t actuation._ The isolation function is ensured by the manual shear valve in each penet'rati ori. *
• The alfowa*b l Value was selected to be the* same as the <cirywel f Pressure-.H{gh Allowable Value_ CLCO since.this may pe J9di ca ti of a LOCA i.nsi de primary .contai riment. ,, . '.This .Funttioh.is.olates the Gr.oup ll(D) TIP valves: . .. -. (continued) B 3.3-160a Revision No. ss***I Primary Containment Isolation Instrumentation B 3.3.6.1 BASES (continued) ACTIONS The ACTIONS are modified by two Notes. Note 1 allows penetration flow path(s) to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operat6r at the controls of the valve, who is in continuous commuriication with the control room. In this way, the penetration can be rapidly isolated when a need for primary containment isolation is inditated. Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that.once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, wi 11 not result in. separate entry into the Condition. Section specifies that Required Actions of the Condition continue to apply f6r each additional *failure, with Completion based on initial entry into the Condition. However, the Required Actions for inoperable primary isolati6n instrLmentation channels provide appropriate compensatory measures for separate inoperable As a Note has been provided that allows separate Condition entry .for each inoperable pr1mary isolaticin instrumentation channel .. . *-. _.'; PBAPS. UNTT 3 Because of the diversity sensors available to provide iso1atibn arid the redundancy of the is6lation design, an allowabie out of service time of 12 hours for Fu n ct i o n s 1 . d , 2 . a , a n d 2 . b' a n d 2 4 h o u r s fo r Fun c ti on s o th e r than* Functions 1,d; 2.a, and 2.b has been shown to be (Refs. 6 ahd n to permit restoration of any* inoperable channel to OPERABLE This out of service . time is only acceptable provided the associated Function is *still maintaining .is.olation ,capability (refer to Required
• Action B.l Bases)*> Lf the.inoper:abTe channe.l cannot be restciied to bPERABLE the oGt.bf* servi.ce tiine, the .!=hannelmu$t be placed*.in*thetripped .condition. per *Re qui red Ac ti on 1, Pl _cici ng .the inoperable cha.nriel would .conservatively compensate for the i noperabi li ty,
• re.stqre capability to accommodate a single . fai.lu.re, and allow operation to. cor:ttiiiue with no further*
• restrict1ons.* Alternately, if.it is not desired to place the.ch.annel in trip (e.g., as 1n the case.where placing the inoperable channel in.trfp*.wouldresult in an isolation), Condition.* C must be,.entered and its Requir:*ed* Atbon taken .. -,_.,:_'._*. (continued) ._.-.* ..
• Revi No .. 58 BASES ACTIONS (continued) UNIT 3 Primary Containment lsolatio.n. Instrumentation B 3.3.6.I Required Action B.l is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant isolation capability being lost for the associated penetration flow path(s). For those MSL, Primary Containment, HPCI, RCIC,.RWCU, SDC, and Feedwater Recirculation Isolation Functions, where actuation of both trip systems is needed to isolate a penetration, the .Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip (or the associated trip system in trip), such that both trip systems will a trip signal from the given Function on a valid signal. For those Primary Containment, HPCI, RCIC, RWCU, and SDC isolation functions, where actuation of one trip system is needed to isolate a penetration, the Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given function on a signal. This ensures that at least one of the PCIVs in the associated penetration flow path can receive an isolation signal from the given Function. For.all Functions except l.c, l.e, 2.c, 3.a, 3.e, 4.b, 4.e, 5.a, 5.b, and 6.af this would require both trip systems to have one channel OPERABLE or in trip .. For Function *Le, this would require both trip systems to have one channel, associated with each MSL; OPERABLE or in trip.* For Functions l.e, 3.e and 4.e, each Function consists of channels that monitor several locations within a_ given area (e.g., different locations within the main steam tunnel area). Therefore; this would require both trip systems to have one channel per location OPERABLE or in trip. For Functions 2.c, 3.a, 3.b, .4.a, 4.b, 5.a, and 6.a, this would require one trip system to have one channel.
• OPERABLE or in trip. The Completion Time is intended to allow the operator time to and repair any discovered inoperabilities. The I hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. (continued) _ Revision 3 --

BASES ACTIONS PBAPS UNIT 3. Primary Containment Isolation Instrumentation B 3.3.6.1 B.1 (continued) Entry into Condition B and Required Action B.1 may be necessary to avoid an MSL isolation transient resulting from a temporary loss of ventilation in the main steam line area. As allowed by LCD (and discussed in the Bases of LCD 3.0.2), the plant may intentionally enter this Condition to avoid an MSL isolation transient* following the loss of ventilation flow, and then raise the setpoints for the Main Steam Tunnel Temperature-High Function to 250°F causing all channels of Main Steam Tunnel Temperature-High Function to be inoperable. However, during the period that multiple Main Steam Tunnel Temperature-High function channels are inoperable due to this intentional action, an additional compensatory* measure is deemed necessary and shall be taken: an operator sha_l l observe control room i ndi cations of the duct temperature so the main steam line isolation valves may be promptly closed in the event of a rapid increase. in MSL tunnel temperature indicative of a steam line break . . c .1 Required Action C.1 directs entry into the Condition referenced ih Table The applicable Condition specified in Ja6le is Function and MODE . or other specified condition dependent and may change as the Required Action of a previous Condition is comple,ted. Each time an inoperable channel has not met any Required Action of tondition A or B and the associated Completion Time expired, Coridifion C will be entered. for that.chahneL and prov.ides for transfer to -the appropriate subsequent *

• D.1. *D.2.1. and D.2.2 If the channel is not restored to OPERABLE. status or pl aced .
• in trip within the allowed Completion Time, the plant rnust . be pl aced in a MODE or other specified ccinditi on in which the LCD .does not apply; This is done by placing the plant in at least MODE *3 within 12 hours and in MODE 4 within -* .36 .hours (Required Acti.ons D.2.1 and D.2.2) .. Alternately, the associated MSLs may b.e isolated (Required Action continued B 3.3-163 Revision No .. 46 * *. __ ,

BASES ACTIONS *,.,' . ' . . ' *. PBAPS UN IT .3 * .. Primary Containment isolation Instrumentation B 3.3.6.1 D.1. D.2.1. and D.2.2 *(continued) and, if allowed (i.e., plant safety analysis allows operation with an MSL isolated), operation with that MSL isolated may continue. Isolating the affected MSL accomplishes the safety function of the inoperable channel. The Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without cha 11 engi ng p 1 ant systems *. If* the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which

• the LCO does not apply. This is done by placing the plant in at least MODE 2 within 6 hours. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 2 from full power conditions* in an orderly manner and without challenging plant systems.
• F.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path{s) accomplishes the safety.function of the inoperable channels. Alternately, if it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating .the penetration flow path(s) could result in a reactor scram), Condition G must be entered and its Required Actions taken. The 1 hour Completion Time is acceptable because it minimizes risk while allowing sufficient time for plant operations personnel to isolate the affected penetration fl ow path ( s). (continued) . B 3 .3-164* Revision No. 3 BASES . ACTIONS (continued) G.1 and G.2 Primary Containment Isolation Instrumentation B 3.3.6.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, or the Required Action of Condition F is not met and the associated Completion Time has expired, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 w.ithin 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full . power conditions in an orderly manner and without plant systems. H.l and H.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated SLC subsystem(s) is declared inoperable or the RWCU System is isolated. Since this Function is required to ensure that the SLC System performs its intended function, sufficient remedial measures are provided by declaring the associated SLC subs.Ystenis inoperable or isolating the RWCU System. The*! hotir Completi6n is because it
• minimiies tisk allowing sufficient time for personnel to isolate the* RWcu* System. * * *
• I. I and 1.2 'If the channel is 'not restored. io OPERABLE status or pl aced * . in tr'ip.within the allowed Completion Time, the associated penetration flow path should be closed. However, if the , shutdown .. cool lng ft.met ion is needed-to provide core coo 1 i ng, : .* these Actfons a 11 OW the penetration fl ow path to remain unisolated provided action .is immediately initiated the.chanhel to OPERABLE status*or to isolate the RHR Shutcjown Cpol ing System *(i.e., provide alternate decay heat remov.al*capabilities so the.penetration flow path can. be iSplatE!d):. Acti6ns must continue until* the channel .is .. restored. to OPERABLE status or the RHR Shutdown Cooling . :System.ts* isolated. *. * ;, . * . . :. ; ' . *. . . . .
• Rev i s i on No . : 3 . *. .. I Primary Containment Isolation Instrumentation B 3.3.6.1 BASES (continued) SU RV EI LLANCE REQUIREMENTS PBAPS UN IT 3 As noted at the beginning of the SRs, the SRs for each Primary Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1. -The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 6 and 7) assumption of the average time required to perform channel surveillance. That analysis demonstrated the 6 hour testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary. SR 3.3.6.1.1 of the CHANNEL CHECK that a gross failure of instrumentation has. not occurred. A CHANNEL CHECK is a comparison of the. parameter indicated on one channel to a similar parameter on other channels. lt is based on. the assumption that* instrument channels moni tori hg the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive drift in one of the . channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifyl.ng the i nstrum'entati on continues to operate properly between each CHANNEL CALIBRATION. ' ' . . .. -are by the staff based on a combination of the cha'nriel instrument uncertainties, incl ud.ing. i ndi cat'i on and readabi.l ity. If a channel is criteria, it 'rnay be an indication that the instrument has drifted outside its limit. The Surv*ei l lance Frequency is controlled under the Surveillance frequency Control Program. The CHANNEL CHECK supplement?' less formal; but more frequent, checks' of ' channels .dlir_ing Mrmal operational use of the displays associ with the _channels :required by th.e LCO. continued B 'Revision No. 87 I. I BASES SURVEILLANCE (continued) PBAPS .UN IT 3 Primary Containment Isolation. Instrumentation B 3.3.6.1 SR 3.3.6.1.2 A CHANNEL FUNCTIONAL TEST is performed each required channel to that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.6.1.3. SR 3.3.6.1.4. and SR 3.3.6.1.5 CSR 3.3.6.1.6 Deleted) A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the *channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to. account for instrument drifts between successive calibrations, consistent with the assumptions 6f the current setpoint methodology. Specific to Main Steam Line Pressure-Low (Technical Table 3.3.6.1-1, Function l.b) and the Main Steam Line Flow-High (Technical Specification Table 3.3.6.1-1, Function l.c), there is a plant specific program which verifies that this instrument channel functions required by verifying the as-left as-found settings consistent with those established by the setpofot methodology. The Surveillance Frequency is controlled the Surveil1ance Frequency Control Program. continued B 3. Revis1on No. Jl9 I BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UNIT 3. Primary Containment Isolation Instrumentation B 3.3.6.1 SR 3.3.6.1.7 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 7.3. 2. NRC Safety Evaluation Report for Amendment Numbers 156 and 158 to Facility Operating License Numbers DPR-44 and DPR-56, Peach Bottom Atomic Power Station, Unit Nos. 2 and 3, September 7, 1990 . . 3. UFSAR, Chapter 14. 4. NED0-31466, "Technical Specification Screening Criteria Application and Risk Assessment," November 1987. 5. UFSAR, Section 4.9.3. 6. NEDC-31677P-A, "Technical Specification Improvement for BWR Isolation Actuation Instrumentation," July _1990. 7. NEDC-30851P-A Supplement 2, "Technical Specifications *Improvement Analysis for BWR Isolation Instrumeritation* .Common to RPS and ECCS Instrumentation," March 1989. B 3.3-168 Revision No.-87 Secondary Containment Isolation Instrumentation B 3.3.6.2 B 3.3 INSTRUMENTATION B 3.3.6.2 Secondary Containment Isolation Instrumentation BASES BACKGROUND PBAPS UNIT 3 The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1). Secondary containment isolation and establishment of vacuum with the SGT System within the required time limits ensures that fission products that leak from primary containment following a OBA, or are released outside primary containment, or are released during certain operations when primary containment is not required to be OPERABLE are maintained within applicable limits. The isolation instrumentation includes the sensors, relays, and switches that are necessary tQ cause initiation of secondary containment isolation. Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a secondary containment isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (1) reactor vessel water level, (2) drywell pressure, (3) reactor building ventilation high radiation, and (4) refueling floor ventilation exhaust high radiation. Redundant sensor input signals from each parameter are provided for initiation of isolation. The outputs of the channels are arranged in a one-out-of-two taken twice Automatic isolation valves {dampers) isolate and SGT subsystems start when both trip systems are in trip. Operation of both trip systems is required to isolate the secondary containment and provide for the necessary filtration of fission products. {continued) B 3.3-169 Revision No. 3

'** '*" ** . *:-: *,._,.*. Secondary Containment Isolation.Instrumentation B 3.3.6.2 BASES (continued) SAFETY ANALYSES, LCO, and ... APPLICABILITY The isolation signals generated by the secondary containment isolation instrumentation are implicitly assumed in the safety analyses of Reference$ 1 and 2 tri initiate closure of valves and start the SGT System to limit offsite doses. . ' . '<:-: .. . * ... -'V *, -*,.* . Refer to LCO 3.6.4.2, "SecondaryContainment Isolation Valves (SCIVs)," and LC03.6.4.3, "Standby Gas Treatment (SGT) System, ... Applicable Safety Analyses Bases for more detail of the safety analyses. * * -The secondary containment isolation instrumentation satisfies* Criterion 3 of the*NRC Policy Statement. Certain instrumentation Functions are retained for other reasons and are descri.bed below in the individual Functions discussion. *The OPERABILITY of the secondary containment isolation instrumentation is dependent on the OPERABILITY of the individual. channel Functions. Each Function must have the required number. of OPERABLE channels with their setpoints.set the specified Allowable Values, as shown.:.tn Table 3 .. 3:6. 2-L The actual setpoint is consistent.with ,applicable setpoint methodology A. channel inoperable if its actual trip *setting not withiri its required Allowable Value. ' . -. ' .. . . ' . ' Allowable* values are' specified_ *for* each specifi-ed

• in the ,Tabie. **Trip .setpoirits* are *specified ln the: setpoi.nt * -cal_clilations. *.The trip *setpoints are selected to ensure th.at. ttie *set points* do riot *exceed* the* Allowable Value betwe.en * .*.Operation with" a tri_p* setting less conservaq.ve the trip setpoi:nt, ** bu,t within its. Allowable* .. -, *. * ** * * . . . -' . -' ', . ' . .. * .. -., -. *'* -. *-* . .-. :* ** Trip setp-oi nts .. are -those_ :predetermined_ values' of output at , __ which an action should-t(lke ,place. lhe --* * .*: * * * ,: .coiri(>ar.e.d to the* act9a l t>ro<:ess parameter (e. g/, reactor . . .....
• vessel _.water: levelL. and* when -the in_eas.ured ,output value* of: . -'. ;: * , _ .. the; prpcess P.ara:metef:exceecis the* setpoint, the as sod a:ted *. deviCe trip unit) Changes arialytic* or . design,.limits.*are_ derived_from:the limiting value$ of the< ---. . *. _ .. par,ameters pbtained from.the* safety -analysis -or. *. ... -.. other,._appr,oprlate . A 11 owabl e __ V.a l ues are * . derived ._from Jhe. analytic qr. *design limits_,** corrected. for* :process, and.-fostfu.m*ent .The trip -.*
• setpoints are then .detey:lilin.ed. from ana]ytical "Or .design: . .;_ *_1 imits*, correc'ted for' calibration, process' and i'nstrument . ' -. . c*'_;* ,. ..... .-*: :. *:: ' . .* .*,* (continued) -.. '.>", ---. . *. . . . -... *
• Revisiori No.' 3 ---.. -... .* .-. ._ '. -**.,

BASES APPLICABLE SAFETY ANALYSES, LCO, and* APPLICABILITY (continued) . . -.. PBAPS. UNIT 3 Secondary Containment Isolation Instrumentation B 3.3.6.2 errors, as well as, instrument drift. In selected cases, the Allowable Values and trip setpoints are determined by *engineering judgement or historically accepted practice relative to the intended function of the channel. The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environments during the operating time of the associated channels are accounted for. In general, 'the individual Functions are required to be OPERABLE in the MODES or other specified conditions when SCIVs SGT System are required. The Applicable Safety Analyses, LCO, and App_licability di.scussions are listed below on a Function by Function basis. 1.

• Reactor Vesse*l Water Level -Low (Level 3) Low reactor pressure (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too.far, fuel damage could result. An isolati.on of the secondary containment and actuation of the SGT System are initiated in order to minimize the poteni{al of an offsite d6se The Reactor Vessel Water Lev.el".'."'" Low (Level 3} Function is one the Functions
• assumedto be OPERABLE and capable of pro.viding isolation *. and initiation signals. The isolation and initiation systems on Reactor Vessel Water Lev:el -Low* (level 3) support . actions to erisure that any offsite releases are within the lim,its>calculated in the safety analysis .. Reactor Vessel .Water Low 3) *signals are initiated' from level transmitters that sense the difference between the pressure due :to a constant column of water . and the pressure due to the actual water level (variable leg) in the.vessel. Four.channels of Reactor:_vessel *water Level,_: Low (Level 3) Function are ,available and are requfred to be-OPERABLE .in MODES 1;*2, and 3 fo ensure. that:no single iifstrumenLfailure can preclude *_ the i sol at ion function .. -* * . (continued} -,**-**. 8-Rev.ision No. 3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY PBAPS UNIT 3 ... -.,' .. Secondary Containment Isolation Instrumentation B 3.3.6.2 1. Reactor Vessel Water Level-Low {Level 3) . (continued) The Reactor Vessel Water Level -Low (level 3) Allowable Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves and SGT System start are not critical to orderly plant The Reactor Vessel Water Level -Low (Level 3) Fun ct ion is required to be OPERABLE in MODES l, 2, and 3 where considerable energy exists in the Reactor Coolant System (RCS); thus, there is.a probability of pipe breaks resulting in significant releases -0f radioactive steam and gas. In MODES 4 and 5, the probability and consequences rif events are low due to the RCS temperature limitations of these MODES; thus, this Function is not In addition, the Function is also required to be OPERABLE during operations with a potential for draining the reactor vessel (OPDRVs) because the capability of isolating potential sources of leakage must be provided to ensure that offsite dose limits are not if core damage occurs. 2. Drywell Pressure-High High drywell pressure can indicate a break in the reactor coolant pressure boundary (RCPB). An isolation.of the secondary containment and actuation of the SGT System are initjated in order to minimize the potential of an offsite dose release. The isolation on high drywell pressure supports actionsto ensure that any offsite releases.are within the limits calculated in the safety analysis. Tbe Drywell Pressure-High Function associated with isolation is not in any UFSAR accident or transient analyses but provide an* isolation arid initiation signal. It is retained for the redundancy and diversity of the secondary containment isolation instrumentation as required by the NRC approved licensing basis. (continued) Revision No.; 3

.. . . -:** ..... * . . .. BASES APPLICABLE SAFETY ANALYSES, LCO, and-. APPLICABILITY .. *, ,** Secondary Containment Isolation Instrumentation B 3.3.6.2 . 2. Drywell Pressure-High (continued} High drywell pressure signals are initiated from pressure. that sense the pressure in the drywell. Four channels of Drywell Pressure-High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude performance of the isolation

• The Allowable Value*was chosen to bethe same as the ECCS Drywell Pressure-High Function Allowable Value (LCO 3.3.5.1) since this is indicative of.a loss of coolant accident (LOCA). The Drywell Pressure-High Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable. energy exists in the RCS; there is a probability of pipe breaks in significant releases of steam an<;i gas. This Function is not required .in MODES. 4 . and 5 because the probability and consequences of these* events" are 1 ow due . to the RCS pressure and temperature limitations of these MODES.
• 4.* Rea'ctor Building Ventilation and Refueling Floor* Ventilation Exhaust Radiation-High . High secondary containme*nt exhaust radiation is* <!n . . indication of gross failure of the.fuel The release may have. originated from the *primary containment due toa break in the RCPB or during refueling due to a . -*tiandling accident. When Ven.tilation Exh.aust-Radiation-::High * . *is. deteeted' . secondary containment i sol ati on and. actuation .. . . of the SGT System are initiated to 1 imit t.he release of 'fission prodt,1cts as assumed.in the*UFSAR safety analyses (Ref ... 4). .. . * .. *-;*_. -* :-*-.; PBAPS' UNIT'/3 . .. '._' . . The*. Vent.ilation Exhaust: si.gnals are ' initiated from radiation detectors that are lOcated o.n the: . ventilatfon exhaust piping coming from the reactor building and the refueling floor"zones, respectively. The signal . from each detector is input to an .i ndi vi dual monitor whose tr-ip outputs are. assigned 'to an i sol at ion channel. .Four.* .. ' ,*_ *. . (continued) :*-* . ..... . . .. :.. **.**:. B 3 .3-173 *. Revision No. 3 .. ** *'. l.* ,. * ' *:
• \' ;. -BASES APPLICABLE . SAFETY ANALYSES,. LCO, and APPLICABILITY *.ACTIONS . "*. :' > . PBAPS *UNIT 3 .. Secondary Containment Isolation Instrumentation B 3.3.6.2 3 I 4. ' Reactor Building Ventilation and Refueling Floor Ventilation Exhaust *.Radiation-High (continued) channels of Reactor Building Ventilation Exhaust. Function and four channels of Refueling Fl6or Ventilation Exhaust Radiation-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Allowable Values are chosen to promptly detect gross of the fuel cladding. The Reactor Building Ventilation and Refueling Floor Ventilation Exhaust Radiation-High' Functions are required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists; thus, there a probability of pipe breaks resulting in significant of radioactive steam and gas. Iri MODES 4 and 5, the probability and consequences of these. events are low due to the RCS pressure and temperature limitations of the$e MODES; thus, these Functions are not required. In addition, the Functions are also 'to be OPERABLE during OPDRVs and movement of RECENTLY IRRADIATED FUEL assemblies in the secondary containment, because the of detecting releases due to fuel failures (due to fuel uncovery or dropped fuel assemblies) must be provided to that offsite dose limits are not exceeded. *A Note has been provided to modify the ACTIONS related to $econdary ,c6ntainment ii6lation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered; subsequent divisions, subsystems, components; or variables in the*Condition, discovered to be inoperable or not w.ithi n limits, wi 11 not* result in separate entry into the Condition. Section 1.3. also that Required Actions of the Condition continue to for each additional failure, with Completion Times based on initial entry into the Condition. However, Required Actions for inoperable secondary containment isolation instrumentation provide *appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows .. se'parate Condi ti on entry for each inoperable secondary contaioment isolation instrumentation channel. (continued) ' 8 3.3-174 Revision No. 76 *

,*,, BASES ACTIONS (continued) '.** PBAPS UNIT 3 Secondary Containment Isolation Instrumentation B 3.3.6.2 Because of the diversity of sensors* available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of 12 hours for Functions 1 and 2, and 24 hours for*Functions other than Functions 1 and 2, has been shown to be acceptable (Refs. 5 and 6) to pe.rmit restoration of any inoperable channel to OPERABLE status. Thi.s out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B.l Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.l. Placing the inoperable channel in trip would cbnservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the in6perable channel in trip would result in an Condition C be entered and its Required Actions Required Actiori B.l is intended to ensure that appropriate *are taken if multiple, inoperable, untripped channels within the same Function result in a compl_ete loss

• of i sol at ion capability. for the assoc1 ated penetration .fl ow pat.h(s) or a complete.loss of automatic initiation .. capability* for: the SGT System.. A *lunct ion is considered to be maintaining sectmdary containment *isolation capability. whe.n Sl,ifficient channels are OPERABLE or in trip, such that both trip sys terns wi 11 generate. a tr.i_p signal from the g i_ven . . function Ori a valid signal. ensu(es .that.at least of the*t.wo in the a.ssociated .penetration flow path and ... at. least one'SGT:subsystem can _be initiated on an .isolation . sfgnal from the given Furictfon. _,*For Functions l, 2, 3,. and 4, this would require both trip systems to have one channel OPERABLE or hi * .* .* CcontinuedL
• B 3.3-175 ' Revis ion No*' 3

i .. -/." . /* ... ' BASES ACTIONS .. *,.'.

• SURVEILLANCE . . * . -. '_: . *-. *. -**. . .. PBAPS 'JJNlt 3 .. *. ,:s _,.., -:,:. Secondary Containment lso.Jation Instrumentation . . . . . . B 3.3.6.2 B .I . (continued) '
• The completion Time is intended to allow the operator time to and repair any discovered inoperabilities. The l hour C6mpletion Time because it minimizes risk allowing time for restoration or tripping of channels .. . .. and If any*ReqUired Action.ahd associated Completion Time of Condition'A.or Bare not met, the ability to isolate the secoilda.ry containment and start the SGT System -cannot be. ensured. *Therefore, further a_ctions must be performed to . *ensure-the ability to maintain the. secondary containment function. lsolatingthe associated secondary containment penetration flow path(s) and starting the associated sen (Re qui red Act i ans C. l. l and C. 2. 1)
• perf arms the intended* fund ion* of the . instrumentation and a 11 ows operati_on to * * * *
• decla;i ng as*saci.ated *sc1Vs or. SGT subsyslem(s) inoperable *(Required Actions :C.L2 and C.2.2) is also acceptable* sinte .. the Required Actions of the ** *re*spective LCOs (LCO 3.6.4.2 and LCO 3.6'.4.3) provide .. appropriate
• actions for : i nope.rah le ' -,.. . -* . -.-. ' . One s suffi dent; fo.r /pl ant opera ti ons'personnel. to* .. e_stablish required plant conditions or to declare the .. associ.at!=!c:f inoper,able without unnecessarily
• challengin9, * *
• As: *nat.eq. 'the* SRs> the, each . -Se_tondary Containment ls.o'l.ation Functfon are* .. * -**Totated'.'inthe sRs coluritn of Tab1e 3-.3.6_.:2...:i.* -. *-.:; ., .. ; -*': . ... --.< *.' -...... : ... ' . . ,*-'*: .-:_ .* :* .. :,. I*'. ; '*.-. "'* ... ' . -. ':: * .. -*: . -. ," .* **-..... _ ,-* :;:*',:. -**,. * .. :' ' .. . ,-, >***". ........ :*.-*.*-.* Cconttnued} . -. ' -*_, *._,_. .. '.* . :_-*.-, Revision ,No.' 3 * .. _ ;* .* . * .. '

BASES SURVEILLANCE REQUIREMENTS (continued) .. _ ... -.. PBAPS' UN IT 3 *'*.-Secondary Containment Isolation Instrumentation B 3.3.6.2 The Surveillances .are modified by a Note to indicate that when a channel is placed in an stbtus solely for performance of Surveillances, entry into associated Conditions and Required Attions may delayed for up to 6 hours provided the associated Function maintains isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status*nr the Condition entered and Required Actions takeh .. This Note is based on the reliability analysis (Refs. 5 and 6) assumption that of the average time required to *perform channel surveillance. That an6lysis demonstrated hour testing allowance does not significantly reduce the probabilitj that the SCIVs will isolate the penetration flow paths and that the SGT System will initiate when necessary. SR 3.3.6.2.l Performance of the CHANNEL CHECK ensures that a gross failure of instrumehtatibn has not occurred. A CHANNEL CHECK is normally a comparison of *the indicated on one channel to a similar parameter on channels. It is based on* the assumpti'on that instrument channels monitoring the same parameter should read approximately th.e same value .. deviations between the instrument channels

• could be an indication of excessive instrument in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifyirig the instrumentation continues to operate properly* CHANNEL CALIBRATION. . criteria are determined by the plant staff based on a combination of the charinel instrument uncertainties, including indicatio*n and readability. If a channel is outside the it mciy be an indication that the has drifted outside its limit. The Surveillahce Frequency is c6ntrolled under the Surveillance* Frequency Control Program. The CHANNEL CHECK supplements less formal, but. more frequent, checks of channel status during use of the displays assdciated with channels required by the LCO.
• continued ' -; . B 3.3,,177 Revision.No. 87
• BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS LJN IT 3 Secondary Containment Isolation Instrumentation B 3.3.6.2 SR 3.3.6.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.6.2.3 and SR 3.3.6.2.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the chan*nel responds to the measured parameter within the necessary range and CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between sutcessive calibrations, consistent with the current plant specifit setpoint methodology. The Frequency is controlled under the *Surveillance Control Program. -SR 3 . 3 . 6 . 2 . 5 -The LOGIC SYSTEM FUNCTIONAL TEST demonstrates. the _OPERABILITY of the requi rec! i sol ati on logic -for a spe.cifi c The system functional testing on SCIVs and the SGT System in LCO 3.6.4.2 and LCO -respect1 vel y, overlaps this Survei 11 ance to pro vi de cOmpl ete . testing of the assumed safety The Surveillance Frequency is controlled under the frequency Program. (continued) : ' .. * -B 3 .. 3-ll8 .
• Rev i s i on N () : . 87 I 'i I BASES (continued) REFERENCES -.' . PBAPS UNIT** 3
• Secondary Containment Isolation Instrumentation B 3.3.6.2 1. UFSAR, Section 14.6. 2. UFSAR, Chapter 14. 3. UFSAR, Section 4. UFSAR, Sections 14.6.3 and 14.6.4. 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990. 6. NEDC-30851P-A Supplement 2, "Technical Specifications . Improvement Analysis fot BWR Isolation Instrumentation *Common to RPS and ECCS Instrumentation," March 1989. B 3.3-179 Revision No. 3 I . MCREV System Instrumentation B 3.3.7.1 B 3.3 INSTRUMENTATION B 3.3.7.1 Main Control Room Emergency Ventilation (MCREV) System Instrumentation BASES BACKGROUND The MCREV System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all plant conditions. Two independent MCREV subsystems are each capable of fulfilling the stated safety function. The instrumentation and controls for the MCREV System . automatically initiate action to pressurize the main control room (MCR) to minimize the consequences of radioactive material in the control room environment. In the event of a Control Room Air Intake Radiation-High signal, the MCREV System is automatically started in the pressurization mode. The outside air from the normal ventilation intake is then passed through one of the . ch.arcoal filter subsystems. Sufficient outside air .is drawn in through the normal ventilation intake to maintain the MCR
• slightly pressurized.with respect to the turbine building. The MCREV System instrumentation has two trip systems with* '*two Control Room Air Intake Radiation-High channels in each trip . The outputs of the Control Room Ai.r Intake Radiatto*n-High channelS are arranged in twotrip systems, which use a i:>ne-out,...of-two logic *. The tripping of both trip systems will initiate both MCREV subsystems. The channels include equipmefit (e.g., trfp Onits} that* -compares measured input signals with pre-e*stabl hhed setpoints .. When the*setpoint iS exceeded, the channel output relay acti'.fates; which then. a*utputs a MC REV System initiatfon_ signal to the_: initiation logic. APPLICABLE ..
• The ab*i Hty of the*. MC:REV System to i n:tai n. the habitability SAFETY ANALYSES; of the MCR is explicitly assumed for. certa1n accidents as LCO, .and * . *
• discussed in*. the UFSAR safety analyses ( s; 1, 2, and 3} . 'APPLICABILITY MCREV _System operation ensur(;!s that the *radiation exposure PBAPS UNIT 3* ' of control' ro.om personnel' through the duration of any one _of tbe postulated accidents, does not exceed ;acceptable iimits. * * ** * . ' .. ** <continued) * ._., ': i:,. *: . . Revision NO. 3 '

BASES APPLICABLE SAFETY ANALYSES, LCO, and APP LI CAB IL ITV (continued) . PBAPS UN IT ) MCREV System Instrumentation B MCREV System instrumentation satisfies Criterion 3 of the NRC Policy Statement. The OPERABILITY of the MCREV System instrumentation is dependent upon the OPERABILITY of the Control Room Air Intake Radiation -High instrumentation channel Function. The Function must have a required number of OPERABLE channels, with their setpoints within the specified *Allowable Values, where appropriate. A channel is inoperable if its actual trip setting is not within its required Allowable The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Allowable Values are specified for the MCREV System Control Intake* Radiation-High Function. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that. the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than setpoint, but within its Value, is acceptable. Trip setpoints are those predetermined values of output at which an action should take place; The setpoints are compared to actual process pirameter (e.g., control room air intake radiation), and when the measured output value of th(:! process parameter exceeds the setpoint, the associated device changes state. The analytic limits are derived from the limiting values of

• the parameters obtained from the safety analysis. The Allowable Values derived from the analytic limits, corrected for calibrati6ri, process, and instrument errors. The trip setpoints are determined from analytical or design . *limits, .cc:irrected for calibration, process, and instrument errors*;* as we*l T as, instrument The trip set points derived Jn this. manner provide adequate protection bY .. ensuring i nstrunient *and :prqce.ss uncertainties expected for the environments during the operating time of the associated channels *are. accounted for.** The: room *air infake monitors measure*. radiatfcm levels jn fresh air supply plenum. A high rac,liation level .may pose a threat to*MCR personnel; thus, automat'ically 'initiating the MC.REV System. . * (continued) ' .'.-* '.-:' . ' ' B Revfsi orj** No. 3 ..

BASES APPLICABLE SAFETY ANALYSES, *Leo, and APPLICABILITY (continued) ACTIONS *

• PBAPS UN IT 3 -*--.* ... MCREV System Instrumentation B 3.3.7.1 The Control Room Air Intake Radiation-High Function consists of four independent monitors. Two channels of Control Room Air Intake Radiation-High per trip system are available and are required to be OPERABLE to ensure that no single instrument failure can preclude MCREV System initiation. The Allowable Value was selected to ensure of the control room The Control Room Air Intake Function is required to be OPERABLE in MODES *1, 2, and 3 and during.CORE ALTERATIONS, OPDRVs, and movement of irradiated fuel assemblies in the secondary containment, to ensure that
• control room personnel are protected during a LOCA, fuel handling event, or draindown .. During MODES 4 and 5, when these specified conditions are not in progress (e.g., CORE ALTERATIONS), the probability of a LOCA or fuel damage is low; thus, the Function is not required. A Note has been provided to modify the ACTIONS related to MCREV System instrumentatfon channels. Section 1.3, Completion Times, specifies that once a has been entered, subsequent divisions, subsystems, components, or variables expressed in.the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condit'ion. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based.oil initial entry into theCondition. However, the Required Actions for. inoperable MCREV System instrumentation channels .provide. appropriate compensatory measures for separate inoperable* channels.** As such, a Note has been provided that allows separate Condition entry for each inoperable MCREV System channel.
• A.I and A.2 *Because of.the redundancy of sensors available to provide initiation signals and the redundancy of the MCREV System. design, an allowable otit of service time of 6 hours has been shown to be acceptable (Ref. 4), to permit restoration of any i noperab.l e channe 1 to OPERABLE status. However*, this out of service time is only acceptable provided the Control Room Air Intake Radiation-High Function is still maintaining MCREV System initiation capability. The Function is considered_ to be maintaining MCREV System . . . . (continued).

f .. * ":. .*: .. ', .< *.. . ,:* . ',*.* : ... " . ' .. . . . *. ,,'* . . . . *. -. *; .:. : '.*.* ., . .. . ':* '. .* ... BASES ACTIONS* . ': ... : .. < . .. ,_ -'. -* . ' . . ' . . '*" -. . .... . -** ... . *. PBAPS : *-,* :** .. *'*;.' . :/. .. **.;-,. MCREV System Instrumentation. 8 3.3.7.1 A:l and A.2 (continued) initiation capability when sufficient channels are *OPERABLE or in trip such that the two.* trip systems wi. ll generate an . initiat*ion signal from the given Function on a valid.signaL. For the Control .Room Air Intake Radiation-High Function, this would require the two trip systems to have channel per trip* system OPERABLE or in trip. .In this situation* (loss of MCREVSystem initiation capability},' the 6 hour allowance of Required Action A.2 is not approp.riate .. *If the Function is not maintaining MCREVSystem initiation . ccipability, the MCREV System must be declared inoperable within 1 hour of discovery of the loss of.MCREV.System initiation capability in both trip systems. . . . . . . The 1 hour Completion Time (A.I) is acceptable because it* minimizes risk while allowing time for restoring or tripping of * * ** If the inoperable channel cannot be re.stored to OPERABLE . status within the allowable*out of service time, the channe.l must.be placed tripped condition per Required ..

• Adion Placi_ng the inoperable channel in trip would. conservatively compensate for the. inoperability, restore .. *. capability to.accommodate a single failure, and allow i .. * . continLle. Alternately, if it is not t6 place the channel in trip (e.g., as in the case where , _.
• _placing the inoperable channel in trip would result in an . .. .Condition B*must be ente.red and its .Requited* Act i*on taken. * * * *.:******. . :1f.1 .;and B.2 With: any (\ct'iCm and Completion Time :not * .*.
• the associated MCREV subsystem(s) must be pl aced. in ... . .. operation per Required*Atti:onB.lto ensure that control* .. '.room personnel \flfll be protected in the .event of a Desi.gn : Bcisis Accident., The used to place *the MCREV *. . subsystem(s) in _operatto.11 must provide for automatically** re'.""initiating the subsysJem(s} upon restoration of power following*a loss of power to the MCREV subsystem(s).' . -. Alternately, if* it, is n.ot desi re.d to start the. subsystem{s}, ** .the fo1CREV subsy_stem(s} .associated with .. inpperable, untrippe_d.** * * '* . . i nued) . *,,. , . -*;.**.' .... . :* _. '."* ' -*--.. :**: . B 3 .3-18.3 *. Revis i cin<N9.
• 3 -**.'*., .. ! * .... . .. t* .:::-* .. **

BASES ACTIONS SURVEILLANCE REQUIREMENTS / . UNIT 3 B.l and B.2 (continued) MCREV System Instrumentation B 3.3.7.1 channels must be declared inoperable within 1 hour. Since each trip system can affect both MCREV subsystems, Required Actions B.l and B.2 can be performed independently on each MCREV subsystem. That is, one MCREV can be placed in operation (Required Action B.1) while the other MCREV 5ubsystem can be declared inoperable (Required Action B.2). The 1 hour Completion Time is intended to allow the operator time to place the MCREV subsystem(s) in operation. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for placing the associated MCREV subsystem(s) in operation, or for entering the applicable Conditions and Required Actions for the inoperable MCREV subsystem(s). The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated and Required Actions may be delayed for up to 6 hours, provided associated Function maintains MCREV System initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 4) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing does not significantly reduce the probability that the MCREV System will initiate when necessary. SR 3.3.7.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK {s normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring ihe same parameter should read approximately the same value. Significant deviations between the instrument channels tould be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect continued B 3.3-184 Revision No. 87 I I J BASES SURVEILLANCE REQUIREMENTS .* ,; PBAPS UN IT . 3 SR 3.3.7.1.l (continued) MCREV System Instrumentation B 3.3.7.1 gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supp1ements less formal, but more frequent, checks of channel .status during normal operational use of the displays with channels required by the LCO. SR 3.3.7.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the.entire channel wi 11 perform the intended *function. Any setpoint adjustment shall be consistent with the assumptions of the curreht plant specific setpoint methodolog'y. . . The Sur\1ei 11 ance Frequency *is controlled under the Survei 11 ance Frequency Control Program. SR 3.3.7.L3 A CAlIBRAtlON a complete check of lhe loop and the* This.test verifies the responds t9 the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION Teav.es the channel adjusted to account for i.nstrument drifts between succ*essive cal i bra'ti.ons' rnnsi stent with the as*sumpti ons of the pl ant specific_ sHpoi nt methodol og.y. .* The Surveil 1 Freque.ncy is controlled under the Surveti l_ance Frequency Control Pr-ogram. *(continued) B .3.3-185 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES . ... -:_ .-PBAPS UNIT 3 SR 3.3.7.1.4 MCREV System Instrumentation B 3.3.7.1 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.7.4, "Main Control Emergency Ventilation CMCREV) System," overlaps this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 10.13. 2. UFSAR, Section 12.3.4. 3. UFSAR, Section 14.9.1.5. 4. GENE-770-06--1, "Bases for Changes to Survei 11 ance Test Inter*vals and Allowed Out-of-Service Ti.mes for Selected Instrumentation Technical Specifications," Feb r pa r y 19 91 . B 3. J:..186 Revisi*on No. 87 -_, . I LOP Instrumentation B 3.3.8.1 B 3.3 INSTRUMENTATION B 3.3.8.1 Loss of Power (LOP) Instrumentation BASES BACKGROUND PBAPS UNIT 3 ---. '. Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power for energizing various components such as pump motors, motor operated .valves, and the associated control components. The LOP instrumentation monitors the 4 kV emergency buses voltage. Offsite power is the preferred source of power for the 4 kV emergency buses. If the LOP instrumentation detects that voltage levels are too low, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources. Each Unit 3 4 kV emergency bus has its own independent LOP instrumentation *and associated trip logic. The voltage for each bus is monitored at five levels, which can be considered as two different. undervoltage Functions: one level of loss of voltage and four levels of degraded voltage. The Functions cause various bus transfers and disconnects. The degraded voltage Function is monitored by four undervoltage relays per source and the loss of voltage Function is monitored by one undervoltage relay for each emergency The degraded voltage outputs and the loss of voltage outputs are arranged in a one-out-of-one trip logic configuration. Each channel consists of four protective relays that compare offsite source voltages with pre-.established setpoints. When the sensed voltage is below the setpoint for a degraded voltage channel, the preferred offsite source breaker to'the 4 kV emergency bus is tripped and autotransfer to the alternate offsite source is

• initiated. If the alternate source does not provide adequate voltage to the bus as sensed by its degraded grid. relays, a diesel generator start signal is initiated. A description of the Unit 2 LOP instrumentation is provided in the Bases for Unit 2 LCO 3.3.8.1. (continued) B *3.3-187 .**Revision No. 5 BASES (continued) APPLICABLE SAFETY ANALYSES, LCD, and APPLICABILITY LOP Instrumentation B 3.3.8.1 The LOP instrumentation is required for Engineered Safety Features to function in any accident with a loss of offsite power. The required channels of LOP instrumentation ensure that the ECCS and other assumed systems powered from the DGs, provide plant protection in the event of any of the Reference 1 (UFSAR) analyzed accidents in which a loss of offsite power is assumed. The first level is loss of voltage. This loss of voltage level detects and disconnects the Class lE buses from the offsite power source upon a total loss of voltage. The second level of undervol tage protection provided by the four levels of degraded grid voltage relays which are set to detect a sustained low voltage condition. These degraded grid relays disconnect the Class lE buses from the offsite power source if the degraded voltage condition exists for a time interval which could prevent the Class lE equipment from achieving its safety function. The degraded grid relays also prevent the Class lf equipment from sustaining damage from prolonged operation at reduced voltage. The combination of the loss of voltage relaying and the degraded grid relaying provides protection to the Class lE distribution system for all
• credible conditions of voltage collapse or sustained voltage degradation. The. initiation of the DGs on loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Accident analyses credit the loading of the DG based on the loss of offsite power during a loss of coolant The diesel starting and* loading times been included in* the delay time each safety.system component requiring DG supplied power following a loss of offsite
• power. The LOP instrumentation satisfies Criteritin 3 of the NRC 'Policy Statement. * * -The. OPERABILITY of_ the LOP is upon t he 0 P ERA B I LI TY o f t he-i n d i v. i d u a 1 in st r um en t a t i on re 1 a y ch an n e 1 Fun Ct i on s spec if ie.d i n Table 3 . 3 . 8 . 1 -1. Each *Function must have a required number of OPERABLE channeJs per 4 kV bus, their setpoints within the specified Allowable Values except the bus undervoltagi which does not have an Allowable Value. A degraded voltage .channel is if its actual setpoint is not. within its required Allowable Value.* Setpoints are calibrated consistent with the Improved Instrument Setpoint C6ntrol Program (IISCP) methodology assDmptions. I continued B 3. 188 Revision No.-88 I I. BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) . PBAPS UN IT 3 LOP Instrumentation B 3.3.8.1 . The loss of voltage channel is inoperable if it will not start the diesel on a loss of power to a 4 kV emergency bus. The Allowable Values are specified for each Function in the Table 3.3.8.1-1. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint within the Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., voltage), and when the measured output value of the process parameter exceeds the setpoint, the protective relay output changes state. The Allowable Values were set equal to the limiting values determined by the voltage regulation calculation. The setpoints were corrected using IISCP methodology to account for relay drift, relay accuracy, potential transformer accuracy, measuring and test equipment accuracy margin, and includes a calibration leave alone zone. IISCP methodology utilizes the square root of the sum of the squares to combine random non-directional accuracy values. IISCP then includes relay drift, calibration leave alone zones, and margins. The setpoint assumes a nominal 35/1 potential transformer ratio. The specific Applicable Safety Analyses, LCO, and Applicability discussions for Unit 3 LOP instrumentation are listed below on a Function by Function basis. In addition, si.nce some equipment required by Unit 3 is powered from Unit 2 the Unit 2 LOP instrumentation supporting the required sources must also be OPERABLE. The OPERABILITY requirements for the Unit 2 LOP instrumentation is the same as described in this section, except Function 4 (4 kV Emergency Bus Undervoltage, Degraded Voltage LOCA) is not required to be OPERABLE, since this Function is related to a lOCA on Unit 2 only. The Unit 2 instrumentation is listed in Unit 2 Table 3.3.8.1-1. 1. 4 kV Emergency Bus Undervoltage (Loss of Voltage) When both offsite sources are lost, a loss of voltage condition on a 4 kV emergency bus indicates that the respective emergency bus is unable supply sufficient power for proper operation of the applicable equipment. Therefore, the power supply to the bus is transferred from offsite power to DG power. This ensures that adequate power will be available to the required equipment.
• continue . B 3. 3-189 Revision No. 88 I _J

... I . BASES APPLICABLE SAFETY ANALYSIS, LCD, and APPLICABILITY PBAPS. UN IT 3 LOP Instrumentation B 3.3.8.1 1. 4 kV Emergency Bus Undervoltage (Loss of Voltage) (continued) The single channel of 4 kV Emergency Bus Undervoltage (Loss of Voltage) Function per associated emergency bus is only required to be OPERABLE when the associated DG and offsite circuit are required to be OPERABLE. This ensures no single instrument failure can preclude the start of three of four DGs. (One channel inputs to each of the four DGs.) Refer to LCD 3.8.1, "AC Sources-Operating," and 3.8.2, "AC Sources-Shutdown," for Appl i ca bi l i ty Bases for the DGs. 2 .. 3 .. 4 .. 5. 4kV Emergency Bus Undervoltage (Degraded Voltage) A degraded voltage condition on a 4 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficient for starting large ECCS motors without risking damage to the motors that could disable the ECCS function. Therefore; power to the bus transferred from offsite power to onsite DG power wben there is insufficient offsite power to the bus. This transfer will occur only if the voltage of the preferred and alternate.power sources drop below the Degraded Vciltage F0nction Allowable Values (degraded voltage with a time delay) and the source breakers trip which causes -the bus undervoltage rela.y to initiate the DG. This ensures that power will be available to the.required equipment:

• Four Functions are to monitor c;Jegr.aded voltage at four different leveJs .. These are the Degraded Voltage Non-LOCA, Degraded-Voltage LOCA, Degr*aded Voltage High Setfing*, .and Degraded Voltage Low Setting. *These *monitor the following voltage levels with the:. following time delays*: th.e Function 2* relay, 2286 -2706 2'secorids when source: voltage is
• abruptly to *z*ero volts (inverse-time.delay); the Function 3 re.lay, 3409 -3829. volts in appr.oximately 30 seconds voltage is reduced abruptly to 2940 volts *cinverse time delay); the Function 4 relay, 3766 -* 3836 yolts in approximately 10 seconds; and ttie Function 5 r-elay,* 4l:l6 --4186-volts in approximately 60. seconds: The * *-Fundio'n 2_and 3* relays ar(inverse time delay relays ... These relaYs operate along a curve* ..
• With relay operation being inverse with time, for continued B 3.3-190 :Revision No. 88:

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY ACTIONS PBAPS UNIT 3 ,, LOP Instrumentation B 3.3.8.1 2 .* 3 .. 4 .* 5. 4 kV Emergency Bus Undervoltage (Degraded Voltage} (continued) an abrupt reduction in voltage the relay operating time will be short; conversely, for a slight reduction in voltage, the operating time delay will be long. The Degraded Voltage LOCA Function preserves the assumptions of the LOCA analysis and the combined Functions of the other relays preserves the assumptions of the accident sequence analysis in the UFSAR. The Degraded Voltage.Non-LOCA Function provides assurance that equipment powered from the 4kV emergency buses is not damaged by degraded voltage that might occur under other than LOCA conditions. This degraded grid non-LOCA relay has an associated 60 second timer. This timer allows for offsite source transformer load tap changer operation. Degraded voltage conditions can be mitigated by tap changer operations and other manual actions. The 60 second timer provides the time for these actions to take place.

• The degraded grid voltage.Allowable Values are low enough to inadvertent power supply transfer, but high enough to ensure. that sufficient power is available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment. Two channels (one channel per source) of 4 kV Emergency Bus Degraded Voltage (Funttions 2, 3, 4, and 5) per associated bus are required to be OPERABLE when the associated DG and offsite-circuit are required to be OPERABLE. . This ensures no single failure can preclude the start of three of four DGs (each_ 1 ogic' inputs to each of the four DGs ). Refer to LCO 3. 8 .1 and LCO .3. 8. 2 for App li cabi 1 i ty Bas.es for the DGs. *
• A Note* has been provided (Note 1) to modify the ACTIONS
• related to LOP instrument(ltfon channels. Section 1.3, Times, spec_ifies that once a Condition has been entered; divisions; components, or* variables expressed in the Condition, .discovered to be inoperable or not within limits, will not result in separate the Cpndit ion.: Section L 3 a Tso specifies that . . Required Actions of the Condition continue to apply for*each _ additiOna.l Times based on initial (cont i nu*ed) ; Rev i s ion "1 . I " " 'I i. BASES ACTIONS (continued) ' *: ** t .. -' -.*. ._ PBAPS-UNIT 3 . -. '*--. LOP Instrumentation B 3.3.8.1 entry into the Condition. However, theRequired Actions for inoperable LOP instrumentation channels provide appropriate compensatory measures for separate inoperable.channels. As such, a Note has been provided that allows separate Condition entry for each inoperable LOP channel . . A. I Pursuant to LCO 3.0.6, the AC Sources-Operating .ACTIONS would not have to be entered even if the LOP instrumentation fooperabil ity _resulted. in an inoperable offSite circuit. Therefore, the Required Action of Condition A is modified by _a Note to indicate that when performance of a Required . *Action results in the inoperability of an offsite circuit, Actions for LCO 3.8.1, 11AC Sources-Operating;" must be immediately entered. A Unit 3 offsite circuit is considered to.be inoperable if it is not supplying or riot capable of supplying (due to loss of autotransfer capability) at least three Unit 3 4 kV emergency buses when the other offsite
• circuit .is power capable of supplying power to *all four Unit 3 4 kV eme_rgency buses. A Unit 3 offsite circuit is also considered to be inoperable if the Unit 4 kV emergency buses being powered-or capable of be1ng powered.from the two offsite circuits. are all the-same when* at least -one of the_ two circuits does not provide power or is not capable **of supplying power to all four Unit 3 4 kV emergency buses; Inoperabil ity of a Unit 2 off site circuit is the same as described for a Unit 3 offsite cfrcuit, except that the circuit path _is to the Unit 2 4 kV emergency buses required to be OPERABLE by LCO 3. 8. 7, "Di str1 but ion
• Systems .:....:-Operating." The Note allows Con_ditiCm' A to ._. provide requirements for the 1 os'S of *a LOP -i nstrllmentatlon w.ithout regard to whether an offsite *Circuit is* -rendered inoperable. -LCO 3.8.1 provides appropriate -restrict.ion for. an inoperable offsite circuit.
• Required Action A.l-is applicable when one 4 kV emergency bus.has one or two required Function 3 (Degraded Voltage High Setting) channels inoperable or when one 4 kV emergency bus has one or two required Function 5 (Degraded Voltage Non-LOCA) channels inoperable. In this Condition, the affected .Function may not be capable of performing *its intended function automatically for these buses. However, the would.still receive indication in the control room.of r condition on the unaffected buses and .a manual transfer of the affected bus powet supply to ( cont_i n-ued) ... : *. -' ._ < Revision 5: ,,., .. ._J I *: ,*: " ' r:. *,' . "* I . ; ' . . ' -. . ' .***. .* -** . _: BASES ACTIONS ' ' . _. PBAPS .UNIT j .. * .. ., . A. I (continued) LOP Instrumentation . B 3.3.8.1 the alternate source could be made without damaging plant equipment. Therefore, Required Action A.I allows 14 daYs to restore the inoperable channel(s) to OPERABLE status or place the inoperable channel(s) in trip. Placing the inoperable channel in trip would conservatively compensate for the i noperabi l i ty, restore design trip capabil i ty to the .* LOP instrumentation, and allow operation to continue.
• Alternatively, if it is not desired to place the channel tn trip (e.g., as in the case where placing the channel in trip would result in DG initiation), Condition D must be entered and its Required Action taken.
• The I4 day Com'pletion Time is intended .to allow time to. restore the channel(s) to OPERABLE status. The Completion. Time takes into consideration the diversity of the Degraded Voltage Functions, the capabilities of the remaining LOP Instrumentation Functions on the affected 4 kV emergency bus and on the other 4 kV emergency .buses (only one 4 kV emergency bus is affected by the inoperable channels)., the fac*t that the Degraded Voltage High Settin'g *and Degraded -Voltage Non-LOCA Functions provide only a marginal increase in the protection pr-ovided by the voltage monitoring scheme, the low probability of the grjd
• in* the voltage -band* protected by these Funct i ans, and the:. * * *ability of the operators to perform:the Functions . . Pursuant to LCO 3. 0. 6, th.e' A.C Souri:es -Operating ACTIONS would not have to be entered even if the LOP instrumentation inoperability resulted in an inoperable offstte circuit. * .. Therefore, the Requtred Action of ConditiorLB *is modified .by .. a Note to that .when performance of a Required * . . .. .. Action results in the. inoperability of *an offsite circui.t; Actions *for.*LCO Sources-'Operating,11 must be'. *_. . immediately entere.d. A Unit 3 offsite circui't is considered. to be i nope.rable. if it i S: not Slipplyi ng or not capable o.f .. " supplying (due to loss of autotransfer capability) at least ', .. three Unit 3 4 kV emergency buses when the other offsite * . circuit is provid*ing power or capable of supplying power to .. all four Unit 3 4 kV emergency buses. A. Uriit 3 offsite ....
• circuit is also considered to be inoperable if the Unit 3, 4 kV emergency buses befog powered or of being* . : . powereq from the two offsite circuits are all the. same. when***. ..at least orie of the two. circuits does not provide power or. ** . i nu.ed} .. . .. *:'** B 3.3-193 * :RevisicinNo. 5 ... " , .. * .. **;*_:' :1 BASES ACTIONS PBAPS UNIT 3 B. l (continued) LOP Instrumentation B 3.3.8.l is not capable of supplying power to all four Unit 3 4 kV emergency buses. Inoperability of a Unit 2 offsite circuit is the same as described for a Unit 3 offsite circuit, except that the circuit path is to the Unit 2 4 kV emergency buses required to be OPERABLE by LCO 3.8.7, "Distribution Systems -Operating." This allows Condition B to provide requirements for the loss of a LOP instrumentation channel without regard to whether an offsite circuit is rendered inoperable. LCO 3.8.1 provides appropriate restriction for an inoperable offsite circuit. Required Action B.l is applicable when two 4 kV emergency buses have one required Function 3 (Degraded Voltage High Setting) channel inoperable, or when two 4 kV emergency buses have one required Function 5 (Degraded Voltage LOCA) channel inoperable, or when one 4 kV emergency bus has one required Function 3 channel inoperable and a different 4 kV emergency bus has one required Function 5 channel inoperable. In this Condition, the affected Function may not be capable of performing its intended function automatically*for these buses. However, the operators would still receive indication in the control room of a degraded voltage condition on the unaffected buses and a manual transfer of the affected bus power supply to the alternate source could be made without damaging plant equipment. Therefore, Required Action B.l allows 24 hours to restore the inoperable channels to OPERABLE status or place the inoperable channels in trip. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore design trip capability to the LOP instrumentation, and allow operation to continue. Alternatively, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in DG initiation), Condition. D must be entered and its Required Action taken. The 24 hour Completion Time is intended to allow time to restore the channel(s) to OPERABLE status. The Completion Time takes into consideration the diversity of the Degraded Voltage Functions, the capabilities of the remaining OPERABLE LOP Instrumentation Functions on the affected 4 kV . emergency buses and on the other 4 kV emergency buses (only . two 4 kV emergency buses are affected by the inoperable channels), the fact that the Degraded Voltage High Setting *and Degraded Voltage Non-LOCA Functions provide only a (continued) B 3.3-194 Revision No. 5 BASES ACTIONS ' .. ---'.-*-_ PBAPS UN IT 3 lL...l (continued) LOP Instrumentation B 3.3.8.1 margirial increase in the protection provided by the voltage monitoring scheme, the low probability of the grid operating. in the voltage band protected by these Functions, and the ability of the operators to perform the Functions manually. Pursuant to LCD 3.0.6, the AC Sources-Operating ACTIONS would not have to be entered even if the LOP Instrumentation inoperability resulted in an inoperable offsite circuit. Therefore, the Required Action of Condition C is modified by a Note to iridicate that when performance of the Required Action results in the inoperability of an offsite circuit, Act1ons for LCD 3.8.1, "AC Sources-Operating,!' must be immediately entered. A Unit 3 offsite circuit is considered to be inoperable if it is not supplying or not capable of supplying (due to loss of autotransfer capability) at least three Unit 3 4 kV emergency buses when the other offsite. circuit is providing power or capable of supplying power to all four Unit 3 4 kV emergency buses. A Unit 3 offsite circuit is also considered to be inoperable if the Unit 3 4 kV emergency buses being powered or capable of powered from the two offsite circuits are all the when at least one of the. two circuits does not provide power or is .not capable of supplying power to* all four Unit 3 4 kV emergency buses. Inoperability of a Unit 2 offsite circuit is the same as described for a Unit 3 offsite circuit, except* that the circuit path is to the. Unit 2 buses required to be OPERABLE by LCD. 3.8.7; "Distribution Operating."* The Note allbws C.onditiOn C ,to.provide requirements for the loss of a -LOP i nstru-rrientati on channel without regard to whether ari -offsite circui*t is rendered inoperable. lCO 3.8.i provides appropriate restricti'ori for an inoperable offsite circuit.---. *:-, .---. Required,Acliciil c.r is appli.cable when.bne or mor.e 4 kV,> emergency bµ'ses have o'ne. or rriore J'equired* Function 1, 2, or 4 (the Loss of Voltage, the Degraded Vol Low Setting, and the Degrade*d Voltage LOCA Functions, respectively) channels i noperabl.e .-_or when one 4 kV emergency bus has oi:le required Fu_ncti.on 3 (Degraded Voltage High Setting) channel . and one required F.unCtion 5 .(Degraded Voltage Non-LOCA) ._ * -<-thanne\. o'r when.-any :combinati-on of three or more' required Function 3 and/or Function 5 channels are -1*
• inoperable.* . In t.his Cbndition, the affected Function may* not be*capable continued B 3 .. 3-195 Revision No._ 78 BASES ACTIONS -SURVElL.LANCL .* REQUIREMENTS .. *'( .. -' . PBAPS UNl_T j LOP Instrumentation B 3.3.8.1 C.l (continued) of performing the intended function and the potent i a.l conseqOences associated with the inoperable channel(s) greater than those resulting from Condition A or Condition S. Therefore, ortly 1 hour is allowed to restore the
• inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service the channel must be placed in the tripped condition per Required Action C.l. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore design trip capabilitj to the LOP instrumentation, and allow operation to Alternately, "if it is not desired to place the . channel *in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation), Condition D must be entered and its Required Action taken. . . . . . . The Completion Time is based on the potential consequences associated with the inoperable channel(s} and is intended to allow the time.to evaluate and repair any discovered The 1 hour Completion Time. is acceptable because it minimizes riskwhile allowing time for restoratiori.or tripping of channels. If any Required Action and associated Completion Time are *not met; the associated function is riot capable of performing the intended function, Therefore, the associated
• DG(s) is declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of 'Leo LCO which provide appropriate actions for the -.* * . ' *. -. , . As noted at the beginning'of the SRs, the SRs for each Unit l LOP Funttion are located in the SRs C()lumn SR . .5 is applicable only to Unit 2 LOP iristrumentation:
• The su'rveillance are by a Note *t-0 indicate :that wlien a channel is placed in an inoperable status solely for performance of required Surveillances, .entry into associa:ted Conditions and.Required Actions may be delayed for-up _tcf2 hours py-ovided: (a) for Futidion 1, the * .associat.ed function maintains initiation ca"pability for (continued) B . .3-.3-'-196 .
• Revi s*:i on No: 5 BASES SURVEILLANCE REQUJ REMENTS (continued) --c.-' PSAPS UN IT 3 LOP Instrumentation B 3.3.8.1 three DGs; and ( b) for Funct.i ons 2, 3; 4, 5, the associated Function maintains undervoltage capability for three 4 kV emergency buses. The loss of function for one DG or undervoltage transfer capability for the 4 kV emergency bus for this short period is appropriate since only three of four DGs are required to start within the required times and because there is no appreciable impact on risk. Also, upon completion of the Surveillance, or expiration of the 2 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.* SR 3.3.8.1.1 and SR 3.3.8.1.3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to that the entire channel will perform the intended function. Any setpoint adjustment shall be with assumptions of the current plant setpoint methodology. The Surveillance Frequency is controlled under the* Surveillance Frequency Control Program. SR 3.3.8.1.2 A CHANNEL CALIBRATION is a check of the relay circuitry and associated time delay relays. Thts test *verifies the channel responds to the parameter within the.necessary* range and accuracy. CHANNEL. CALIBRATION leaves the channel adjusted to account for instrument drifts between c6nsistent with the assumptions of the current specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Control Program. .. --... continued B 3.3d97 Revision NO; 87 * *.,'* I .

BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UNIT 3, '-SR 3.3.8.1.4 LOP Instrumentation B 3.3.8.l The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCD 3.8.l and LCD 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.8.1.5 With the exception of this Surveillance, all other Surveillances of this Specification (SR 3.3.8.1.1 through SR 3.3.8.1.4) are applied only to the Unit 3 LOP i n s t r u men ta t i on . -T h i s S u r v e i 1 1 a n c e i p r o v i d e d t o d i rec t _that the appropriate Surveillance the required Unit 2 LOP instrumentation are governed by the Unit 2 Technical Specifications. Performance of the applicable Unit 2 Surveiflances will satisfy Unit 2 requirements, as well as satisfying this Unit 3 Survei 11 ance Requirement. The Frequency required by the applicable Unit 2 SR also governs performance of that SR for Uhit 3. 1. UFSAR, Chapter 14. B 3.3-198 Revision No. 87 RPS Electric Power Monitoring B 3.3.8.2 B 3.3 INSTRUMENTATION B 3.3.8i2 Reactor Protettion System (RPS) Electric Power Monitoring BASES BACKGROUND PBAPS UNIT. 3 RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG) set or an alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus against unacceptable voltage* and frequency conditions (Ref. 1) and forms an important part of the primary success path of the essential safety circuits. Some of the essential equipment powered from the RPS buses includes the RPS logic and scram solenoids. RPS electric power monitoring assembly will detect any abnormal high or low voltage or low frequency condition in the outputs of the two MG sets or the alternate power supply and will de-energize its respective RPS bus, thereby causing all safety functions normally powered by this bus to . de-energize. In the event of failure of an RPS Electric Power Monitoring System (e:g., both in seriei electric power monitoring *assemblies), the RPS loads may experience significant effects from the unregulated power supply. Deviation from the nominal conditions can potentially cause damage to the scram solenoids and other Class IE devices. In the event of a low voltage condition, the scram solenoids can chatter and potentially lose their pneumatic control capability, resulting in a loss of primary scram action. In the event of an overvoltage condition, the RPS logic relays and scram solenoids may experience a voltage higher than their design voltage. If the overvoltage condition persists for an extended time period, it may cause equipment degradation and the loss of plant safety function. Two redundant Class IE circuit breakers are connected in series between each RPS bus and its MG set, and between each RPS bus and its alternate power supply if in service. Each of these circuit breakers has an associated independent set (continued) B 3.3-199 Revision No. 3 I i .* BASES BACKGROUND (continued) RPS Electric Power Monitoring B 3.3.8.2 of Class IE overvoltage, underyoltage, underfrequency relays, time delay relays (MG sets only), and sensing logic. Together, a circuit breaker, its associated relays, and sensing logic constitute an electric power monitoring assembly. 'If the output of the MG set or alternate power supply exceeds predetermined limits of overvoltage, undervoltage, or under.frequency, a trip coil driven by this logic circuitry opens the circuit breaker, which removes the associated power supply from service. APPLICABLE The RPS electric power monitoring is necessary to meet the SAFETY ANALYSES of the safety analyses by ensuring that the equipment *powered from the RPS buses can perform its intended function.

• RPS electric power monitoring provides protectibn to the RPS components that receive power from the RPS buses, by acting to disconnect the RPS from the power supply under specified conditions that could.damage the RPS LCO ,. ,* . .. "' .; .-,; .. PBAPS UNIT 3 *_ equipment.
• HPS electric power monitoring satisfies Criterion 3 of the NRC Pol icy Statement .. 'The OPERABILITY' of each:RPS electric ,power monitoring' '
• as*semblY. is .dependent on the OPERABILITY of the overvoltage,. undervciltage, and as well as the OPERABILITY of the associated cfrcui t breaker. Two el ectriC power monitoring assemblies are required to 'be OPERABLE for *each inservice* power s,upply. This provides redundant* protection against any abnormal*voltage or.frequency cqnditibns* to no single RPS electric power mi:mitoril'lg assembly.failure can* preclude the function of RPS components .. Ea.ch i nservi ce el ectr'iC power monitoring assembly's trip logic setpoints are require<i:J:to be within*. the specified Allowable.Value. lhe setpoint :;s * ** '.calibr'ated' cons1stent with, applicable' setpoint methodology . assumpt io!ls * .. * * 'values are specified for each RPS: electric . monitoring asse.mbly trip logic (refer to SR 3.3.8.2.2) .. Trip are in The.trip set points, are* sel e.cted based on engineering -judgement and* . . _ i;>pera_t ion* al experience to .ensure .that-the set points do -not. exceed the* Allowable Value '.between CHANNEL CALIBRATIONS. .. \:Jith a trip setting les.s conservative than the tr1p -seJpo1nt, but within Jts Allowable Value, is .. ... :. . : . ..,}. *:." ' (continued) B 3 .3-:-200 Revision No. 3 BASES LCO (continued) . *,, _ PBAPS -UNIT .3 RPS Electric Power Monitoririg B 3.3.8.2 acceptable. A channel is inoperable if its actual trip setting is not within its required Allowable Value. Trip setpoints are those predetermined values of output at which an action should take.place. The setpoints are compared to the actual process parameter (e.g., overvoltage), and when the measured output value of the process parameter exceeds the setpoint, the associated device changes state. The overvoltage Allowable Values for the RPS electrical power monitoring assembly trip logic are derived from vendor specified voltage requirements. The undetfrequency Allowable Values for the RPS electrical power monitoring assembly trip logic are based on tests performed at Peach Bottom which concluded that* the lowest frequency which would be reached was 54.4 Hz in 7.5 to 11.0 secorids depending load.* Bench tests.were also performed on RPS components (HFA relays, scram contactors, and scram valves) under more severe than thbse in the plant (53 Hz during 11.0 and 15.0 second intervals). Examination of these components concluded that functioned correctly under these conditions. The undervoltage Allowable Values for the RPS electrical power;monitoring assembly.trip were confirmed to be *acceptable throug_h testing. Testing has shown the scram pilot solenoid valves can be subjected to voltages below 95 volts with no degradation in their ability_ to perform their safety function. It was concluded the RPS logic relays and scram contactors' will*not be adversely affected by voltage below 95 volts since *these components will -dropout under -\foltageconditions thereby satisfying their safety
• funcffon . . The of the RPS eiectric power mon-itoring
• a.ssembl-ies is essential fo. disconnect the RPS components from *the_ MG_ set or _alternate power supply-during abnorma 1 voltage rir frequency condi ti oils.
• Si nee the degradation of a
• ti on cl ass 1 E source supplytng -power to . the .. RPS bus -can occur *as.a' re_sult of any r*andom single failure, the OPERABILITY of* the.RPS electric power monitoring assemblies is required
• when the RPS colT)ponents are required to be OPERABLE. This _results i.n the R_PS-Electric Power Monitoring Systein . OPERABJLITY being in MODES l and 2; and. in MODES *3, _ 4; and Swith anj.control rrid from a core cell -containing one .or more fue 1 .as semb 1 i es. -* *(continued) .*" .. -Revfsi on No: 3 ;.':*:*

BASES {continued) ACTIONS 1.;, --. -*

• PBAPS UNIT 3 RPS Electric Power Monitoring B 3.3.8.2 If 'one RPS electric power monitoring for an inservice power supply (MG set or alternate) is inoperable, or one RPS electric power monitoring assembly on each inservice power supply is inoperable, the OPERABLE assembly wi 11 st il 1 provide protection to the RPS components under degraded voltage or frequency conditions. the reliability and of the RPS Electric Power System is reduced, only a limited time* (12 hours) is allowed to the inoperable t6 OPERABLE status. If the inoperable assembly cannot be
• restored to OPERABLE status, the associated power supply(s) must be removed from service {Required Action A.I). This p 1 aces the RPS bus in a safe' condition. An alternate p*ower supply with OPERABLE powering monitoring.assemblies may then be used to power the RPS bus. The 72 hour Completion Time takes into account the remaining OPERABLE electric power monitoring assembly and the low probability of an event re quiring RPS e 1 ect ri c power monitoring protection occurring during this period. It allows time for plant operati-0ns personnel to take. corrective actions or to place plant in the required conditicin in an orderly manner and without 'challenging plant systems.
• Alternately, if it is not desired to remove the power supply from service (e.g., as in the case where the power supply(s) would result in a scram isolation), Condition C or D, as applicable, must be entered and its Actions taken. *
• If both power monitoring assemblies for an inservice power supply (MG set. or alternate) .are inoperable or both power
• monitoring assemblies in .each inservice power supply are the system _protective function is 1 ost. In this condition, 1 hour is allowed to restore one assembly to OPERABLE status for eacti inservi ce power supp 1 y. If one . inoperable for each inservice powef supply cannot .be restored to OPERABLE status, the associated power supply(s) *must be removed from service within 1 hour (Required Action B.l). An alternate power supply with OPERABLE assemblies may then be used to power one RPS bus . . * (continued) .*. If 3 .'3:,;_202. * ., Revision No.* 3 '* _-.

BASES ACTIONS ,._ PBAPS. UNIT' 3 .!L_l (continued), RPS Electric Power Monitoring B 3.3.8.2 The 1 Completion Time is sufficient for the plant operations personnel to take corrective actions and is acceptable because it minimizes risk while allowing time for restoration or removal from service of the electric power monitoring assemblies. Alternately, if it is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C or D, as applicable, must be entered and its Required Actions taken. lf any Required Action and associated Completion Time of Condition A or B are not met in MODE 1 or 2, the plant must be brought to a MODE in which overall plant risk is minimized. The plant shutdown is accomplished by placing the plant in MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE*4 may be made as it is also an acceptable low-risk state. The allowed Completion Time ii*reasonable, based on operating experience, to reach ihe required plant tonditions from full conditions in an brderly manner and without challeriging plant lL._l If any Required Action and Completion Time of Condition A or B.are n6t met in MODE 3, 4; or 5 with any* control rod withdrawn from a core eel l containing one or

• more fuel assemblies, the operator must immediately initiate, action to fully insert all insertable control rods in tells one or more fuel assemblies. Required . Action D.l results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not required. (continued} B 3.3-203 Revision .No. *57 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS. UN If 3 RPS Electric Power Monitoring B 3.3.8.2 SR 3.3.8.2.1 A CHANNEL FUNCTIONAL TEST is performed on each overvoltage, undervoltage, and underfrequency channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with design documents. As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is only required to be performed while the plant.is in a condition in which the loss of the RPS bus will not jeopardize steady state power operation (the design of the system is such that the power source must be removed from service to conduct the Surveillance). As such, this Surveillance is required to be performed when the unit is in MODE 4 for 24 hours and the test has not been performed within the Frequency specified in the Surveillance Frequency Control Program. This Surveillance must be performed prior to entering MODE 2 or 3 from MODE 4 if a performance is required. The 24 hours is intended to indicate an outage of sufficient duration to allow for scheduling and proper performance of the Surveillance. The Note in the Surveillance is based on guidance provided in Generic Letter 91-09 (Ref. 2). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.8.2.2 and SR 3.3.8.2.3 CHANNEL CALIBRATION is a complete check of the relay circuitry and applicable time delay relays. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted between successive calibrations consistent with the plant design documents. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.3.8.2.4 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, the logic of the system will automatically trip open the associated power monitoring assembly. Only one signal continued B 3,3-204 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS REFERENCES* -.*. -. --** .. *, *.* PBAPS UN IT 3 SR 3.3.8.2.4 (continued) RPS Electric Power Monitoring B 3.3.8.2 per power monitoring assembly is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class lE circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable. The Frequency .is controlled under the Surveillance Frequency Control Program. 1: UFSAR, Section 7.2.3.2. 2. NRC Generic Letter 91-09, "Modification of Surveillance Interval for the Electrical Protective Assemblies in Power Supplies for the Reactor Protection System." 3.. NEDC-32988-A, 2, Technical Justification to SuppQrt Risk-Informed Modification to Selected Required End States for BWR.Plants, December 2002. *.*-, .... _-,_ . . >:* ,, _.* B 3.3-205 Revision No .. 87 . I

. ' 1* I, *. . ' *. PECO . . ENERGY Peach Bottom .. Atomic.Power StatiOn IMPROVED* -TECHNICAL . * * . SPECIFICATIONS . . * * *. (UNIT #3 BASES) . : ... . . ---* .* ,;.-... -' '; .. * ,. *-.; .. -. . . . ',_ . .' . " : : . . -: . . ... -**-, . . ' . . .'-.: --.. '.* * .. _ .* ::: . -*: _*_--.-,. '. ... . '. -.. :-_. -.* *.*, .:.. .. . ..... :. .. ':.* ... *.*. * .... . * ; -* . " . . -. . . :* ... ' . . . . . . " .. . ' "* . .: . *-**'.* -. *.. . .* . . *-*' _.. *-*'* ... . . _, .. .,_' -*_ . --. . . _ . ., :J*. ! ' PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B TABLE OF CONTENTS page(s) i ................................................................................................................... Rev 28 ii ..................... ........................................................................................... Rev 106 iii .................................................................................................................... Rev 3 B 2.o SAFETY LIMITS (SLs) page(s) 2.0-1 ....*.*....*.....*.**..............*.......*.*.*.*.....*.........**..*..*......*..........*....*.*....*.....* Rev 98 2.0-2 *.*.****...* ; ....*.................**.***..*.*.*....**.**..*.**...*................*...*..*....*.*....*.*.. Rev 130 2.0-3 ............................................................................................................ Rev 130 2.0-4 ............................................................................................................. Rev 48 2.0-5 ....*..*..*.*.....*.....*...*.........*...**....*.....*....*..*...*.**.....*....*..*.*......*..*......*.....* Rev 76 2.0-6 ....*..*.......*..*.......*.........*.... : .*...**.......*.....*...*.*................. ; *...*..**........... Rev 130 .2.0-7 ....*.***..*.*....*..*.....**...*.*.*................*.........*........*..*......**.. : ..**.*.**.*....*.*.... Rev 76.* 2.0-8 .... , .......................... ; .......... , .................................................... ............. Rev 58 2.0-9 ..*.**.*.....*....*..*..**.*.....**..*...*......*..........*...*... : **.....*.*.....**....*......*.*...***..*... Rev 76 2.0-10 .***.*..*..*.......*...*........* ; *....*..*... , *....*.*.....**..***...... , .*......*.....*.*.**.*..***.**... Rev 76 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY page(sj 3.0-1 *....*.*....*..*....*.*...*..*...*....*........*.*.*.. : ......**..**.*...*.......*.**......*.*......*.....*. Rev 100 3.0-5 .............*..........*.*.......**.......*...*.*...*.**..*........***.*..*.*..*..**.....*.*.**.*..*.*.**... Rev 53 3.0-Sa ............................................................................................................ Rev.53

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*, PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.1 REACTIVITY CONTROL SYSTEMS (continued)

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Rev 119 3.2-13 ......................................................................................................... Rev 119 ii. Revision No. 137 PBAPS UNIT 3 m LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.3 INSTRUMENTATION page(s) 3.3-1 .....**...*....*..***....*..*.*.****..........*.**..*.*..*..*..*..*.*.**...**..**.*.***.**..**.*......**.**......** 119 *-.* -.-* . 3.3-5 -*6 (inclusive) .....*..**....*...*.***.*..*..* * ***.***...*......*.***..*....*...*******.***.**...*... Rev 17 3.3-7 ...*....*....*..*......*.*.*.*........*......*.....*.......*...*.*......***..**........*....*....*.*....*.. 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PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.3 INSTRUMENTATION (continued) ... page(s) ,* ..

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• 3.3-92f *. ,:;'. ........ ,. .******. : ** ** ... : ..*. **. :: *...*. :.: .*....*....*. , .* .... .-: ...... .u ******* Rev 58 3.3-9,2g : .... ;.,., ....... : ...... ;; . .-; ... .-:;* ... ..... ; .** : .................. :.: .................... .-.Rev 119 3.3-92h .......... : ......... : ..... : ......... ; .......... ;,*; .. * ........ , ... : .............. * ....... ;.: ................. Rev .. 87 -3.3-92i .... : ** .......... : ... ... :: .............. :: ... ...... : ............................ ;; ... ............ 119 ** .. ; .... .......... .-................. : ... ....... ; ..... , ... : .................. : .. :;;, .. ..... ; ....... Rev 87
• 3.3-93 -98 ... ;.;* .......... ,, ..... ;;'. ........ ....................... ; ..... : ........... :: .... Rev3 3.3-99 ... ;: ...... :: ................. .. : ....... .* *.: .......... : **. : ... ......... : ... .-* .-... -. ................. Rev *23 * *. 3.3-100 ...... : .. :: ... : .. : ..... ".: .... : ...... : ...... , .... : ... : .... .-............. ; .... : ..... : ... .' *. ; ............... Rev 58 . 3.3-101 *; ... .. .......... : ........... : ............. u.:., .. ; .................. .... ...... ..... ;, ........ *. Rev 58 3.3-102 ...... ;-................... .... ........... ; .. * .. ;*: ... : ...................... * ..... : ... : ............ ;*,;; .... Rev 58* 3:3-103*L.: .... : *. :.: ..... : ..... :.-.. : .... : ...*..* :.: *. : .. ...... : ........... : ....... : .... ..... ... ;.; .. Rev 58 -.* . . 3.3-104 ...... ... .. .. ::* .. ... : ........... ........ .............. : ............................. Rev 58 . 3.3-105 ..... : .. .. ;* ...... ............. ,: .............. .................. ;; ........... .................... Rev*58 3.3-106 .. .... :.: ..... : .......... :: ...... : .. ;;; .. .. : ..... ; .. ; .... ............... :: ...... .. ; ............... ; .. : Rev3 3.3-107 ; ..... : ............ : .... ........ -... ........................... ;;; ... ,.: ..... :.: .. :'."".: ............ Rev 58. '3.3-108 " 111 (inclusive) ....... .. ............................. , ........ , ...... : ...... '. ..... ...... Rev 3 . -: . . ... *iv Revision No: 1_37 PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTI NG B 3.3
• INSTRUMENTATION (continued) p*age(s) 3.3-112 ....****....* : ..*.*.******..*.**. ................... **.**..***. : *...**.**...****..** '.******************** Rev 79 3.3-113 -124 (inclusive) ....*..*.**..*.*.*.*..*.*.**..***...*.*..*..**...*..*..*.....*...**...*...*.*.* Rev 3 PBAPS UNIT 3 * ----,-*, ... -3.3-125 ..*..*..*...*. : ***..*..* * ................................................................................. Rev 59 3.3-126 ............................................................. ........................................... Rev 84 3.3-127 .................................................. : ......................................................... Rev 3 3.3-128 .......................................................................................................... Rev 87 3.3-129 ......................................................................................................... Rev 87 3.3-130 .................. ; ........................................................................... : .*....*... Rev 87 3.3-131 -138 ..***..***...*.*..*..****..*. , ..*..*.*...*.......*. Rev 3 3.3-139 *..*..*.***....*..*...*... : .**.*...**.**..**..*. , ***..* * .................................................. Rev 87 . 3.3-140 *.**...*.**...*.......**....**.*....**.*. : .*.....*....*..*.*.....*** , *.*..*.*.......*....*.**.*.*.*.*.*... Rev 87 3.3-141 ...* ' ....**...**..........*...**......**.*..**.*.*.*.**.**.**....***.*......*.**.*...* : ...*..*.*.*.*.....*. Rev 87 3.3-142 ..**.****.*.***...*......**.*..*....* : .*..*..*...*..*.****.....* : *.*...**.*.**.*...*. ; ..****.*.*.*..*.. Rev.119
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• __ ;.' ' ' Revision No. 137

I: PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.3 INSTRUMENTATION (continued) page(s) 3.3-185 .*.*..**.*......**...***...**..........*..**.***..**.***....*.***.**.*. : .****.*..*.*.......*.*...**...... Rev 87 3.3-186 ......................................................................................................... Rev 87 3.3-187* ........................................................................................................... Rev 5 3.3-188 *.*.*. : .................................................................. : ............................... Rev 88 3.3-189 ... : ..................................................................................................... Rev 88 3.3-190 ......................................................................................................... Rev 88 3.3-191 -194 (inclusive) .............................................................. ; *.**.*.*.*...... Rev 5 3.3-195 ......................................................................................................... Rev 78 3.3-196 ................................................................ .......................................... Rev 5 3.3-197 .................................................................................. : .....*...*..*...*..... Rev 87 3.3-198 ............................................ ............................................................ Rev 87 3.3-199 ........................................................................................................... Rev 3 3.3-200 ........................................................................................................... Rev*3

• 3.3-201 .......**.*...*...... : ...*..*.*..*.....*........*...**..*.**.*.**..*..*..*.***..*.*.....** .' *.**.*.*.***.*** Rev 3 3.3-202 ....................................................................................... , .**. : .*......*.*.*.. Rev*3 3.3-203 .............................. ;; ............ ............................................................. Rev 67 . 3.3-204 .......................................................................................................... Rev 87 . . 3.3-205 ... * ............. ; ........................................................................................ Rev. 87 B 3.4 REACTOR COOLANT SYSTEM (RCS) page(s) * -*-. .. *. PBAPS UN.IT 3*. 3.4-1 ................................... ; ........................................................... : ..****..*.. Rev 1.18. 3.4-2 ........................................................................................................... Rev 118 3.4-3 ..................... ; .*. , ........................................................................ : ........ Rev.125 3.4*4* ............................................................................................ * ................. Rev 51 . 3.4-5 ....................................... ; .*..*... : ................................ , ......... : ................ Rev 125 3.4-6 ...................... ; ......................... ....................... * ..................................... Rev 51 . 3.4-7*.; ................................................. * ....................... .' .............. : ................... Rev*12s . 3.4-8 ...................................... .....****.. ; .................................................. : .** Rev 125
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• vi Revisio.n No. 137 I . I

,* I. 'I* I 1. " I 1; . .:**-_ !i* l.i-* PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued) * -page(s) 3.4-37 ............................................................................................ ............ Rev 128 3.4-37a ......................................................... ; ... : ............................ * .............. Rev 129*

• 3.4-37b ........................ ............................ ; .............. ............... ................... Rev 128 3.4-39 ................................. : ....................................................................... Rev 128 3.4-42 ................................................................................. ....................... Rev 129 3.4-42a .*** *.***.****.* ................................................................... .-.*..*.*..*.*.**** _Rev 128 3.4-43 *.*************************.*.*******.*. : .*********.*****..*.**.********.**.***********.***************** Rev 102 3.4-:44 *****.* * *.*.*.***.**.****.*.**.**.******** , Rev 102 3.4-45 ........................... ....... ; ................................................ .-.................... Rev 102 3.4-46 .**..*..*****.*.***.*.... , .*..*.*. ; .*.*..*.*.**.*.*.***.**.*.* ; ***.*.**.*.*.*.*.*.*.*.*.*.**.*..*.*.**..* Rev 102 * . 3.4-47 *.* ...................................................... , ............................................... Rev 102 3.4*48 ............................................... : .*.**.**.*****.**.*.*.***.***.**.***.*.**. .............. Rev 102 .* _ ******.***.*** .' ........................................................................................ Rev 102 3.4.,50 ..... ********.*.*** -...................................... .............................................. Rev 102 3.4-51 .**** ; .................................................. ; .**.****.*.*.***...**.*****..*.**.**.*..**..*..** Rev 102 3.4-52 ............................................................................................................ Rev 50 3.4-53 ......................................................................................................... Rev 119 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE . ISOLATION COOLING (RCIC) SYSTEM page(s) * . .,. PBAPS' UNIT 3 3.5-3 *********.**.**.** , .**** ; ***************.*.*.****.****.****.*.**.********.*.*.*****.****.*..****.********** Rev 110 3.5-4 ********..*****.*****.*..*.**.*.*****.***.* .-*.**.*.*. : ..................................................... Rev 127 3.5-5 ......................................... .' .......................................... ; ...................... Rev 128 3.S-:6 ............ : ................ ........... : ....... : .............. .-................... .-.................... _Rev 112 3.5-6a **.**.* : ***.. .-........................................................................................ * ....*** Rev -96 3.5-7 ....................................... : ..................................................................... Rev 89 -3.5-8 ........................... .-.*.* .................................. .' *.*.****.*..*.*..*..***.*......*.*.*. Rev 101 3.5-9 .*...**** : ............................................... , .*..**.*.*...*.*.*.**.*..* **.....**.*..***.**..* Rev 128 -3.5-10 ................................. , ....................................................................... Rev 129 3.5-1oa* .......... ; ......................... , .. -.-............................................................... Rev 128 3.5-11 ........................................................................................................... Rev 87 -. .-3.5-12 * .-: ............ : **** :.-****..*.** ................................................ Rev 133
• 3,5.13 ................................ .-**********.*.**. .......................................................... Rev 99 3.5-14 ................................... _ ...................................................................... Rev 132 *3.5-15 .*****.*.***. .-.: ****..*******.***.**** .-**.*.*******.***.*********.*.*********.*.****.*..***************.*** Rev 87 3.5-16 *.***.*************.****.*****.*.*.**************.** : ***.**.**********.*********.****.***.***************** Rev 87 3.5-17 .................................. :;.: ................................................................... Rev 101 3.5-18 ................ * ......................................................................................... Rev 135 3.5-19 .................. _ ......................................................................................... Rev 96 * *3;5-19a ............ ; ............................................................................... : ............ Rev 96 3.5-19b_ ******* , *.*.********.**.**..*************.********** , **.*********.*********.*.*******..*.****.*******.*** Rev 96 3.5-22 ************.*****.**.**************.*. * **.*.****.********.*.*******. ; .................................... Rev 128 3.5-23 ***..**.**** : **.**.**.*******.**.***.******. * **..****.***..****.*****.*..******.*.***.*...******.*.****.**** Rev 58 ........... -................. **** .' ...................... ................................................ Rev 110 * . ................................ ; ................... * .................... ......... ; ... ........... ; ...... Rev 128 3.5-26 .***...** .*.*.*****.******* : ............................................................................... Rev 67 3.5-27 .; ** : ******.**.****.*****.************.**.***.**.****.*.*.*****.*.****.*.******.. -. .-.*.***.*.*..***.*.*... Rev 129 * -3.5-27a ................................................................................................... ; ... Rev 128
• 3.5-28 * **.* *... :.' ****.*******************.* ;.-.********************** : ****.*..********.. .-.*** : ****..*..**.*.*..* Rev 132 **. :: *.**..** *..******** ********.*.****.*** : ................... ; ** * *****..*.**.**.****.**.*.*..***.*..*.**. Rev 87.*. *3.5-30 .*.**.*** *.** *. : ..**..*..**..*...... * .* ; .*.**...**.*..*..*..***.*.*..*.*. *:.; .............. *********...*. Rev 67 vii Revision No. 137 PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.6 CONTAINMENT SYSTEMS page(s) *-* .**-.-* . * . .--.. PBAPS UNIT3 3.6-1 .............*..................*...*......... , .............................................................. Rev 27 3.6-2 ........................................................................................................... Rev 119 3.6-3 ............................................................................................................. Rev 67 3.6-4 ............................................................................................................. Rev 87 3.6-5 ........................................................................................................... Rev 119 3.6-7 ........................................................................................................... Rev 119 3.6-11 ............................................................................................................. Rev 6 3.6-12 ...................... * ..................................................................................... Rev 87 3.6-13 ............ ............................................................................................ Rev 119 3.6-16 ........................................................................................................... Rev 91 3.6-17 -18 (inclusive) ................................................................................... Rev 2 3.6-20 ........................................................................................................... Rev 58 3;6-21 ........................................................................................................... Rev 58 3.6-22 .: ....*. ............................... : .................................................................. Rev 58 3.6-23 ............. * .............................................................. : ............................. Rev 119 3.6-23a ........... , ........................................................................................... Rev 119 3.6-24 ................................. ; ............... : ......................................................... Rev 91 3.6-25 ............ ,; .............. : .............................................................................. Rev 87 3.6-26 ..***.*. ; *..**..*........*...*..*..*............*....**.....**.**..*............*.....**.*.***.*..**.....*. Rev 87 3.6-27 **.**........*.....*..........*.....*.. ; .*...... ; .*...**.....*..**..*...... .-.**..*.....*.*..**.*......*..*. Rev 87 .. 3.6-28 ....................... ; ................................................................. * .................. *Rev 87 3.6-29 ........................................ ; ..................................................... * ........... Rev 119
• 3.6-30 ................. : ......................... : ..................... * ........................................ Rev 119 3.6-31 **. , ... -.................................. ; ................................................................. Rev 20 *. .... ; ........ : .. :* ......... : ............. : ......... ** ..... .-....................... * ............................ Rev 11*9 3.6-35 ......*.. : ... * *.** : .. : ............ : ... : ........................... , .................................. : ...... Rev 91 _ 3.6-J8 ......... : ..... ' ... * ... , ...... : ... ;.; .......... ; ........ : ..... : .*****. : ..* : ................................... Rev 67
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• 3.6-41 : .......... ** .' ............. : .................................. , ........... : ........ _ ... _ ... ._ *. , ............ Rev 87 3.6-43-.......*.*. .-*** ,.:.; *.*..**......*. , ** .-*...*.*.*.....*..*.*.. ;;;* ** -.**.*....*.*. ,*., ...*..*....* : ..*....****.. Rev 44 3.6-45 .......... ;;-;.": .... : ... : ............ -................... : .... : *... ;;;-; *..*.*.*...** , ...................... ; **. Rev 67* * : ....... ... -.*:: .**.* : ...... ..... ;: ......... ... -. ................ ;.: ........... -............. : .............. Rev-87--3.6-47: .............. : *.*.. .' .... ; ....... ; ....... * *. *; ........... : ............ ; ........................ * ........... ; ... Rev-87 -3.6-49 *.. .-*.. .' ................. .-.: ......... ' ......... : .. ;; ......... .. ........................ : .. -. .............. Rev* 1*1* 3.6.,50 ;*;,.; *.. -.: .. .. : ...... :::-.-.--'. .. -... ' .** ** : .*. .-;; ........... : ................ : ................................ Rev 17 .. :: : : :::::i: ;:: :*::::::-:::::::: * -: ........ : ... , .. *:*****: ..... : ... ; ... .... ; ..... : ...... , ... ............... , .... :; .... * ......... -.* ...... Rev 87 _ 3.6-56 ............. : ..** ,_ ......... ; .. ;, ... : ............... : ..****..* : ............. -. ....... : ........ ,; ......... _ .. Rev 119
• 3.6-57 ....... :-..................... ; ...... : *. ; *..** : ........... : ............... ; ........... .-................... Rev .128 . .** : -3.6-59h .* .. : .. : ....* -.-: ........ *.-.. .-..*. -: .......................... : ... : ...* : .... * .... : ...... .-;-. ....... .-:* .......... Rev 128 * .-3.6-SO *** ;;;* .. j ** ." *** ::: ......... : .. ..... **** ". *** : .... ,., .. : .... :: ** ......... : ** : ............... : ...... :: Rev 119 viii , Revision No. 137 I I !' PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.6 CONTAINMENT SYSTEMS (continued) page(s) 3.6-61 ***.*.*.....*.**..*...*...**.. , ..****...*.....*****...*..*******.*.*..**...*.*...***.......*.*.*****..*.. Rev 128 3.6-62 *..*..*.......*.........*.**....**........ ; .*....*..*.*..*.....*.*.*...*..****..*.*.......*....*****....*.. Rev 67 3.6-63 .......................................................................................................... Rev 132 3.6-63a ........................................ ; .............................................................. Rev 129 3.6-63b ....... ............................................................................................... Rev 128 3.6-63c ....................................................................................................... Rev 128 3.6-63d ....................................................................................................... Rev 128 3.6-63e ....................................................................................................... Rev 128 3.6-63f ........................................................................................................ Rev 132 3.6-639 .*.**.*. ; ............................. : ................................................................. Rev 129 ....................................... : ....... .'.; ............................... .' ..................... Rev 128 3.6-64 ....... : ..................................................................................................... Rev 81 3.6-70 ...................... ; ...***....****..*.** , **.....*.*.****.***.....*...**..*.*...*.... ; ...*....**...*...*.. *Rev 81 3.6-72 .*.*** : .................. ; ....................................................................... ; .*....*..*. Rev 87 . . 3.6-73 ............................. ................. .................................. , ......................... Rev 76 3.6-74 .*.**. : .................................................................................................... Rev 76 3.6-75 *;., ***. * .................................................................................................... Rev 76 3.6-76 ............. , ................ , .......................... ;* ................. : .................... : ........ Rev 122 3.6-77 ................................................. *. : ........................................................ Rev 97 3.6-78 .. ; .. : ............................. : ............................................ : ***.*.**.**.*....*...*..... Rev 76 3.6-79 .... : .. ... ;* .......... ; .......................... ;* ........................................................ Rev 76 3.6-81 ..... , ....*.*.**...*.*. : ....**..*...*...*.** .***. : .**.*.**.*.*.*.*.*..***.**.*.*. ; .**.*..*.*.*......**.*... Rev 58 3.6'."82 ................ *.......*.***.....**...*. : *....*.*.**.*.*. : *...*...*..***..*...*.*.*.*..*...**.**....*.*.*. Rev 76 3.6-83 ....... _. *...*.**..*.**...*..*.**.***...**...*..*.*.**...*. , ................................ : ....*..*.....*. Rev 87 3.6-84 ..................... ;.* ............... ; .** , ***....*........... : ..... ;: ...*.*.***..* ; ....................... Rev*87
• 3.6-87 *.**. ;.; **.*....*..*... : ..***.*.**....**** : *.*.** : *.**...**.***.*.....* ;* .......****.*.....***...**......**. Rev 76 3.6-88 ...*.*..*. : .* ... ;* ***.....*................**. ; ...... ; .*...*...**.*....**......*. ,; *.* : .**........**......*. Rev 76 3.6-89 .*.* *...** ; **.**.*. .*....**..*.*** : ..**.*.*..** ......................................................... Rev 87 3.6-90 **** ,:*; ...... : .*... : *.*. ; ..**.**.***.*.* : ..**. *.* .** ,.: *.*.*....***.***...***... *.;* ......... : .*.*.....**......*. Rev 87 B 3;7 PLANT SYSTEMS , .*.' . . . . ' ' -. -' . . *. ' . -. page(s) . . ! :;:::: ::::::: ::: :::: '.:::::::: :::: :::£ ::: :::::: ::::: ::::::::: :::'.: :: :::E:: ::: : :: :: :::::::: :: . 1 i: **.-,' 3.7-.4 *. , .**.**. , ..... : .............. ::., *..***. : ** _, ...**.* ;.; .** :* ................ ; ..... : .**. :: ..... :: ............... Rev. 1.19 3_.7-5 ....... _.:; *.*. .. ,.;*: ...*..*.** : .. ;.'. ...................... : .. :_. ...........**.* Rev 119 3:7-8 .*.. ;: **... : ..*.*.**. :.; .......................... : ................... ." .***.. ; .. ; *.*. :*: .... :; ............. :*Rev 109 -*-, 3.7-9 ....... .'.;;; ............ : *..* :: **** ..... ; ................ * .**.. ; *........*. .-... *.* **.* * ...... ............. :*.:.: Rev,*109** 3.1-.10 ..* ..... ,*., .*....*.* : ...... ;'.: ..... : .*. ; *.* ;,.;*.'. ......** : .................. .* '.; .. : .... ;: .*.*.*.*** ; .... Rev .87 *.* -. . \ --. ' ::: ::::: :::: ::::::::*:::::: ::: ::::: ::::::::::: :::: ::::: ::: ::::::::: :::::,:::::::::;:::::::::: ::: . 3. 7-13 *.*... ; ...**...*..*..*. '; ****.*... .................... ;.; .* .. .. .Rev*1 PBAPS UNIT3 ix Revision No. 137

! PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.7 PLANT SYSTEMS (continued) . page(s)

• 3._7-14 *....*.**......*..*.*.*.****.*.*.**.. ; *.....*.**.**** ........................... _. .*.......**..**..*.***..... Rev 87. 3.7-15 *.....*.*........*....*.....*..**...*.*..*...**...*....**.*.......*.....**...**..*.....*..*.*.*..*....... Rev 114 3.7-16 .**.*...*......* : *.*....* ; .*...*.*.......**...*..*..**.*.....*.*..*..*..**....**.*.........*....*..**..*. Rev 114 3.7-16a ... _ ......................................................... ; *........**............* ; ..*......*.....*. Rev 114 3.7-16b .**.*.........*....*..**.*..*.*...*.....*..**..*. : *... ; **............****.* _ *.........*...*.....*....*.* Rev 123 3.7-17 .*** * *... , *......**..*....**.*.*.....*.*. ; ................................................................. Rev 114 3.7-18 *..**...* : ......**.*.***......*.....*....*.*.**. ; *.**.*........****...***....*....*...*..**..*.. : ......... Rev 114 3.7-19 ..***.****....****.* * .*..*.*.*.....*.*.*.....***.*..*..*....*....**.....*** .-..* ...........*..*. : *..*....*.. Rev 69 3.7-20 .***.....***....*......*............*........*.....*.*........***...........*...*...**..........*.....*.... Rev 87 3.7.;20a .***...*.....*......*...*.....*......*.**.**..*.*.**.. ; **...**..**.*....**.***.*..*.*....****..*****.*. Rev 1_14 3.7-21 .**..*... *'************************************************************************************************Rev 123* 3.7-23 ****.*.***.. -...**.*...**....*.......*..*..*.*.*.*.****.*.**....*.....*..**.****..*...*.....*.*..*.*.*.*.**. Rev *67 3.7-24 *..*..............*...*...**...*....... : ..*.**..*.*.**.*.**....*........***..* *; ........*..*..*....*.*..*.*. Rev 87 3.7-25 .*..*.*.***...*.**.*.*..*.****.*...*.*......**....*...**.*..........**.****.**.**......*..*.....*...**.*. Rev 119 3.7-26 '. *..*..**.*... ; ......................... ; ...**.*.. ;_. **.*.**...........*****..* ; .*...........*.*...***..*. Rev 119 3.7-27 .****..*......*.*....*.*..**.....*......*..*.....**...*.**......***...*****.*..** * ........*..*..........*. Rev 119 3.7-28 .***.*.*.*....*.*...*..*..** .-.... ..*.*.*...*....... .-.*...... _ *...**..***.*..*..**..*.*.... , .*........*..* Rev 111 3.7-29 .****..*........*..**.**.........*.*..* .' ....***....**.*..*.......*..*.**.......*............*....*...*....* Rev 76 3.7-30 .****..*.*....*.***.**..*.*.**.*.*........*.**..*.*.***.****..*...*.*...***.*.***......*.**...*..*...*.*... Rev 87 B 3.8 ELECTRICAL POWER SYSTEMS p*age(s). 3.8-1 .*.**.*.*...*.*.*.**.*.*..*....*.** ; *..* *..*.*...*.*.***.**....***...*..***..*...*.........*.......*..*.*..* Rev 83 ** 3.8-2 ................................................................................. ::* ....*...*.*..*...**.......* Rev 90 3.8-2a .* *.: ..*.*..... : .**...*..*..**.*.*.*.*.*..*....****..****.....*.***.*.*. .' **...**.....*...*..*.......*.*....* Rev 90 3.8-3 ..**.*..*..***.. ;_;, **..... : *.**.***.*...*.*..*.*...*.*.*...*.....***...**..*...*...*..*... '. ..*. * ....*...*.** Rev 119 3.8-5 .*.****... , .....*.* : .*.... : .. ; ..*.....*......*..**.*......*...** .-.***...*.... : .***.............*... ......*..* Rev 74 .3.8-6 .....*. * ...*.*....*....*.** ; **.*.*.............**...*** ; **.............*.***........*...*....*.....*.*.*...... Rev 53 3.8-7 ....................................... * ... : *.*.** * .*.*...**..*.**...*.*.*.***..*...*..*.***..****..*.*** ..*.*.** Rev 5 .* --3.8-8 ..... .......... ..................... ;.* ... ..... : ..... ...................................................... Rev -86. . -*-----** PBAP$ UNIT 3 * .. -,, .. 3.8-9 .*. ; ..... .-.: ... .-.-*.**.*.**.*..**.*.*.*...*..*.***.* .-*.**...**...*.. ..*..**..........*. : ....*.*.*.*.*.*..*.*. Rev 86.
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• 3.8-11 .. :.-.***...*...*..*.......*..*..*.*...*.*..**..*. -.: *..*..*..*.....*...*.....*.....*.*.. : .... * ..*....*****... Rev.61 *3.8-12 ...*....**.*.. * ..*....*.... _ ** , ...*.*.*...*..**..*.*.*...*..*.*...*** : ...*..... : *...*.*....*...*...*.....**..*. Rev 1 * .....*. ; .*.*.........*..*..**.*...*.........*....**** ; . ." .....*....**.*****.................... .-: ..*.**...*. Rev 67 3.8-18 .*.*..** : *.****.* : ......*..**.*....*.*....*.***.....*.*...*..**...*.*..***.*.**..*...*.*.....*......*...... Rev 72 3.8-19 ...*.*.*.*.*...*..*..*.....***.... : *. .-*.*.*.**. : **.* .........*.......***.. :*.: **.....*.** ; ................. Rev 87 3.8-20 *..*...*.*.*....*..*..*....**....*.*.*.*..*...* ; *.*. .-: *. , .....***......***....**.......*....*...*..***. : .*. Rev 87 3.8-2t *.*.*..*.*.*....** , *....****.*...*.*.*.*.*.*.*****..*.*.***..****.**.*..***...*...*.*.*... .-.*..*.*..*.*.**. Rev 87 3.8-22 .......*.*.*...*.....* , .. : .**..*.*.*.*.*.*.*.**.*.*****.**...**.*..*.*...**.*.......*.*.....*....*..*.....* Rev -87 3.8-23 ********.***..****.*.****...**.*.*.*****.****.**** ; .*.****.*.*******.* ; *******.* : ..**.*****. ; *..*********** Rev 87 3.8-24 *..***...*.......... : .***...*.**.......*.********.*.*.*.**....**.*.**..***.*.***..***.*..**..*..*...*.... Rev 137 3.8-25 *..*.*.*.*.****...*****.**.** ; .*.**..*..**..*.*...*.*....**.........*.***.....**....*.......**..*.*.*....*.*. Rev 1 . . 3.8-26 *.**.*.*.*.*..*.*.....*....***.*..*.*........***....*.**.*****......*..****..**......**.....*.*.*...*..*..* Rev 87 3.8.,27 ;.; ***...*.*. : ..*...*.*.*..*****.**..*...***..*.***** , *.....*.**.**.*.*.**.*.**..**.*.****...*......*..**** Rev 87 -3.8-27a ............................................................... : ..*.*..*.....*.....**...*.*.*..*.....*.... Rev 58 3.8;.28 ....***. ;; .*...*..*...****..**.*.... : ...* ; ....**..***.*.*.....****..... -..*...**....*.*.......*..*.*.*.. * ..*. Rev 87 . 3.8-29 ._._ ****.** : .*..............* .' **.... : .** .' ...*.... ; ..*.*.*.*....*.****..*...... : ***.....*.......*..* ; *.. : .*.*. Rev 72 3.8-30 ..... ** :.: .*..*..*..*****.....*. .*......**..*.*****...*......***.*..*.......*.*..*.*...*.....*.*.*..*.** Rev *97 * *3.8-31 .*** *.. ' .*......*...*....*......*.....*..*.*.*. .-.**.*......*. : **...* ; *....**. '. ....* : *.. .-...*..*. .-.*.. .-.. ; Rev.58 . . 3.8-32 .** -**.. ; .. ; *...**.*...*..**..* ; ................... : .*.. : *..*.*.*.....*...*.*.....*..*.*.. , ***......*.*..... *Rev 87 * *.. . --Revision No. 137

,*": : .. *.-, .. I . PBAPS UNIT 3 -NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.8 ELECTRICAL POWER SYSTEMS (continued) page(s) 3.8-33 ...**.....**.. ; .*.*...*.*.*..*....*..*....*..... ; .*...******.......*..*.... :, ***...*.***..*.****..*. ; ....*. Rev 87 3.8-34 *...*......**......*...*..*..****.**...*.*...........*......***.**...........***...*..*.*...*..*..**..*..*. Rev 87

• 3.8-35 ..*......* : .*...*..***...*....*.*..*...*.*.*......*..*.......**..*....*..**...*.*..*. ; ***......*..*...**. Rev 115 3.8-36 .*.*.....*....**.....*.*... ; .**..* * ........................................................................ Rev 87 3.8-37 ...................................................................................................... : *..* Rev 72 3.8-38 ...**....***...**.*..*.........*..*.*...***...*.*....*..*....**..*..*........*....*...*..**.*.**.***....*.. Rev 87 3.8-39 .*.**********...*.*.*......*.*.*..*......*.*..........*.*..*..**..*.**............*.*.....*.*.****...**.**. Rev 95 .3.8-42 ...........**.*.*..*..*.*.......*..*....*..................**......*..............*..*..........**......**. Rev 58 3.8-46 -47 (inclusive) ...*.*...*.*...*.........**..*.*...*..*....*...*..*........**..*.*......*..*.... Rev 18 3.8-48 ...*...*....**.....*...*......*.....*.*.*.*.....**...*..*...*...............*...**.**.*...*.* ; ........*** Rev 105 3.8-49 .........*.......*.*...*.*.*.....**......*.*.....*....*.......*..*..*.....*...*..*.. : ..**...*..*.**...... Rev 124 3.8-51 ...*.....**..*....*..........*....**.*.....*. : ....**..........**.*.....*. : ....*..**.*...*......**.*...... Rev.136 3.8-53 ...........****.*..*..*............*...................*...*..*..*...*.*...*......*..*........*...*.....* Rev 136 3.8-54 ..*...*.*..**....*..***.***.*.*.*...*.***.*.*....*.***....*.*..****..*.*.*..**.*..********..**.** ; *..*..*.. Rev 87
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• 3.B-80 ..**.....**..*.*...*..*....*.......*..*.*...*.*....*..**...*.......*..*.*.*..*.....*..*..*.*..*.*.......... Rev 87 3.8-89 *.***..*****.**.***.*****...**..**..*..*.*.*.*....*.**.**...**.******...*.*...*.**..*..*.*..*.*.**...*..... Rev 86 . 3.8-90 ...*.......**.**.**... .' *..*... .' ..*...*.*....**.........*....*..*.****...*.*.*...*..*.. * .*.*.*..***.. , ..**...* Rev 86 . 3.8-91 ..**.*...**..*.*.*.*..*....*..*...***.*.*.*. .*.*..** : .....****..*......*..........*..**.*.*...*.......*..* Rev 86 3.8-92 .* ; .**... : ..................... , ...........*****..*..**.*.*..*......*..*...... : ..**.*......*...*....*..*.*. Rev 87 __
• 3.8-97 ..* , .......**...***...*...*......**..*..*.*...* : ....**.*..*....*.......*.* , ..*. : *...*......*.*.*.**....**... Rev 87 83.9 .REFUELING OPERATIONS page(s). -: *,, PBAPS UNIT 3" ....*.. ... .. : ....* : ...*.*.*.*..*.. : .*....*. ..* : .*.**.*..*.*..*.* .*.* ..*.*.*...* ; .*.**.*. .-.*.....**.... Rev 29 . ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: 3.9.-7 .**.*...*. _ .*....*. , ..** * ...*..*.*..*.......*..***.........*...*.*..... ;, .......................... :Rev 87 3.9-8 .*.**.*... ; ****.*.*.*..** ; ... .' ***. **..*.. : .*.......... ..... ; .*.. Rev 17-3.9-9 .......................................... _ ....*.* : .........*...*. _ *.*..* : **.*....*.. : ........................ . .'Rev 87. , 3.9-10 *.**.**..***.***.*....*.* ****.**.*.**..*.*..**... : .**.**.*..*.*.*.**.....*.*....**..*.*..*.*.***.......... Rev .1*1* -* . 3.9-14 -....................................... -....*.... * .......*.*....*...* -.................. : * .-................... Rev 17 .. ** .. . 3.9-15 ',.: .....*...*.*...*..*..*...*** .-.' .****.**.. ;.; *.....**..*.*.*...**.**.*.*....**.**..*..*.*. ; ....*...*.*.*.. Rev 87 3.9-17 .***.*.*.**.**.*.***.******* .-*.*.....**.***. *...*..*..*..*.*.***...******* : *******..***.*..**.... : .. : ***** _Rev 75*
• 3.9-19 ...*.* : .. : .............................................................. : ............................... : *. Rev,.87 3.9-21 *.***....****.*.*..*........ *: .******..**...*.. ; ... ; .*..**.*.*......*.. * *.*.*..*.* : *.......*.......*..... * .. Rev 128 * .3;9.:.23 *..**...*.** .'.: .***....* : ................. : ************.*.*......*......*...*.*.**..** :* ..*.*.*.*....***** Rev 128 -.*. 3'.9-23a :* ................... :: .* _ ** ;: ..*.. ; .. ; *. , .. : .*.*.*.**.*....*.. .' *. : .................... , .*. ; .............. Rev-129* .. * .-3._9-23b .**. _ **** : ...*.. ..... ; ..**** : ..* ;_ ** , *.*.......*.*....*.....**. _ *.*.*... : .*.. *: ....... : **..*.***...... Rev 129* _ .......................... : *.. : .*.******.. :.:;* .*.. .-: **..*.*.*.*.*..* .-, *... '. ................................. Rev *_;. *
• 3.9-27 * ***..*......**. : .... *.***..*.* : **.*.***.***...*....* .-................................ : ...**.*. : ........ Rev 128 ** 3:*9-28 ......................... :* ..** .-... ; ****** ;: .***.*. .**..*.*.*....*.*** : ...... : ........................... :.Rev 129 :." ... 3.9-29 ......*.......... ............ :.: .................. :; ...................... *: ..... -.* ..*...*..... ;* ....*........ -Rev_128 xi Revision No. 137 PBAPS UNIT 3 -LICENSE NO. DPR 56 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING B 3.10 SPECIAL OPERATIONS page(s) 3.10-1 ...*.......***........*.*.*..*.....*...**...*..*.........**.*...***.*..*.*.......*.................*....* Rev 131 3.10-2 .....*....***...*..*..*...*.......*...**................***.*....***.*....**....*.*......*......*...****.* Rev 131 3.10-2a *.......***...*.....*******.*...*.........*.........*.**..*..****..*...**......... .-*.**......*......*.. Rev 131 3.10-3 ..... , .*..**....*.**.....*..*.*.............*..*...........**.****..**..**...**...........*....*......... Rev 131 3.10-4 .*..*..*..**..*.*.*.*.*...****..*.*...*..****...........*..*..*...*......*.........*.*................... Rev 131 3.10-5 ...........*......*.*....*........*...........*.........**.*...**........*.*..*..*.*.*.*...........*....*.* Rev 17 3.10-8 .*..*.....**..*.....*..*.*......*.*..**..*.*...*............*.***......................*.......*.......**.. Rev 87 3.10-9 .*..*......*................*.....*..**.*..**.*..........*..* .-.**......................*..*....*...*....... Rev 87 3.10-13 ..*....**..*....*...*....**......*..*.**.*....*.*........*..*........*......*..............*....... * .....* Rev 87 3.10-18 ....**.....**......*..*..*.....*..*..*..*.............*..*.***...*.*...**................*....*.*......** Rev 87 3.10-22 .**....*.*..*............*.*...*.....*.....*.............*.**...........................*................ Rev 87 3.10-26 .*.....**..*.*.*......*....*..**..*..*.....*.....*....*..*..**.............*............................. Rev 87 3.10-30 **..*.**.*.*...*...*.......*.*.*.*...*..*.*..*....*..****..**...**.................*...*...*..*.*.*.....* Rev 73 3.10-31 ..*..*..******..********.....*..*..*..**.*..*.....*...**..*...**..*...**.*........*........*.*.*........ Rev 17 3.10-32 **....**...*.*...*..*.*.*....**..*..*..****..*....*....**.***.***..*.*..*.*.....*...............*....*... Rev 30 3.10-33 ...*.....**...*.*..*..........*.*.....*.......*.*......**.*.......*....*...*....*.....*.................* Rev 64 3.10-35 ...*...****.*.....*....*.*...*****.*.**...*.*...*..*.*.*...*.**...*.*.............*...*...*....*...*..... Rev 87 3.10-36 ..........*.....*...*............*.*.....*..*.....*.*...*.**..*.....*..**.*............*....*.......**... Rev 87 All remaining pages are Rev 0 dated 1/18/96. PBAPSUNIT3 xii. Revision No. 137 TABLE OF CONTENTS B 2.0 SAFETY LIMITS (SLs) ......................................... B 2.0-1 B 2 .1 .1 B 2.1 .2 *Reactor Core SLs .................................... B 2. 0-1 Reactor Coolant System (RCS) Pressure SL ........... B 2.0-7 B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ........ B 3.0-1 s.URVEILLANCE REQUIREMENT (SR) APPLICABILITY ................. B 3.0-10 B 3 .1 B 3 .1 .1 B 3.1.2 B 3.1.3 B 3.1.4 B 3.1.5 B 3.1.6 B 3.1.7 B 3.1 .. 8 B 3.2 B 3.2.1. B 3.2.2 B 3.2.3 B 3.3
• B 3.3.1 .1 B 3.3.1.2 B 3.3.2.1 B 3.3,2.2 B 3.3.3.1 B 3.3.3.2 B' 3.3:4.1 B.3.3.4.2 B 3. 3. 5 :1 . B 3.3.5.2 B 3. 3. 6 .*1 .* B 3*:3;6.2 B 3.:-3.7,l B 3.3.8.1' B 3.3.8.2 . REACTIVITY CONTROL SYSTEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 3. 1 -1 SHUTDOWN MARGIN (SDM) ............................... B 3 .1-1 Reactivity Anomalies ................................ B 3. 1-8 Control Rod OPERABILITY ............................. B 3.1-13 Control Rod Scram Times ............................. B 3.1-22 Control Rod Scram Accumulators ...................... B 3.1-29 Rod Pattern Control ................................. B 3. 1 -34 Standby Liquid Control (SLC) System ................. B 3.1-39 Scram Discharge Volume (SDV) Vent and Drain Valves .. B 3.1-48 POWER DISTRIBUTION LIMITS .... : .......................... B 3.2-1 AVERAGE PLANAR.LINEAR HEAT GENERATION RATE (APLHGR) ......................................... B 3.2-1 MINIMUM CRITICAL POWER RATIO (MCPR) ................. B 3.2-6 LINEAR HEAT GENERATION RATE ( LHGR) ................. B 3. 2-11 *INSTRUMENTATION ......................................... B 3.3-1 Reactor Protection System (RPS) Instrumentation ......... B 3. 3-1 *Wide Range Neutr6n Monitor (WRNM) Instrumentation ....... B 3.3-37 Control Rod Block Instrumentation ....................... B 3.3-46 Feedwater and Turbine Level Trip Instrumentation ..... : ............................ B 3.3-59 Post Monitoring (PAM} , ........ B 3.3-66 Remote Shutdown System ...... '. .... " ..... ; ................ B 3. 3-77 Anti ci pate*d Tra.hsi .ent Without Scram Reci rcul ati on
• Pump Trip (ATWS-RPT) Instrumentation ............. B 3.3-84 **End of Cycle Reci rcul at ion Pump Trip
• Instrumentation . . . B 3. 3-92a thru B 3. 3-92j Emergency Core System (ECCS) . . .* ... . Instrumentation ................... ; : ....... , ... : . B 3. 3-93 Jsolation Cooling (RCIC) System . .*. Instrumentation ........... ., .. *: ..... ,. ............ B *Primary Containment Isolati6n.Instrumentation: ........ :. B *secondary Jsolatjon Ir\strumen.tation .. , ....... B 3.3-169
• Main Control Room Emergency Venti lat.ion (MCREV) " . *
• System Insfr:umerilation ..... ; *: ........ "' ... : .. .,: .. B 3.3-180 . Loss of Power (LOP) Instrumentation.\:-:;,, ... _-...... B 3.3-187 Reactor Protection System (RPS) Electric Power .. ***
• Mon)toring .. -. *. : .. : ............................ ; ... B 3 .. 3-199 -*.; .i *-.:':. ,. *. -.* .. PBAPS UNIT 3 i
• Revisi ori No. 28. .. * . _;. *.-... _

TABLE OF CONTENTS (continued) B 3.4 B 3.4.1 B 3.4.2 B 3.4.3 B 3.4.4 B 3.4.5 B 3.4.6 B 3.4.7 B 3.4.8 B 3.4.9 B 3.4.10 B 5. B 3.5.1 B 3.5.2 B 3. 5. 3.-B 3.6 B 3.6.1.1 B .3.6.1.2 B 3.6.1.3 B-3. 6 .1. 4 B 3.6.1.5 B 3.6.i.6 B 3. 6:.*2. 1 B 3.6.2 . .2 *B3.6.2.3 B 3.6.2.4 B 3.6.2.5 B 3.6.3.1 B. 3. 6. 2 B 3.6.4:1 B 3.6.4.2 B 3. 6. 4/3 B .3.7." B3.7;J.* B 3.7.2 B 3. T. 3. B 3.7.4 .* _.'.', B 3. r:5 REACTOR COOLANT SYSTEM (RCS) ............................ B 3.4-1 Recirculation Loops Operating ....................... B 3.4-1 Jet Pumps ........................................... B 3.4-11 Safety Relief Valves (SRVs) and Safety Valves (SVs). B 3.4-15 RCS Operational LEAKAGE ............................. B 3.4-19 RCS Leakage Detection Instrumentation ............... B 3.4-24 RCS Specific Activity ............................... B 3.4-29 Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown ............................. B 3.4-33 Residual Heat Removal (RHR) Shutdown Coo1ing System-Cold Shutdown ............................ B 3.4-38 RCS Pressure and Temperature (P/T) Limits ........... B 3.4-43 Reactor Steam Dome Pressure ......................... B 3.4-52 EMERGENCY CORE* COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) ........................ B 3.5-1 ECCS'-Operating ............................. : ....... B 3.5-1 ECCS-Shutdown ........... , .......................... B 3.5-18 RCIC System ......................................... B 3.5-24 . CONTAINMENT SYSTEMS ..................................... B 3,6-1 Primary Containment .* ........................... * ....... B 3.6-1 Primary Containment Air Lock .................... : ....... B 3.6-6 Primary Valves (PCIVs) ............ B 3.6-14 Drywell Air Temperature ....... : ..... : ................... B 3.6-31 Reactor .Building-to-Suppression Chamber Vacuum* Breakers .................................. ; ....... B 3.6-34 Suppression Chamber:to-Drywell B 3.6-42 .Pool Average .................... B 3.6-48 Suppression Pool Water Level ......... , ........ , ......... B 3,6-53 Residual Heat Removal (RHR) Suppression Pool_ * * .. Co _o l i n g *. . . . . . . . . . . . . . . . . :* . . . . . . . . . . . . .. ,. . . . . . . . . . . B 3 . 6 -5 6 Residual Heat Removal (RHR) Suppression Pool Spray ...... B 3:6-60 Res.idual Heat .R_emoval (RHR) Drywell Spray ....... * ........ B 3.6-63a . Del'ete.d ..*. , * .. .... ** ...... * .......... * ............* *., ...... B Primary Containment Oxygen Concentration ...... : ......... B 3:6-70 Secondary C.Onfainrrient .... :.-: ... ,: ..... .-.......... : ......*. B 3.6-73 Secondary Containment *isolation Valves CSCIVs) ........ :. B Standby Gas Treatment (SGT) System ......... , ... _,: .*..... B 3.6-85 PLANT SYSTEMS'.,: ......... : .... .... * .... .... B High Pre*ssufe Service Water (HPSW) System .. : ..*..... B 3.7-1 Emerge.ncy_Service Water (ESW). Sys_tem and Ncirmal Heat Si.nk ........ * .. * .. * ...*. .-... : ....... : ... -...... B 3.7-6-Emergency Heat Si,rik .*. : .' ....... : ....*. : ... * .......... B 3. 7-11 Mai*n Control Room Emergency V_enti l ati on CMCREV) . Sys_tem .. ; ... * ... _.;;< ....... : ....... ,: ....... ..... B 3,l-15 Main Condenser *off gas . .. :: ........ * .... : .......... B 3. 7-22 _. . . ' . -*-. . (continued) PBAPS UNIT. 3 * .ii.* Revision Nd. 106 --*.* . . . . ' TABLE OF CONTENTS (continued) B 3.7 B 3.7.6 B 3.7.7 B 3.8 B 3.8.1 B 3.8.2 B 3.8.3 B 3.8.4 B 3.8.5 B 3.8.6 B 3.8.7 B 3.8.8 B 3.9 B 3.9 .1 B 3.9 .. 2 B 3.9.3 B 3.9.4 B 3.9.5. B 3.9.6 B 3.9.7 B 3.9.8 B 3. B 3.10.1 B 3.10.2 B 3.10:3 B 3.10.4 B 3*.10. 5 B 3 . .'10. 6 **. 13 3.10.i B 3.,10.8 PBAPS UNIT 3 *. -.-*' PLANT SYSTEMS (continued) Main Turbine Bypass System ......................*... B 3.7-25 Spent Fuel Storage Pool Water Level ................. B 3.7-29. ELECTRICAL POWER SYSTEMS ................................ B 3.8-1 AC Sources-Operating ........................... * .... B 3.8-1 AC Sources-Shutdown ................................ B 3.8-40 Diesel Fuel Oil, Lube Oil, and Starting Air ......... B 3.8-48 DC Sources-Operating ............................... B 3.8-58 DC Sources-Shutdown ................................ B 3.8-72 Battery Cell Parameters ............................. B 3.8-77 Distribution Systems-Operating ..................... -B 3.8-83 Distribution Systems-Shutdown ...................... B 3.8-94

• REFUELING OPERATIONS .................................... B 3.9-1 Refueling Equipment Interlocks ...................... B 3.9-1 Refuel Position One-Rod-Out Interlock ................ B 3.9-5 Control Rod Position ................................ B 3. 9-8 Control Rod* Position Indication ..................... B 3.9-10 Control Rod OPERABILITY-Refueling .................. B 3.9-14 Reactor Pressure Vessel (RPV) Water Level ........... B 3.9-17 Residual Heat Removal (RHR)-High Water Level ....... B 3.9-20 Residual Heat Removal (RHR)-Low Water Level ........ B 3.9-24 SPECIAL OPERATIONS ......... : ............................ B 3.10-1 Inservice Leak and Hydrostatic Testing Operation .... B 3.10-1 Reactor Mode Switch Interlock Testing ............... B 3 .10-5 Single Control Rod Withdrawal-Hot Shutdown ......... B 3.10-10 Single Control Rod Withdrawal-Cold Shutdown ........ B 3.10-14 Single Control Rod Drive (CRD) Removal-Refuel'ing .* ...........*.................. B 3.10-19 Multiple Control Rod Withdrawai-Refueling ........... B 3.10-24 Control Rod Testing-Operating ...................... B 3.10-27 SHUTDOWN MARGIN (SDM) Test-Refueling ............... B 3.10-31 Revision No. 3 iii Recirculation Loops Operating B 3.4.1 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.1 Recirculation Loops Operating BASES BACKGROUND PBAPS UN IT 3 The Reactor Coolant Recirculation System is designed to provide a forced coolant flow through the core to remove heat from the fuel. The forced coolant flow removes more heat from the fuel than would be possible with just natural circulation .. The forced flow, therefore, allows operation at significantly higher power than would otherwise be possible. The recirculation system also controls reactivity over a wide span of reactor power by varying the recirculation flow rate to control the void content of the moderat-0r. The Reactor Coolant Recirculation System consists of two reci rcul ati on pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet Each exterrial loop contains one variable speed motor driven recirculation pump, an Adjustable Speed Drive (ASD) to control pump speed and associated piping, jet pumps, valves, and instrumentation. The recirculation loops are part of the reactor coolant pressure boundary and are located inside the drjwell structure. The jet pumps are reactor vessel internals. The recirculated coolant consists of saturated water from the steam separators and dryers that has been subcooled _by incoming feedwater. This water passes down.the annulus between the reactor vessel wall and the core shroud. A portion of the .cool ant flows from the vessel, through the two external recircula-tion loops, *and becomes the driving flow for the jet pumps. Each of the two external recircuiation loops qis<:;harges high pressure. flow into an : external manifcild, ffom which individuil recirculation inlet lines are routed to the jet pump risers within the reactor v e s s e (. Th e r em a i: n i n g p o rt io n of t he c o o l a n t mi x t u re i n t h e
• annul us becomes the suction fl ow for the .)et-pumps. This* .... * .. flow the pump at suction inlets is accelerated by the driving flow. The drive flow and suction fl6w are mixed the jef pump throat section. The _ flow then passes through the jet pump diffuser section into the area below core (lower* plenum), gaining head jn .the process to drive the required flow upward the core. The enters the of the fuel channels and contacts the fuel* cladding, where heat tb the As it rises, _the continued>** B 3.4-1* Revision No. 118

... _. BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 Recirculation Loops Operating B 3.4.1 begins to boil, creating steam voids within the fuel channel that continue until the coolant exits the core. Because of reduced moderation, the steam voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. The recirculation flow control allows operators to increase recirculation flow and sweep some of the voids from the fuel channel, overcoming the negative reactivity void effect. Thus, the reason for having variable recirculation flow is to compensate for reactivity effects of over a wide range of power generation Ci .e., 65 to 100% of RTP) without having to move control rods and disturb desirable flux patterns. Each recirculation loop is manually started from the control room. The ASD provides regulation of individual recirculation loop drive flows. The flow in each loop is manually controlled. *The operation of the Reactor Coolant Recirculation System is an initial condition assumed in the design basis loss of coolant accident (LOCA) (Ref. 1). During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant flow during the first few seconds of the accident. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core flow response for the next several seconds until the jet pump suction is uncovered. The analyses assume that both loops are operating at the same flow prior to the accident. However, the LOCA analysis was reviewed for the case with a flow mismatch between the two loops, with the pipe break assumed to be in the loop with the highej flow. While the flow coastdown and core response are potentially more severe in this assumed case (since the intact loop starts at a lower flow rate and the core response is the same as if both loops were operating at a lower flow rate), a small mismatch has been determined to be acceptable based on engineering judgment. The recirculation system is also assumed to have sufficient flow coastdown characteristics to maintain fuel thermal margins during abnormal operational transients, which are analyzed in Chapter 14 of the UFSAR. continued B 3.4-2 Revision No. 118

BASES APPLICABLE SA.FETY ANALYSES (continued) PBAPS. UN IT 3 Recirculation Loops Operating B 3.4.1 Plant specific LOCA and average power range monitor/rod block monitor Technical Specification/maximum extended load line limit analyses have been performed assuming only one operating recirculation loop. These analyses demonstrate that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling (Refs. 2, 3, 4, 7, and 8). The Maximum Extended Load Line Limit Analysis Plus CMELLLA+) operating domain has not been analyzed for single recirculati-0n loop operation. Therefore, single loop operation is prohibited in the MELLLA+ operating domain (Ref. 9). The transient analyses of .Chapter 14 of the UFSAR have al so been performed for single recirculation loop operation (Ref. 5) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified. During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor instrumerit

• setpoints is also to account for the different relationships between *recirculation drive flow and reactor core flow: MCPR limits and APLHGR (power-. . dependent APLHGR multipliers,. MAPFACP, .and flow-dependent APLHGR mµltipliers, MAPFACt) for single loop operation are specified i.n the. COLR. The* APRM Simulated Thermai Pow.er-. High is in LCO 3.3.1.1, Protection System CRPS) Instrumentation." *
• continued .--.... ..**,, '.: B *_3. 4-3 ,Revision No. 125 l . -

I I 1.* BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UN IT 3 . . .. Recirculation Loops Operating B 3.4.1 Recircul.atioh l_oops_ opera_tingsatisfies Criterion 2 of the NRC Poljcf Statement. * . --. reci.rcul:ation.loops are required *to be.*in .. operatio_n:with their flows'riiatche*d within the limits * *. in SR.3A.1.l,to ensure that during a LOCA caused by a brciak of pjping of recirculatiori*lobp the. (continued)-B 3.4-.4 BASES LCO . (continued)

• APPUCABI LITY PBAPS UNIT 3 Recirculation Loops Operating B 3.4.1 assumptions of the LOCA are Alternatively, with only one recirculation loop in operation, modifications _to the required APLHGR limits (power-and flow-dependent APLHGR MAPFACP and MAPFAC,, respectively of LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and APRM Simulated Thermal Power-High Allowable Value (LCO 3.3.1.1) must be applied to allow continued operation consistent with the assumptions of Reference 5. Single loop operation is prohibited in the MELLLA+ _operating domain per Reference 9. The LCO is modified by a Note which allows up to 12 hours before having to put in effect the required modifications to required limits after a change in reactor operating conditions from two recirculation loops operating to single recirculation loop operation. lf the required limits are not in compliance with the applicable requirements at the end of this period, the associated equipment must be declared inoperable or the limits "not satisfied," and the ACTIONS required by honconformance with the applicable implemented. This time is provided due to the need to stabilize operation with one recirculation loop, including the proced0ral steps necessary to limit flow in the operating loop, and the complexity and detail required to fully implement ahd confirm the required limit modifications. In MODES 1 and 2, for operation of the Coolant Recirculation System are necessary since there is in the reactor core and.the limiting design basis transients and accidents are assumed to occur. In MODES 3, 4, and 5, the consequences of an are reduced and the coastdown characteristics of the recirculation loops are not important.* (continued) * .. B 3.4-5-ReVi si_on No. 125 .*

BASES * *'.' l: :. PBAPS UN'IT 3 Recirculation Loops Operating B 3.4.1 THIS PAGE LEFT BLANK INTENTIONALLY (The contents of this page have been deleted) B 3.4-6 Rey i s i o n .N o -; 5 1 I , I . f ' BASES (continued) Recirculation Loops Operating B 3.4.1 ACTIONS A.l

• PBAPS-UNIT 3 With the requirements of the LCO not met, the recirculation loops must be restored to operation with matched flows within 24 hours. A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than required limits. The loop with the lower flow must be considered not in operation. Should a LOCA occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to status. Alternatively, if the single loop retjuirements of the LCO are applied to operating limits and RPS setpoints, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident sequence. Note that single loop operation is prohibited in the MELLLA+ operating domain per Reference 9. The 24 hour Completion Time is based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action, and on frequent core monitoring by operators allowing abrupt in core flow conditions to be quickly detected. This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flow loop jet pumps, causing vibration of the jet If zero or reverse flow is detected, the condition should be alleviated by changing pump speeds to re-establish forward flow or by tripping the pump.
• continued B 3 .. 4-7 Revision No. 125

' '. BASES Recirculation Loops Operating B 3.4.l ACTIONS .!L_l (continued) *,*---PBAPS lJN IT 3 The MELLLA+ operating domain is not analyzed for single recirculation loop 6peration. Therefore, single loop operation is prohibited in the MELLLA+ operating domain. (Ref. 9). Action shall be taken to immediately exit the MELLLA+ domain in order to return to operation at an analyzed condition. However, it is expected that plant design limitations will preclude operation in the MELLLA+ domain with a single recirculation loop. With no recirculation in operation or the Required Action and associated Completion Time of Condition A or B not met, the plant must be brought to a MODE in which the LCO does not apply: To achieve this status, the plant must be brought to MODE 3 within 12 hours. In this condition, the retirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependente on the recirculation loop coastdown characteristics. The:allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 *.from full. power conditions in an orderly manner and without cha 11 enging . pl a'nt systems. (continued) . ; .. *,._* __ ,** B 3 .4-8 . -.--Re v i s i 0 n NCL 12 5 .*** .-- BASES (continued) SURVEILLANCE REQUIREMENTS .. . : -'* PBAPS UN 1T 3 SR 3.4.1.1 Recirculation Loops Operating B 3.4.1 This SR ensures the loops are within the allowable limits for mismatch. At low core flow (i.e., < 71'.75 X 106 lbm/hr), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < 71.75 X 106 lbm/hr. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop .. ** The mismatch is measured ih terms of core flow. (Rated core flow i.s 102.5 X 106 lbni/hr. The first limit is based on mismatch s 10% of rated core flow when operating at < 70% of tore flow. The second limit is based on mismatch s 5% of rated core flow when 70% of rated core flow .. ) If the flow exceeds the specified limits, the loop the lowet flow is considered not in operation bperation in the MELlLA+ domain is prohibited per Reference 3. The.SR is not required wheh both are not in operation since the mismatch limits are during. single loop or natural circulation operation. The** must be within the specified . after both lciops in operation. The . Surve_ill ance Frequency is .controlled under .the Surveillance Frequency Control_ Program:. (continued) *-. :, *B J: Rev i s i b.n NO .. 12.5 * --.'. . I 1. Recirculation Loops Operating B 3.4.1 BASES (continued) REFERENCES PBAPS' UN IT 3 1. UFSAR, Section 14.6.3. 2. NEDC-32163P, "PBAPS Units 2 and 3 SAFER/GESTR-LOCA Accident Analysis," January 1993. 3. NEDC-32162P, "Maximum Load Line Limit and ARTS Improvement Program Analyses for Peach Bottom Atomic Power Station Unit 2 and 3," Revisi-0n 1, February 1993.

• 4. NEDC-32427P, "Peach Bottom Atomic Power Station Unit 3 Cycle 10 ARTS Thermal Limits Analyses," December 1994. 5. NED0-24229-1, "PBAPS Units 2 and 3 Single-Loop Operation," May 1980. 6. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 7. * "Peach Bottom Atomic Power Statibn Units 2 & 3 GNF2 ECCS-LOCA Ev al uati on," GE Hitachi Nuclear 0000-0100-8531-Rl, March 2011. 8.
• G.-080-VC-272, "Peach Bottom Atomic Power Station LOCA Ev al uati on 'for GE14," General Electric Company, July 2000 . . 9. "Maximum Extended Load Cimit An a ly s i s Pl us Li c ens i n g Topi cal Report , " Rev i s i on 3 ; .June2009. Revision No; 125 Jet Pumps B 3.4.2. B 3.4 REACTOR COOLANT SYSTEM (RCS) B Jet Pumps BASES BACKGROUND The Reactor Coolant Recirculation System is described in the Bae kg round section of the Bases for LCO 3 . 4. I , * "Recirculation Loops Operating," which discusses the operating characteristics of the system and how these characteristics affect the Design Basis Accident (OBA) analyses.
• Th'e jet pumps are reactor vessel internals and in conjunction with the Reactor Coolant Recirculation System are designed to provide forced circulation through the core to remove heat from the fuel. The jet pumps are located in
• the annular region between the core shroud and the vessel inner wall. Because the jet pump suction elevation is at . two-thirds core height, the vessel can be reflooded and coolant level maintained at two-thirds core height even with the complete break 6f the recirculation loop pipe that is located. below the jet pump suction elevation.
• Each reactor coolant recirculation loop contains ten Jet pumps. Recirculated coolant passes down the annulus between* the reactor vessel wall 'and the core shroud. A portion*of the coolant flows from the vessel, through the two external reci rcul at ion loops, and becomes the driving fl ow for the jet pumps. Each of the two external recirculation*loopi discharges high pressure *flow into .an external manifold from* which individual recirculation inlet lines are routed to the . jet pump risers within.the reactor vessel. The remaining ' portlon of the cool ant mixture in t,he' annulus becomes' the
• suction fl ow for the jet pumps. This fl ow enters the jet pump at suet ion i.il lets arid is accelerated py the drive fl ow. The drive fl ow and suet ion fl ow are mixed in the jet pump *throat section.
• The total flow then. passes throµgh .the jet -* ' pump diffuser section. into the area below the core {lower '
• pl en um), gaining* suffi ci erit head in the process. to drive. the . required fl ow upward, through the core. ' APPL,ICABLE *Jet pump JlPERABILITV i.s an impl icit:assumption in the design SAFETY ANALYSES *basis loss of coolant accident {LOCA) analysis evaluated in .. Reference I . {continued).**** . . -PBAPS, UNIT* .3 B 3.4-Ti Revi ston 0 BASES APPLICABLE . SAFETY ANALYSES (continued) LCO APPLICABILITY ACTIONS . PBAPS UN IT 3 Jet Pumps B 3.4.2 The capability of refl ooding the core to two-thirds core height is dependent upon the structural integrity of the jet pumps. If the structural system, including the beam holding a jet pump in place, fails, jet pump displacement and performance degradation could occur) in an increased flow area through the jet pump and a lower core flooding elevation. This could adversely affect the water level in the core during the reflood phase of a LOCA as well as the assumed blowdown flow during a LOCA. Jet pumps satisfy Criterion 2 of the NRC Policy Statement. The structural failure of any of the jet pumps could cause s i g.n i fi cant degradation in the ability of the jet pumps to allow reflooding to two-thirds core height during a LOCA. OPERABILITY of all jet pumps is required to ensure that operation of the Reactor Coolant Recirculation System will be consistent with the assumptions used in the licensing basis analysis (Ref. 1). In MODES 1 and 2, the jet pumps are required to be OPERABLE since there is a large amount of energy in the reactor core . and since the limiting DBAs are assumed to occur in these MODES. This is consistent with the requirements for operation of the Reactor Coolant Recirculation System (LCO 3.4.1). . In MODES 3, 4, and 5, the Reactor Coolant Recirculation System is not required to be in operation, and when not in operation, sufficient flow is not available to evaluate jet pump OPERABILITY. An inoperable jet pump can increase the blowdown area and reduce the capability of reflooding during a design basis LOCA. If one or more of the jet pumps are inoperable, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 The Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. (continued) B 3.4-12. Revision No. 0
• ... :-** ,. *';. ' ., .. . :I:**. ,. J ** *** ,* *=>*' ... .. -.. I .* .. * ' Jet Pumps B 3.4.2 BASES SURVEILLANCE REQUIREMENTS . * -: ' .. ; :_'". *; .. , \ . :. , ' . SR 3.4.2.1 This SR is-designed to detect degradation in jet pump performance that precedes jet pump failure (Ref. 2). This SR is required to be performed only when*_ the 1 oop has forced recirculation flow since* surveillance checks and
• measurements.can only be performed during jet pump operation. The jet pump_failure.of concern is a complete mixer displacement due to jet pump beam failure.* Jet pump plugging is.also of concern. since*it adds flow resistance to the recirculation loop. Significant degradation is indicated if the specified criteria confirm unacceptable deviations from established patterns or relationships. The allowable deviations from the established patterns have been developed based on the variations experienced at plants . during normal operation and :with jet pump assembly failures (Refs. 2 and 3). Each*recirculation loop must satisfy one of the*performance criteria provided. Since refueling activities {fuel assembly replacement or shuffle, as well as . any modifications to fuel support orifice size or core plate bypass flow} can affect the relationship between core fl ow, _jet pumpfl9w, and recirculation loop flow, these
• relationship*s may need.to be re-established-each cycle_. *. Similarly, initial .entry into extended single loop operation . may_ also require of-these .
• During -,the initial weeks oJ operation .under such conditions, . while new patterns, II engineering , . judgement of the daily-surveillance results is used to -.. detect s-ig'nific:ant *abriOrmalities which could indicate a jet *_*-pump faiJ:urE{. -* * ' * * -. . , .:. _-_-Th'e *recirculattori' *pump 'speed sties_ .(pump . flo!' and Joo1:>> fl.ow versus pµmp speed} *are. determined by the * . . _ *flow resistan.ce'. from*:the*Joop suC:fion' through* the jet_ pump * .,. __ , _ _.;A change fo .the: relationship indicates: a plug, ---flow)*estrictlon, : :*: * -* leakage,_* or: new: fl ow J)a_th *,.between the recirculation pump' * .. .--*d;i sthar;ge and* jel* puijip -n-ozzl e .. ._ For tn is criterion, th.e p1.,mip * . _.* . ,* -:-... *.--': ., .. ., < .. '.flow* anQ.-loop fl:ow pump m1.1st -be *Veri -.--;, .** * -* ----* * .::_ * -* -* ** * * * -.-*. * , .-. *. . .** 'lndiv.ici.ual.jet pumps.tn a r-ecirculationJoop normally*do*not ** .have'-. the s.ame fl ow.
• The* unequal fl ow is: due t.o the -drive : -, .
• _ .. flow manifold, \wh.ich:dc>es<riot distribute .to all -ri*sers. :The flow. {err* jet pump' diffuser to lower plenum* .. -_ 'i:fit;ferential pres.sure) pat.tern' or relationship of one -**** .. *' _*,. ' ' ..... *..., -(cont i.Tlued l --* :_. ' --* *
• I , * ... ,* *-: .*, ... _*.Revision No.';Q . -.. *. .-....... , .. **. I BASES SURVEILLANCE REQUIREMENTS REFERENCES SR 3.4.2.1 (continued) Jet Pumps B 3.4.2 pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow for a jet pump that has experienced beam cracks. The deviations from normal are considered indicative of a potential problem in the recirculation drive flow or jet pump system (Ref. 2). Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2. The Surveillance is controlled under the Surveillahce Frequency Control Program. This SR is modifi.ed by two Notes. Note 1 allows this Surveillance not to be performed until 4 hours after the recirculation loop is in operation, since these can only be performed during jet pump operation. The 4 hours is acceptable to conditjons app0opriate for data collection and evaluation. Note 2 allows this .SR not to be 24 hours after THERMAL POWER exceeds 23% of RTP. During low flow condititins, jet pump noise.approaches the threshold response of the.associated fl ow i nstrUmentati on and .precludes the and meaningful data, The 24 hours is an acceptable time to establish tondititins appropriate to SR. . ..
• 1. . UFSAR, 'Sect"lon 14. 6. 3. . . . ' ' 2. . GE SEfrvi ce Information Letter No. 330, .!'Jet Pump Beam
• Crack_s, 11 June 9, 1980 .'
• 3 . N u R EB j c R 3 0 5 2 j II c l 0 e b ut 0 f . I E B u l l et i n 8 0 -0 7 : B w R . . Jet Pump Assembly Failure*," Novembe.r 1984. . . *, : . . . B Revisiori Na. 119
• ' ..
• SRVs and SVs B 3.4.3 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.3 Safety Relief Valves (SRVs) and Safety Valves (SVs) BASES BACKGROUND PBAPS UN IT 3. The ASME Code requires the reactor pressure vessel be protected from overpressure during upset conditions by self-actuated safety valves. As part of the nuclear pressure relief system, the size and number of SRVs and SVs are selected such that pressure in the nuclear system will not exceed the ASME Code limits for the reactor coolant pressure boundary (RCPB). The SRVs and SVs are located on the main steam lines between the reactor vessel and the first isolation valve within the drywel l. The SRVs can actuate by either of two modes: the safety mode or the depressurization mode. In the safety mode, the pilot disc when steam pressure at the valve inlet expands the bellows to the extent that the hydraulic seating force on the pilot disc is reduced to zero. Opening of the stage allows a differential to develop across the. second stage disc which opens the second stage disc, thus venting the chamber over the main valve piston. This causes a pressure differential across the main valve pist6n which opens the main valve. the SVs are spring loaded that actuate when steam pressure at the inlet overcomes the spring force holdirig the valve dist closed. This satisfies the Code requirement . . , Each of the 11 SRVs discharge steam through a line to a point below the minimum. water level in. the suppression p o o l ;-Th e t h r e e S V s d i s c h a r g e st e a m d i re ct ly t o t he drywell. In the depressurization mode, is opened by a pneumatic actuator which opens the second stage disc. The main valve then opens as described above for the safety mode. The mode provides controlled depressurization of the reactor coolant pressure boundary, All 11 of the SRVs in the safety mode and have the capability to operate in the depressurization mode via manual actuation from the control room. Five of the SRVs are allocated to the Automatic Depressurization System (ADS). The ADS requirements are specified in LCO 3.5.1, 11 ECCS-Operat i ng. 11 (continued) B Revision No.119 I. I. SRVs and SVs B 3.4.3 BASES (continued) APPLICABLE SAFETY ANALYSES LCO PBAPS UN IT. 3 The overpressure protection system must accommodate the most severe pressurization transient. Evaluations have determined that the most severe transient is the closure of all main steam isolation valves (MSIVs), followed by reactor scram on high neutron flux (i.e., failure of the direct scram associated with MSIV position) (Ref. 1). For the purpose of the analyses, 13 SRVs and SVs are assumed to operate in the safety mode. The analysis results demonstrate that the design SRV and SV capacity is capable of maintaining reactor pressure below the ASME Code limit of 110% of vessel design pressure (110% x 1250 psig = 1375 psig). This LCO helps to ensure that the acceptance limit of 1375 psig is met during the Design Basis Event. From an overpressure standpoint, the design basis events are bounded by the MSIV with flux scram event* described above .. Reference 2 discusses additional events that are expected to actuate the SRVs and SVs. Although not a design basis event, the ATWS analysis demonstrates that peak vessel bottom pressure is less than the ASME Service Level C limit of 1,500 psig. SRVs and SVs satisfy Criterion 3 of the NRC Policy Statement. The safety of any combination of 13:SRVs and SVs are required to be OPERABLE to satisfy the assumptions of the safety analysis (Refs. 1 and 2). Regarding the SRVs, the requirements of this LCO are applicable only to their *capability to mechantcally open to relieve excess.pressure when the lift. setpoint is exceeded (safety. mode). ' . . . The SRV and SV setpoihts established to ensure the ASME.Code limit on peak reactor pressure is satisfied .. The ASME Code specifications require *the lowest valve . setpoint to be at or below vessel design pressure (1250 psig) and the highest safety valve to be set so that the total accumulated does not exceed 110% of
• design pressure' for overpressurization.conditions: The: * .. evaluations in the UFSAR are based on these setpoints, but also include the additional uncertainties of + 3% of the nominal setpoint to provide an added degree of
• Operat19n .with valves OPERABLE than specified, or with_ set points outside the ASME limits, could result in a more
• severe reactor to a transient than predicted, possibly resulting in fhe ASME Code limit on reactrir
• pressure being exceeded. (continued)* B3.4-16 *Revision No. i19 BASES (continued) APPLICABILITY ACTIONS SURVEILLANCE . . REQUIREMENTS PBAPS UN IT 3 SRVs and SVs B 3.4.3 In MODES 1, 2, and 3, all required SRVs and SVs must be OPERABLE, since considerable *energy may be in the reactor core and the limiting design basis transients are assumed to occur in these MODES. The SRVs and SVs may be required to provide pressure relief to discharge energy from the core until such time that the Residual Heat Removal (RHR) System is capable of dissipating the core heat. In MODE 4, decay heat is low enough for the RHR System to provide adequate cooling, and reactor pressure is low enough that the overpressure limit is unlikely to be approached by assumed op.era ti on al transients or accidents. In MODE 5, the reactor vessel head is unbolted or removed and the reactor is at atmospheric pressure. The SRV and SV function is not needed during these conditions. A.l and A.2 With less than the minimum number of required SRVs or SVs OPERABLE, a transient may result in the violation of the ASME Code limit on reattor pressure. If the safety function of one or more required SRVs or SVs is inoperable, the plBnt must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.4.3.l This Surveillance requires that the required SRVs and SVs will open at the pressures assumed in the safety analyses of References 1 and 2. The demonstration 6f the SRV and SV safety lift settings must be performed during shutdown, since this is a bench test, to be done in accordance with the Inservtce Testing Program. The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures and be verified with insulation installed simulating the in-plant condition. The SRV and SV setpoint is+/- 3% for OPERABILITY.* Prior to placing new or refurbished valves into service, the valve openings setpoints must be adjusted to be within +/- 1% of their nominal setting. continued B 3.4-17 Revision No. 110 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES ":-*.*-. PBAPS UN IT 3 SR 3.4.3.2 SRVs and SVs B 3.4.3 The pneumatic actuator of each SRV valve is stroked to verify that the second stage pilot disc rod is mechanically displaced when the actuator strokes. Second stage pilot rod movement is determined by the measurement of actuator rod travel. The total amount of movement of the second stage pilot rod from the valve closed position to the open position shall meet criteria established by the SRV supplier. If the valve fails to actuate due only to the failure of the solenoid, but is capable of opening on overpressure, the safety function of the SRV is considered . OPERABLE. The Surveillance is controll.ed under the Surveillance Frequency Control Program. 1. NEDC-33566P; "Safety Analysis Report for Exelon Peach Bottom.Atomic Power Sta ti on, Uni ts 2 and 3, Constant Pressure Power Uprate," Revision 0. 2. . UFSAR, Chapter 14. 3.
• NEDC-32988-A, Revision 2, Technical Justification to Risk-informed to Selected f6r BWR Plants. December 2ob2. :: '. -. : .. *--.*_,-* *. :.--_ .* -.*. *.B 3A-18
• Rev i s i on No . J 19 RCS Operational LEAKAGE B 3.4.4 -B 3.4 REACTOR COOLANT-SYSTEM (RCS) 3.4.4 RCS OperationaJ LEAKAGE BASES BACKGROUND PBAPS -UNIT 3 -The RCS includes systems and components that contain or transport the coolant to or from the reactor core. The pressure containing components of the RCS and the portions of connecting systems out to and including the isolation valves define the reactor coolant pressure boundary (RCPB). The joints of the RCPB components are welded or bolted. During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. Limits on RCS operational LEAKAGE are required to ensure appropriate action is taken before the integrity of the RCPB is impaired. This LCO specifies the types and limits of LEAKAGE. _ This protects t_he RCS pressure boundary described in 10 CFR 50.2, 10 CFR 50.55a(c), and the UFSAR 1, 2, and 3). _ The safety significance of RCS LEAKAGE from the RCPB varies widely depending on the source, and duration. Therefore, detection of_ LEAKAGE in the primary containment is Methods for quickly separating the identified LEAKAGE from the unidentified LEAKAGE are necessary to -provide the operators quantitative informati_on to permit them to take corrective action _should a leak occur that is detrimental .to the safety.:of the facility or the public.' A limited amount of 1 eakage inside primary cont_ainment *is expected .from_auxiliary -systems that cannot be made 100% 1 eaktight. leakage* from these systems sho'ul d be. detected and isolated frmn .the prfJllarY :containment-atmosphere, if *
• possible, so as* not to'mask RCS _operational *LEAKAGE * --* ---*-* --_This *Leo; deals_ with protection of the RCPB--from degradation and the _core from inadequate cool i ng, in addition to --preventing the a:cddent analyse$ release -* --assumpt:i ems from being exceeded. The consequences of vio1atfog this LCO inClude the possibility .of a loss of -coolant accident. ----* ,.*. ,--B 3.4-19 _*. (continued) . *.*' Rev_isHm No. -O I 1** I :*._ ; ... ..... ; *, RCS Operational LEAKAGE B 3.4.4 BASES (continued) APPLICABLE SAFETY ANALYSES LCO _: *. ; . PBAPS UNIT 3 .. *.*, ., The allowable RCS operational LEAKAGE limits are on the predicted and experimentally observed behavior of pipe cracks. The nornla l ly expe*cted background. LEAKAGE due to equipment design and the detection of the instrumentation for determining system LEAKAGE were also considered. The evidence from experiments suggests that, for LEAKAGE even greater than the specified unidentified LEAKAGE limits, the probability is small that the imperfection or crack associated with such LEAKAGE would grow rapidly. * * 'The unidentified LEAKAGE flow limit allows time for corrective action before the RCPB could be significantly compromised. The 5 gpm limit is a small fraction of the calculated fl ow from a critical crack in the primary system piping. Crack behavior from experimental programs (Refs. 4 and 5) shows that leakage. rates of hundreds of gallons per minute will precede crack instability..
• The low limit on increase in unidentified LEAKAGE assumes a failure mechanism of intergranular stress corrosion cracking (I GSCC) in service sensitive type 304 and type 316 . austenitic stainless steel that produces tight cracks. This flow increase limit is capable of providing an early warning of such deterioration. No applicable safety analysis assumes the total LEAKAGE limit .. The total LEAKAGE limit considers RCS inventory .makeup capability and drywell floor sump capacity. RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy*Statement. RCS operational LEAKAGE shall be limited to: a. Pressure.Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, since it is indicative of material degradation. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. (continued) Revision o *

{* .. BASES LCO (continued) b. Unidentified LEAKAGE RCS Operational LEAKAGE B 3.4.4 The 5 gpm of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and drywell sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB. c. Total LEAKAGE The total LEAKAGE limit is based on a reasonable minimum detectable amount. The limit also accounts for LEAKAGE from known sources (identified LEAKAGE) . Violation of this LCO indicates an unexpected amount* of LEAKAGE and, therefore, could indicate new. or* additional degradation in an RCPB component or system. d. Unidentified LEAKAGE Increase An unidentified LEAKAGE increase of > 2 gpm within the previous 24 hour period indicates a potential flaw in the RCPB and must be quickly evaluated to determine the source and extent of the LEAKAGE. The increase is measured relative to the steady state value; temporary changes in LEAKAGE rate as a result of transient conditions (e.g., startup) are not considered. As such, the 2 gpm limit is only applicable in MODE I when operating pressures and temperatures *are established. Violation of this LCO could result in

• continued degradation of the RCPB.
• APPLICABILITY. . In MODES 1, 2, and 3, the RCS operational .LEAKAGE LCO. . ..... PBAPS, UNIT ;3
• applies, because the potential for RCPB LE,l\KAGE is greatest* whe.n the reactor i_s pressurized. *
• In* MODES 4 and 5, RCS operational LEAKAGE limits *are not *required since the reactor is not pressurized and stresses.* .... i.n the RCPB materials and p_otent i al for LEAKAGE are reduced. * * * (continued) . .: .. B Revision No. 0 .*

" *' ,, *:: 1i *: '* " :1* '* -_ 1., ;* . .. *,. .. , ...

• RCS Operational LEAKAGE B 3.4.4 BASES (continued) ACTIONS -PBAPS UNIT 3 A. l With RCS unidentified or total LEAKAGE greater than the li111its, actions must be taken to reduce the leak. Because the LEAKAGE limits are conservatively below the LEAKAGE that would constitute a critical crack size, 4 hours is allowed to reduce the LEAKAGE rates before the reactor must be shut down ..
• If an unidentified LEAKAGE has been identified and quantified, it may be reclassified and considered as identified LEAKAGE; however, the total LEAKAGE limit would remain unchanged * . B.l and B.2 An unidentified LEAKAGE increase of > 2 gpm within a 24 hour period is an indication of a potential flaw in the RCPB and must be Although the increase does not necessarily violate the absolute unidentified LEAKAGE limit, certain susceptible components must be determined not to be the source of the LEAKAGE increase within the required Completion Time. For an unidentified LEAKAGE increase greater than required limits, an alternative to reducing LEAKAGE increase. to within limits. (i.e., reducing the leakage rate such that the current rate is less than the * "2 gpm increase in the previous 24 hours" 1 imit; either by
• isolating *the source or other possible methods) is to evaluate service sensitive type 304 and type 316 austenitic stainless steel piping that is subject to high stress or that contains relatively stagnant or i nt_ermi ttent flow fluids and it is not the source of the increased LEAKAGE. -This type piping is very susceptible to IGSCC. The 4 hour Completion Time is reasonable to properly reduce the LEAKAGE increase or v*eri fy the source before the reactor must be-shut down without unduly jeopardizing plant safety. C.l and C.2 If any Required Action and associated Completion Time of Condition A or B is not met or if pressure boundary LEAKAGE exists, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3-within 12 hours and to MODE 4 within . (continued) B 3 .4.-22 Revision No. 0

. . . -. -. -*, . . :. BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES _-' ,* . ' . PBAPS UN IT 3 C.1 and C.2 (continued) RCS Operational LEAKAGE B 3.4.4 36 hours. *The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant safety systems. SR 3.4.4.l The RCS LEAKAGE is monitored by a variety of instruments designed to provide alarms when LEAKAGE is indicated and to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.5,. "RCS Leakage Detection Instrumentation." Sump level and flow rate are typically monitored to determine actual LEAKAGE rates; however, any method may tie used to quantify *LEAKAGE within the guidelines of Reference 6. The Surveillance Frequency is controlled under Surveillance Frequency Control Program. 1.. 10 CFR 50.2. 2. 10 CFR 50.55a(t}: . . 3. UFSAR,,Se6tion 4.10:4._ . 4 .. GEAP-5620,. "Failure Be.havior in *ASTM A106B Pipes* Cdntaining Axial Through-Wall* Flaws," April 1968. 5. "Investigation and Eyaiu.ation of . Cracking. in Austeniti c. Stafnl_ess Steel Piping of B61 ling Water Reacfors," October 1975. 6. Regulatory.Guide l.4S, -May 1973. Generic '.'NRC Position:on IGSCC in BWR

• Au'steni tic: Sta iY1less St_ eel , Pi ping,,,. January 1988 .. -.*_-B 3.4-23 Revision No. 87 RCS Leakage Detection Instrumentation B 3.4.5 B 3.4 REACTOR COOLANT* SYSTEM (RCS) B 3.4.5 RCS Leakage Instrumentation BASES BACKGROUND , *.*-.; -*** *:; . . . PBAPS UFSAR Safety Design Basis (Ref. 1) requires means for detecting and, to the extent practical, identifying location of the source of RCS LEAKAGE. Regulatory Guide 1.45, Revision 0, (Ref. *2) describes acceptable methods for selecting leakage detection systems. Limits on LEAKAGE from the reactor coolant*pressure boundary (RCPB) are required s-0 that appropriate action can be taken before the integrity of the RCPB is impaired (Ref. 2). Leakage.detection systems for the RCS are provided to alert the operators leakage rates above normal background levels are-dete.cted and also to supply quantitative measurement of rates. In addition to meeting the OPERABILITY requirements, the monitors are typically set to pr6vi de the most sensitive response without. causing an excessive number of spurious alarms .. The Bases for LCO 3.4.4, "RCS Operational LEAKAGE," discuss the limits on RCS LEAKAGE rates. -' . -. Systems for separating LEAKAGE of an identified source from.an unidentified .source are necessary to provide prompt and quantitative inf6rmati.6n to the bperators to permit -them to take immediate corrective actioh. *-LEAKAGEfrom RCPB inside the drywell is detected by at l*east one of two independently monitored variables, such_ as sump changes and gaseous levels . . The primary means of quantifying LEAKAGE in the drywell is -.. .floor drain system. * . -. ' -The drywell .floor draih,sump monitoring system monitors the LEAKAGE.collected -in the::floor*drain sump. This unidentified LEAKAGE consists of LEAKAGE from control rod . drives;yalve flanges *cfr'patkings; floor drai.ris, the *Building Closed-Cooling Water* Systein, and drywell air* cooli'tig<:unit condensate. dra_i ns, -and any L.EAKAGE_ not the drain sump. Ah .alte-rnate to -the flbor drain sump system is-the drywell sump monitorJng s,Ystem, but o_nly if the drywell floor drain. sump .is -_ overflowing. *.The* drywe1l equipment drain sump collei::ts not *only-a1J leakage hot col-lect_edin the drywell floor drairi _sump, _but-als.o*an.Y-overflow from'thedrywell floor drain --_-sump._ .Therefore,_ if the drywell-floor* drain sump is'-. (continued} *B-3.4'."24 RevisfonNo. 93 BASES BACKGROUND (continued) . APPLICABLE SAFETY ANALYSES Leo* PBAPS UN IT 3
• RCS Leakage Detection Instrumentation B 3.4.5 overflowing to the drywell equipment drain sump, the drywell equipment drain sump monitoring system can be used to quantify LEAKAGE.* In this* condition, all.LEAKAGE measured by the drywell equipment draih sump mohitoring system is assumed to be unidentified LEAKAGE. The floor drain sump levei indicators have switches that. start and stop the iump pumps when required: If the sump fills to the high high level setpoint, an alarm sounds in the control room, indicating a LEAKAGE rate the sump in excess of 50 gpm. A flow transmitter in the d1scharge line of the drywell floor drain sump pumps provides flow indication in the control room. The pumps can al so be started from the* control room. The primary containment air monitoring system coritinuously monitors the primary containment atmosphere for airborne gaseous radioactivity. A sudden significant increase of radioactivity, which may be attributed to RCPB steam or water LEAKAGE, is annunciated in the control room. ' ' A threat of significant compromise to the .RCPB exists. if the barrier contains a crack that is large enough to propagate rapidly.* LEAKAGE rate limits are set low enough to detect the LEAKAGE from a single crack in .the RCPB (Refs. 3 and 4). The all owed LEAKAGE rates are wel 1 below the rates p red i ct e d fo r c r it i c a l c r a ck s i z e s CR e f . 6 )
• Th e re fo re , these prov{de adequate response before a* significant break in .the RCPB occur. RCS leakage detection instrumentatioh Criteribn 1
• of the NRC Policy. This LCO requires of principles to be OPERABLE to provide confidence that small amounts of unidentified LEAKAGE are detected in time to allow actions to place the plant in a safe condition, when. RCS LEAKAGE indicates possible RCPB degradation. The LCO .requires two instruments to be OPERABLE. The drywell sump system is to. quantify the unidentified LEAKAGE from the RCS, Thus, for the system to be considered the system must be capable of cont foued B 3,4-2'5 No. 93. . *.: ..

I' I" BASES LCD (continued) . APPLICABILITY PBAPS. UNIT 3 RCS Leakage Detection Instrumentation B 3.4.5 measuring reactor coolant leakage. This may be accomplished by use of the associated drywell sump flow integrator, flow recorder, or the.pump curves and drywell sump pump out The system consists of a) the drywell floor drain sump monitoring system, orb) the drywell equipment drain sump monitoring system, but only when the drywell floor drain sump is overflowing. The identification of an increase in unidentified LEAKAGE will be delayed by the time required for the unidentified LEAKAGE to travel to the drywell sump and it may take longer than one hour to detect a 1 gpm increase in unidentified LEAKAGE, depending oh the origin and magnitude of the LEAKAGE. This sensitivity is for containment sump monitor OPERABILITY. The reactor coolant contains radioactivity that,, when released to the primary containment, can be detected by the gaseous primary containment radioactivity monitor. Only one of the two detectors is required to be OPERABLE. A radioactivity detection system is included for monitoring gaseous activities because of its sensitivities and rapid re*sponses to RCS LEAKAGE, but it has recognized l i mitati ans. Reactor coolant radioactivity levels will *be low during initial reactor startup and for a few weeks thereafter, until activated corrosion products have been formed and fission products appear from fuel element cladding contamination or cladding defects .. If there are few fuel element cladding defects and low levels of activation products, tt not be possible fcir the gaseous primary containment atmospheric radioactivity monitor. to detect a 1 gpm increase with.in 1 hour during normal opera ti on.

• However, the gaseous primary containment atmospheric radioactivity is OPERABLE when it is capable of detecting a 1 gpm increase in unidentified. LEAKAGE with1n 1 hour given*Bn RCS equivalent to that assumed in the design : calculations for.the monitors.(Reference 6). The LCD is satisfied monitors of diverse means
• available. Thus, the drywell monitoring system, in combination.with a primary containment citmospheric .radioactivity moh1tor provides ari acceptable minimum. In MODES 1, 2, and 3, leakage detectiDn systems are required to be OPERABLE to support LCD 3.4.4. This Applicability' is.*
• consistent with that for LCD 3. 4. 4.
• B 3.4-26 Rev i s i on N o . 93 -.:. ' .1 I RCS Leakage Detection B 3.4.5 BASES (continued) ACTIONS A.1. A.2. and.A.3 PBAPS UNIT 3 With the drywell sump monitoring system inoperable, the only means of detecting LEAKAGE is the primary containment atmospheric gaseous radiation monitor. The primary containment atmospheric gaseous radiation monitor typically cannot detect a 1 gpm leak within one hour when RCS activity is low. In addition, this configuration does not provide the required diverse means of leakage detection. Indirect methods of monitoring RCS leakage must be implemented. Grab samples of the primary containment atmosphere must be taken and analyzed and *monitoring of RCS leakage by administrative means must be performed every 12 hours to provide alternate periodic information. Administrative means of monitoring RCS leakage include monitoring and trending parameters that may indicate an increase in RCS leakage. There are diverse alternative mechanisms from which appropriate indicators may be selected based on plant conditions. It is not necessary to utilize all of these methods, but a method dr methods should be selected considering the current plant conditions and historical or expected sources of unidentified leakage. The administrative methods are drywell pressure and temperature, Reactor Recirculation System pump seal pressure and temperature and motor cooler temperature indications, and Safety Relief Valves tailpipe temperature. These indications, coupled with the atmospheric grab samples, are sufficient to alert the operating staff to an unexpected increase in unidentified LEAKAGE. The 12 h6ur interval is sufficient to detect increasing RCS leakage. -The Required Action provides 7 days to regtore another RCS leakage monitor to OPERABLE status to regain the intended leakage detection diversity. The 7 day Completion Time ensures that the plant will not be operated in a degraded configuration for a lengthy time period. B.1 and B.2 With the gaseous primary containment atmospheric monitoring -channel inoperable, grab samples of the primary containment atmosphere must be taken and analyzed for gaseous radioactivity to provide periodic leakage information. Provided a sample is obtained and analyzed once every 12 hours; the plant may be operated for up to 30 days to allow of the required monitor. continued B 3.4-26a Reviston No. 93 BASES ACTIONS SURVEILLANCE. REQUIREMENTS . **---.. PBAPS UN IT '3 RCS Leakage Detection Instrumentation B 3.4.5 B.1 and B.2 (continued) The 12 hour interval provides periodic information that is adequate to detect LEAKAGE. The 30 day Completion Time for restoration recognizes that at least one other form of leakage detection is available. C.1 and C.2 If any Required Action and associated Completion Time of Condition A or B cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 within 36 hours. The allowed Completion Times reasonable, based on operating experience, to perform the actions in orderly manner and without challenging plant systems.
• With all required irioperable, no retjuired automatic means Df LEAKAGE available, and immediate plant shutdown in acccirdance with LCO 3.0.3 is. required. SR .3.4.5.1 This SR .i_s for the performance of a. CHANNEL CHECK of the requ.ired .pr.i ma ry containment atmpspheri c. monitoring system ..
• The confidence the channel is ng properly. The Survei lia:nce frequency is*
• controlled urider the Survei i *1 ance Frequency Program . . ** ... : _., .. ,.* B 3. 4-27 *Revision No. SF I*. BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UN IT *3 . RCS Leakage Detection Instrumentation B 3.4.5 SR 3.4.5.2 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required RCS detection instrumentation. The test ensures that the monitors can perform their function in the desired manner. The test also verifies the alarm setpoint and relative accuracy of the instrument string. The Surveillance Frequency is controlled under the
• Surveillance Frequency Control Program. SR 3.4.5.3 This SR is for the performance of a CHANNEL CALIBRATION of required leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument string. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 4.10:2. Guide 1.45, Revision 0, Pressure Boundary Detection Systems," May 1973. 3. GEAP-5620, "Failure *Behavior in ASTM Al06B Pipes Containing Axial Through-Wall Flaws,." April 1968. ' ' ' 4
• N U REG -7 5 I O 6 7 , " In v es *t i g a t i on a n d Ev q l u a t i on of Cracking in Austenitic Stainless Steel Piping of .Boiling Water Reactors," October 1975. 5. UFSAR, Section'4.10.4. I, p. * ..
• UFSAR, 4.10.3.2. "*'-. *,* .....
• B * .. Rev i.s fon No. 93

"" . ;.-*1 ** .. *, - 1,. ;*.*' t*:. ,i ,_. '< ti.'* 8-3. 4 REACTOR COOLANT S.YSTEM (RCS) B 3.4.6 RCS Specific Activity RCS Specifit Activity B 3.4 .. 6 * .. BASES BACKGROUND I During circulation, the reactor coolant acquires radioactive -materials due to release of fission products from fuel leaks into the react6r coolant and activation of corrosion products in the reactdr coolant.* These radioattive materials in the reactor coolant can plate out in the RCS, and, at* times, an accumulation will break away to spike the level of The release codlant during a Design Basis Accident (OBA) could send radioactive

• into the enviroriment,
• Limits on the maximum allowable level -of radioactivity in the reactor coolant are established to.ensure that. in the *event of a release_of any to the environment during a OBA, radiation doses are maintained within the limits of 10 CFR 50.67 (Ref. 1). . *1-** --This. LCO contains the iodine-specific acdvi ty limits. The iodine isotopic activities per gram of reactor coolant are expressed .in terms *Of a DOSE EQUIVALENT I-131. The allowable level is intended to limit:the maximum 2 hour radiation *dose .to an-individual at the site-boundary to well within the-10 *Cf=R 50.;57 limit as modified in Regulatory Guide 1.1A3, Tabie 6 . . * .. , *SAFETY f\NALYSES ... -. I . . . ... * .. * *,; ... -. PBAPS' UNIT 3-. ' . Ana1:yti cal methods ahc( asswnpti ons. i nvol vi ng tadi mater1 ai .in the -primary co_ol ant are presented in* the UFSAR . 2). The specific activity in-the reactdr coolant_ (the -soUrte term) initial cdndition for of the an accident due to a steam line (MSLB) outside. containment. -No fuel damage is postulated in the MSLB accident, .and the rel ease of radioactive material to the environment 1s assumed to end when the main.steam. valves -(MSIVs) clbse completely .. -This MSLB release the.basis for-determining offsite doses (Ref. 2). The on the specific. activity of the. primary coolant ensure that the maximum_2 hour TEDE doses at the*site b-oundary, resulting from an MSLB outside during steady state operation, will not exceed the' dose guidelines of 10 CFR 50:67 as modified in Re.gylatory Guide 1.183-, Table 6. *--. .. * . ' (continued) ' .. -: . .'*; .. * .. : .-. Revision No-.* 76 -* ... ':.* . .-:*. ... ... ,

,*:* ... ' ;, .. * .. ' -....' . '* .* -*. .': . .* ... ; .. I BASES APPLICABLE . ** SAFETY ANALYSES (continued) LCO ** . LITY *.' '-': : ACTIONS .*',, .; *.,_ . -... *.' *'**** PBAPS UN!J<3", . -*'* RCS Speci fit Activity ' B 3A.6 The limits on specific activity*are values a of typical site locations. *These limits are

• conservative because the evaluation cons{dered more restrictive parameters than for a specific site, such as of the site boundary and the meteotological
• conditions of the site. RCS specific activity satisfies Criterion 2 of the NRC
• Policy Statement. The specific iodine activity is limited :s;0.2 µCi/g*m DOSE EQUIVALENT I -131. This 1 i mi t ensures the source term . . . assumed in the safety analysis for the-MSLB is hot . so any release of radi cacti vi ty to the environment duri.ng an . MSLB is well within the 10 CFR 50.67 li.mits as. modifiE!d in .Regulatory Guide 1,183, Table 6.
• In MODE t, and MODES 2 and 3 with any main steam 1 i r:ie not limits on the primary coolant applicable si nee there is an escape path* for. rel ease of .
• radioactive material from the primary coolant to the environment in the event of an MSLB putsi de of primary* * * . ' . : :,' ' .. : ' :* .
• In MODES 2 and '3 with0the.main steam lines sucb
• limits do not apply si11ce an escape. path dries not-exist .. ' In . : MODES 4 and 5, nc:i 1 i mi ts are required since the reactor i_s .* * .. riot pressurized and the potential. for leakage is. reduced.* *A: 1 and A.2 .*'-' ... *. *When the re;:ictor cool ant specific activity exceeds the *.LCO
• DOSE" EQUIVALENT 1-131 limit, but is ::;;4:0 µCi/gm, samples * *
• must* b_e* analyzed :for* DOSE. EQUIVALENT l-;1 :31 at 1 east; once . . every* 4 hours.: *. In. additiOn, the specific activity mus( be .restored to the LCO lfmit Wi thi n.48 ho"urs .... The Comp-1 etion Time of once every,*4 hours is: based on' the time needed to* . 1:,ake and anal y?.e* a .sarrip1*e*, .*. The 48 *hour:-Completion Ji me. to '.restore. the activity level prmiidesa reasonable time for * * ** .temporary coolant .activity *increases* (iodine spikes}.to.:be . cle(lne(j up witll the processing systems. . . . . ,,. . . . *. ,._ *. ** .-: .. '.' .. **<** ._._,* .. .. .-. .. :;, . : ... , 13. 3.A-,.30 ReVi sion No.-'76 .,. . .. .':-.. : ._., _,._ .:.*. .. : .. *

'. ! I '. I *:[*. .. . 1.* BASES ACTIONS -.,.*_ *.'. **--'." *.PBAf>s:uNIT.3 A.1 and A.2 (continued) RCS Specific Activity B A Note permits the use of the provisions of ThiS allowance permits entry into the applicable MODE(S) while relying on the ACTIONS. This allowance is acceptable due to the significant incorporated into the activity limit, the low probability of an event *which is limiting due to exceeding this lim1t, and the ability to restore transient specific activity excursions while the plant remains at, or proceeds to, power operation. B. 1 . s. 2 1 . s. 2 . 2. 1 . and s. 2. 2. 2 If the DOSE EQUIVALENT I-131 cannot be re.stored to 0.2 µCi/gm within 48 hours, or if at any time it is> 4.0 µCi/gm, it must be determined at least ohce every 4 hours and all the main steam must be within

• 12 hours. Isolating the main steam precludes the possibility of' releasing radioactive material to the environment in an amount that is more than a small fraction of ihe requirements of 10 CFR 50.67 as modified in Regulatory Guide 1.183, Table 6, during a postulated MSLB Alternatively, the plant can be placed in MODE 3 within 12 hriurs and in MODE 4 within 36 hours. This option is provided fbr those instances when isolation of main steam 1 i nes 'i S not desired ( e
• g
• I due to the decay heat 1 oads)
• In MODE 4, requirements bf the LCO are no longer* applicable. *The Completi6n Time of once every 4 hours is the time needed *to take and analyze a The 12 hour Completion Time is reasonable, based on operating eiperience, to isolate the main lines in an qrderly manner and without . challenging pi ant systems. Also, the allowed Completion Times for Required Actions B.2.2.1 and B.2.2.2 for placing . the unit in MODES 3 and 4 are reasonable, based on operating experience, to the required plant conditions from full power conditions in an orderly manner and without chailenging plant systems. (continued) . . . -. .. -B Revision No. 76 I. I BASES (continued) SU RV EI LLANCE REQUIREMENTS REFERENCES PBAPS UN IT 3 . SR 3.4.6.1 RCS Specific Activity B 3.4.6 This Surveillance is performed to ensure iodine remains within limit during normal operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MODES is much less. 1. 10CFR50.67. 2. UFSAR, Section 14.6.5. *,.'. B 3.4-32 Revision No. 87 RHR Shutdown Cooling Shutdown B 3.4.7 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.7 Residual Heat Removal (RHR) Shutdown Cooling Shutdown BASES BACKGROUND Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to reduce the temperature of the reactor coolant to < 212°F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for the reactor in the Hot Shutdown condition. The RHR System has two loops with each loop consisting of two motor driven pumps, two heat exchangers, and associated piping am:I valves. There are two RHR shut9own cooling subsystems per RHR System loop. Both loops have a common suction from the same recirculation loop. The four redundantl manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via the assoc1ated recirculatiort loop. The RHR heat exchangers transferheat to the High Pressure Service Water (HPSW) System. Any one of the four RHR shutdown cooling subsystems can provide the required decay heat removal function. ,. . ' ' ' . ' ' ' ' ,APPLICABLE Decay heat removal by operation of. the* System in the SAFETY ANALYSES shutdown cooling mode required for mitigation of any event or accident evaluated iri the safety analyses. Decay heat removal is, an important safety function LCO <<" -_., " PBAPS UNIT 3
• must. be accompl ishe,d or core damage could result. The RHR . Shutdown CoQ ling System. meets Criterion 4 of the NRC Policy Statement .. ' . , . ,*. ,. * . Two RHR shutdown cooling subsystems are: required to be *OPERABLE;. and when no re.circulation pump is. in operation, one shutdown cooling subsystem must be inoperatiori .. 'An
• OPERABLE RHR shutdown* cool ing *subsystem consists of one , * , OPERABLE RHR pump,, one heat* exchanger,, a *HPSW pump capable of providing cooling *to the heat exch,anger, and the assoc.i ated pi p.i ng and .valves. The two subsystems have a :toinmon suction ,source* and are allowed to have common Since piping is a component (continued) ' --B 3.4-33
• Revisio.n No. o
• BASES LCD (continued)
• APPUCABIUTY PBAPS *UNIT 3 .*.,:. RHR Shutdown Cooling Shutdown B 3.4.7 is assumed not to fail, it is allowed to be common to both subsystems. Each shutdown cool subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly contiAuous operation is required. Management of gas voids is important to RHR Shutdown Cooling System OPERAS I LI TY. Note 1 permits both required RHR shutdown cooling subsystems and recirculation pumps to be shut down for a period of 2 hours in an 8 hour period. Note 2 allows one required RHR shutdown cooling subsystem to be inoperable for up to 2 hours for performance of Surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and .the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy. In MODE 3 reactor steam dome pressure below RHR shutdown isolation pressure {i .e;, the. actual pressure at which the RHR shutdown cooling isolation pressure clears) ihe RHR Shutdown Cooling System must be OPERABLE and be operated in the shutdown cooling mode to remove decay heat to reduce or maintain coolant temperature. Otherwise, a rec1rculation pump is required to be in operation. In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the RHR shutdown cooling isolation* pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping. Decay heat removal at reactor pressures greater than or equal to the RHR shutd6wn cooling isolation.pressure is typically accomplished *by condensing the steam in the main condens.er. continued* B 3.4"34 Revision No .. 128 t : . BASES APPLICABILITY (continued) ACTIONS . . PBAPS UN IT '3
• RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems CECCS) CLCO 3.5.1, "ECCS-Operating") do not allow placing the RHR shutdown cooling subsystem into operation. The requirements for decay heat removal in MODES 4 and 5 are discussed in LCD 3.4.8, "Residual Heat Removal CRHR) Shutdown Cooling System-Cold Shutdown"; LCD 3.9.7, "Residual Heat Removal CRHR)-High Water Level"; and LCD 3.9.8, "Residual Heat Removal CRHR)-Low Water Level." A Note has been provided to modify the ACTIONS related to RHR shutdown cooling Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in ihe Condition, discovered to be inoperable or not within limits, will not result entry into the Condition. Section 1.3 also specifies Required Actions of the Condition to apply fbr each additional failure, With Completion Times based on entry *into the Condition. However, _the Required Actions for inoperable shutd.own cooling subsystems provide appropriate for separate shutdown cooling As such, a Note provided allows Condition entry for each shutdown co6ling A.li A.2. and A.3 .. With one required RHR shutdown cooling subsystem inoperable for decay heat removal, except as permitted by LCD Note the subsystem must be to OPERABLE status
• with6ut delay, *In this remaining OPERABLE can provide the necessary decay heat removal. The (continued) B 3.4-35 Revision.No. 53.

BASES ACTIONS

• PBAPS UN IT 3 RHR Shutdown Cooling Shutdown B 3.4.7 A.I, A.2, and A.3 (continued) overall reliability is reduced, however, because a single failure in the OPERABLE subsystem could result in reduced RHR shutdown cooling capability. Therefore, an alternate method of decay heat removal must be provided. With both required RHR shutdown cooling.subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability. This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour Completion Time is based on the decay heat removal function
• and the probability of a loss of the available decay heat removal capabilities. The required cooling capacity of the alternate method should be ensured by verifying (by calculation or demonstration) its capability to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Condensate/Main Steam Systems and the React<;>r Water Cleanup System. However, due to the potentially reduced reliability of the alternate methods of decay heat removal, it is also required to reduce the reactor coolant temperature to the point where MODE 4 is entered. B.l, 8.2 *. and 8.3 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as permitted by LCD Note 1, reactor coolant circulation by the RHR shutdown cooling subsystem or recirculation pump must be restored without delay. Until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature. The 1 hour Completion Time is based on the coolant circulation function and is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant (continued} B 3.4-36 Revision No. 0 I. BASES ACTIONS SURVEILLANCE REQUIREMENTS -,_,* .. ' -. . '. -PBAPS UN IT 3 .. RHR .Shutdown Cooling System-Hot Shutdown .B 3.4.7 B.1. B.2. and B.3 (continued) circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours thereafter. This will provide assurance of continued temperature monitoring capability. During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate. SR 3.4.7;1 This Surveillance verifies that one required RHR shutdown cooling subsystem or recirculation pump is in operation and reactor .coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal The Surveillance Frequency *is controlled under the Surveillance Frequency Control * * . This is modified by a.Note allowing suffitient . time to**align the RHR System for shutdown cooling operation the pressure*setpoint that isolates the system, Dr'for plBcing a retirculation pump in operatitin. The Note' .takes except Jon to the. requi of the Surveillance being met. (Le,, forced coolant circulation is not required for this inHial 2 ho.ur period), which a}so * . allows entry into the ApplJcability of .this SRecification in accordance with* SR 3,0.4 the Surveillance will not be' "not-met" at the. time *ofei:itry into the Applicability. RHR Shutdown* Coolfng (SOC) System pip.ing and.components the to vbids*anci pockets gas*es; P'reventing *and.managing gas intrusion* and ' atcuhiul atfon fs necessary fqr proper operafi on' of the *** 'requ.i.red.RHR shutdown cooling subsystems a.nd may also prevent: water hammer, pump c;avi tat1 on, and pllinpi ng of*-. noncon'deri:si b'l e gas into the reacto'r vessel. ' ' h.ave ., .. (continued) .:'" -. 'B. 3.4-37 8.evi si on No. 128 .

BASES SURVEILLANCE REQUIREMENTS *. :0. ----------------------------------RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 SR 3.4.7.2 (continued) --Selecti6n of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumeritation isometric drawings, plan and elevation drawings, calculations, and operational procedures. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoratioh. Susceptible 16cations depend on plant and system c6nfiguration, such as stand-by versus operating conditions.

• The RHR Shutdown Cooling System is OPERABLE when it is sufficienily filled with water. For the RHR SOC piping on the dis-charge side of the RHR pump, acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance. criteri6 the susceptible location (or the volume o-f accumulated gas *at one or more susceptible locati.ons exceeds *an acceptance criteria for gas volume in the RHR SDC piping on the discharge side of a pump), the Survei 11 a nee is not met. If tbe accumulated. gas is
• eliminated or brought within. the 'acceptance criteria limits -during. performance the Surveillance, the SR is met . past sysfem OPERABILITY under t_he Corrective Act i oh* Program. If it is *determined by subsequent ev al ua ti on that the RHR Shutdown Cooling System is not rendered by the actumulated gas (i.e. i the system is sufficieritly filled with the Surveillance may be decl,a red' meL -Atcumul ated gas shoal d be .eliminated or -brought within* the ac'ceptance c_riteria 1 i ini ts. Si nee the. RHR soc pipin-g.orrthe d*i-st'harge.side .-of the pump is the same as_ the lOw,PressureCoolat;i't 'Injection pi.ping,.perforinances of*** s u rvei i 1 a nces _*for ECCS **rs* may satisfy the requirements __ of *this s[lrvei 11 ance: . For the. RHR SOC piping _dn the suction side* of the RHR pump; _the .surVeillanc-e is rne.t by virtue of the performance Qf ,Operating procedures that ensurec that the RHR soc_suetion piping fs **adequately. filled :*and veritecL_ .The_ . performance elf th'ese manual actions ensures that the -* surveflTani::e is meL:
• RHR snc System l ncati ans on the di sch a side of the RHR pump $usce'ptible to gas accum_ulatiorr are lllonitored and*, if gas. i*s :found; _.the gas volume_ is compa*red to>the acceptance --criteria.for the-locatfon: Susceptible locations in the same system n'ow path which a re subject .. fo the. same gas (continued) *B 3 .4-37a *** Re.yi sion No. 129

. . . BASES SURVEILLANCE *REQUIREMENTS REFERENCES PBAPS UNIT *3 RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 SR 3.4.7.2 (continued) intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for mohitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval. The SR may be met for one RHR SOC subsystem by virtue of having a subsystem in service in accordance with operating procedures. This SR is. modified by two Notes .. Note 1 that states the SR is not required to be performed until 12 hours after reactor dome pressure is less than the RHR Shutdown Cooling System Iso1ation reactor pressure allowable value in TS Table 3.3,6.1-1. In a rapid shutdown, there.may be insufficient to verify all locations prior to entering the Applicability. Note 2 to .the Surveillance recognizes that the scope of the is limited to' the RHR system The components been determined to not be required to be in the scope of this surveillance due to operating experience and the design of the system. The Surveillance is controlled the Surveillance Frequency Control Program; *The Surveillance Frequency may by location susceptible to gas accumulation. None.

• B .Revision No. 128 *I . . .

I

• I I ...... . . .:-: '*., ,* *, -'*.*: ... .. '. . . . :*_ *. * *. " * ** -'*-.. :* ...
• I., RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 B 3 A REACTOR COOLANT SYSTEM (RCS) -B 3.4.8' Residual Heat *Removal .(RHR) Shutdown -Coo.ling System-Cold Shutdown BASES BACKGROUND Irradiated fuel in the shut<;lown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to maintain the temperature of the reactor coolant s 212°F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for* keeping the reactor in the Cold Shutdown* condition. *_* . The RHR-system has two loops with each loop consisting of two motor driven pumps, two heat exchangers, and associated . piping and valves. There are two RHR shutdown cooling
• subsystems per _RHR System loop. Both loops have a common suction from the-*saine recirculation loop. The four redundant, manually controlled shutdown cooling subsystems ' of the RHR System provide decay heat removal. Each_ pump _ * *
• discharges the reactor cool ant, after circulation through. :> ..
• the respective heat exchanger, to the reactor .via the ** associated recirculation loop. The RHR heat exchangers . transfer heat to the High Pressure Service Water (HPSW) System.
• Any one of the four RHR shutdown cooling c:;an provide the_ requested decay heat removal ; * * ,* .,_.
• I . , , , , :. , . I -APPLiCABLL ne*cay heat removal by operation of the RHR System '; n ._ SAFETY )\NP,L YSES . shutdown coo 1 i ng mode is* not required Jar mi ti gat ion' of any **event or accident: evaluated. in the *Safety analyses .. Dec:;ay ** . heat .removal is, .however, an important safety function ttia't .. must be *accomplish'ed-or core damage coulp result. The_ RHR .
• Shutdown Cooling Systern *meets Criterion 4-of the NRC Pol1cy LCO .. :* *, .** _.* PBAPS. UN IT, 3 "' . *statement. * * * .. Two. RHR shutdown;* cooling*._ subsystems are*. required to be .. *. * .* *OPERABLE, and when n_o recirculation pump ts in "* . _one RHR shutdown cooling subsystem must be* in operation. An * "OPERABLE RHR -shutdown cooling subsystem consists of one *. OPERABLE RHR one -heat exchanger, a HPSW pump .capable of providing cooling to the heat. exchanger, and the .. : ' piping and The *two subsystems have._a . * 'common. suet ion. source *and are al 1 owed to-.have common * * . Since piping is a passive comporienttha(* .. *:* is assumed.* not to faU , tt is a 11 owed* *to. pe common lo both .. * *'*--* (continued) ... * ... ': . -

BASES LCO (continued) APPLICABILITY PBAP:S -uN IT .3. RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 subsystems. In MODE 4, the RHR cross tie valve (M0-3-10-020) may be opened (per LCO 3.5.2) to allow pumps in one loop to discharge through the opposite recirculation loop to make a complete subsystem. In addition, the HPSW cross-tie valve may be opened to allow an HPSW pump in one loop to provide cooling to a heat exchanger in the opposite loop to make a complete subsystem. Additionally, each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. In MODE 4, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required; Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY. Note 1 permits both required RHR shutdown cooling subsystems to be shut down for a period 9f 2 hours in an 8 hour period. Note 2 allows one required RHR shutdown cooling subsystem to be inoperable for up to 2 hours for performance of Surveillance tests. These tests may be on the affected RHR System or on some other plant system or component .that necessitates placing the RHR System in an inoperable status during the performance.* This is permitted because the core heat generati6n be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redun*dancY. In MODE 4, the RHR Shutdown Cooling System must be OPERABLE and shall be operated in the shutdown cooling mode to remove decay heat to maintain coolant temperature below 212°F. Otherwise, a recirculation pump is required to be in operation. In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or to the RHR shutdown cooling isolation pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping. Decay heat removal at reactor pressures above the RHR shutdown cooling isolation pressure is typically accomplished by condensing the steam in the main *Condenser .. continued B 3.4-39 Revision No. 128 . --BASES APPLICABILITY (continued) . ACTIONS *-,. :* ":. PBAPS UNIT 3 .. RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 Additionally, in MODE 2 below this pressu*re, the OPERABILITY requirements for the Emergency Core Cooling Systems (ECCS) (LCO 3.5.1, 11ECCS-Operating11} do not allow placing the RHR shutdown cooling subsystem into operation. The requirements for decay heat removal in MODE 3 below the RHR shutdown cooling isolation pressure and in MODE 5 are discussed in LCO "Residual Heat Removal (RHR} Shutdown Cooling System-Hot Shutdown"; LCO 3.9.7, 11Residual Heat Removal (RHR}-High Water Level11; and LCO 3.9.8, "Residual Heat Removal (RHR}-Low Water Level. 11 A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. 1.3 also specifies Required Actions of :the Condition continue to apply for each additional failure; with Completion Times based on initial entry into the Condition. the Required Actions for inoperable shutdown coo 1 ing_ subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling .* . . .subsystems. As such, a Note. has been provided that al 1 ow.s . separate Condition entry for each inoperable RHR shutdown cooling subsystem. * *A.1 Wi.th one o*r the two :required RHR shutdown cooi i ng subsystems fooper,able, except .as permitted by tCO Note 2, the remaining * . subsystem is capable -of providing the required decay heat removal. However, ,the overall Therefore, an _al tern.ate method. *of decay heat removal must be. :proVided: .With.both required RHRshutdown cooling..

• subsystems inoperable, an alternate.method of.. decay heat "removal must. be prqvided *in addition to that .provided for the initial RHR shutdown cool i fig* subsystem inoperab:J 1 i ty. . This re-establishes bac;kup decay heat removal capabilities, similar to the requirements of the (CO. The 1 hour .. Completiqn. Time is based Qn the decay heat removal function . , and, the. probability.* of a ) ass of. the *available* decay heat .. . . ' (continued) . . . : . . -. s: .*. . ,* Revi siOn 0 ..
• J ..

BASES ACTIONS '. -,* . -. *'

• PBAPS UNIT 3
• A.I (continued) RHR Shutdown Cooling Shutdown B 3.4.8 removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours thereafter. This will provide assurance of continued heat removal capability. The required cooling capacity 'of the alternate method should be ensured by verifying (by calculation or demonstration) jts capability to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Condensate/Main Steam Systems (feed and bleed) and the Reactor Water Cleanup System. B.1 and B.2 With no* RHR shutdown cooling subsystem and no recirculation pump in.operation, except as permitted by LCO Note 1, and until RHR or recirculation pump operation is. re-established, an alternate method of reactor coolant circulation must be placed into servi.ce. Thi*s will provide the necessary circulation for monitoring coolant temperature. The 1 hour Completion Time is based on the coolant circulation function and is such that the 1 hour is applicable separately for eath occurrence involving a loss of coolant circulation. Furthermore; verification of the functioning of the alternate method mµst be reconfirmed every 12 hours thereafter ... This will provide assurance of continued temperature monitoring*capability. Durin{the period when the .reactor coolant .is being
• circulated by an _alternate method (other than by the** required RHR shutdown subsystem or recirculatio'n the reactor coolant temperature and pressure must be .periodically monitored to*_ensure proper Junction of the al ternaJ.e method. The cmce per hour Coi:np let ion Ti me is *deemed appropriate. (continued) ,, ,-. *. B 3.4-41
• Revi slori No.
• o .*,.'**

BASES (continued) SURVEILLANCE REQUIREMENTS .. : :,. __ ** P BA PS . UN IT 3 SR 3.4.8.1 RHR Shutdown Cooling Shutdown B 3.4.8 This Surveillance verifies that one required RHR shutdown cooling subsystem or recfrculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.4.8.2 RHR Shutdown Cooling (SOC) System p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the required RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncrindensible gas intq the reactor vessel. Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawihgs, isometric drawings, plant and elevation drawings, calculations arid operational procedures. The design review is supplemented by system walk downs to validate the system high and t6 confirm the location and brientatibn of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance br restoration. Susceptible locations depend bn plant and. syste_m configuration,. such as stand-by versus operating conditions. . . . . ' The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with For the RHR SOC piping on the discharge side*of the RHR pump, acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the location (or the of accumulated gas at one or more locations exceeds an acceptance for volume in the RHR SOC piping on the discharge side of a pump), the is met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and system OPERABILITY is evaluated under the Corrective Action Progfam. If it is determined by subsequent evalGation that *the RHR Shutdown Cooling System is not rendered inoperable by the the system is sufficiently filled with water), the Surveillance *(continued) B 3.4°'42 Revision No. 129 BASES SU RV EI LLANCE REQUIREMENTS .*REFERENCES *. PBAPS !:JN I.T 3 * ;\ RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 SR 3.4.8.2 (continued) may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits. Since . the RHR SDC piping on the discharge side of the pump is the same as the Low Pressure Coolant Injection piping,

• performances of surveillances for ECCS TS may satisfy the requirements of this surveillance. For the RHR SDC piping on the suction side of the RHR pump, the surveillance is met by virtue of the performance of operating procedures that ensure that the RHR SDC suction piping iS adequately filled and vented. The performance of these manual a ct i on s *en s u re s t h a t t he s u r v e i l l a n c e i s met . RHR SDC System locations on the discharge side of the RHR pump susceptible to gas accumulation are monitored and, if gas is found, gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow which are subject to the same gas i.ntrusion mechantsms may be verified by monitoring a representative subset of susceptible locations, Monitoring may not be practical for locations that are inaccessible. due to radi ol ogi cal or environmental conditions, the pl ant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void
• volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for. monitoring the locations and trending of the results should be to assure OPERABILITY during the interval. The SR can be met by of having an RHR SOC subsystem inservice in accordance with operating procedures. The SR is modified by a Note. The *Note the *scope 6f the survei1lance limited to the RHR system components. The HPSW system*components have-been determined to not be to. be in the scope of this. to operating experience and the design of t h.e *.sy s*t.em. * * * * * * .. -* Surveillance Fr'equenty is controlled under the Surveillance Frequency Control Program. _The Surveillance Frequencj may vary by location *susceptible to gas a.ccumulation..
• None .. * ...... B .3. 4-42a Revision No. 128 . I i I ,. I; RCS PIT Limits B 3.4.9 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.9 RCS Pressure and Temperature CP/T) Limits BASES BACKGROUND PBAPS UNIT 3 All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown Ccooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation. The PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR) (Ref. 9) contains P/T limit curves for heatup, cooldown, and inservice leakage and hydrostatic testing, and also limits the maximum rate of change of reactor coolant temperature. The criticality curve provides limits for both heatup and criticality. Each P/T limit curve defines an acceptable region for normal operation. The usual use of the curves is operational guidance during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and compared to the applicable curve to determine that operation is within the allowable region. The LCO establishes limits that provide a margin to brittle failure of the reactor vessel and piping of the reactor coolant pressure boundary (RCPB). The vessel is the component most subject to brittle failure. Therefore, the LC 0 l i m.it s a pp l y to th e v e s s el. 10 CfR 50, Appendix G (Ref. 1), requires the establishment of P/T limits for material fracture toughness requirements of the RCPB materials. Reference 1 requires an adequate margin to brittle failure during normal operation, abnormal operational transients, and system hydrostatic tests. It mandates the use of the ASME Code, Section III, Appendix G (Ref. 2) .. The actual shift in the RTrrnr of the vessel material wi 11 be established periodically by removing and evaluating the irradiated reactor vessel material specimens, in accordance with the UFSAR (Ref. 3) and Appendix H of 10 CFR 50 (Ref. 4). The operating P/T limit curves will be adjusted, as necessary, based on the.evaluation findings and the recommendations of Reference 5. continued B 3.4-43 Revision No. 102 I I. I I I' BASES BACKGROUND (continued) .... -APPLICABLE SAFETY ANALYSES ::.**.---.*:-, .. *. PBAPS UNIT 3. RCS PIT Limits B 3.4.9 The P/T limit curves are composite curves established by superimposing limits derived from stress analyses of those portions of the reactor vessel and head that are the most restrictive. At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span of the P/T limit curves, different locations are more restrictive, and, thus, the curves are composites of the most restrictive regions. The heatup curve represents a different set of restrictions than the cool down because the directions of the thermal* gradients through the vessel wall are reversed. The thermal gradient reversal alters the location of the tensile stress between the outer and inner walls. The criticality limits include the Reference 1 requirement that they be at least 40°F above the heatup curve or the cool down curve and not lower than 60°F the adjusted reference temperature of the reactor vessel material in the
• regibn is controlling (reactor vessel flange regi6n). The _consequence of vi.olating the LCO limits is that .the RCS his been operated under c6nditions that can result in failure of the reactor pressure vessel, possibly *leading to*a loss 6f coolant accident. In the event these limits are exceeded, an evaluation must be performed to. the effect on integrity o.f the RCPB compo,nents. ASME Code, Section XI, Appendix E (Ref, 6), provides a retommended methodology for. an operatin9 event that an excursion* outside the limits. The PfT limi.ts are not .. derive.d from Design Bas.is Accident {OBA) 'analyses*. They ar"e.prescr.ibe.d *during norma1' operatton* to ... _avo:i d eilco1Jnteri ng pressure; tempe.rature, and temperature. *_rate of chai:ige condTtion*s that might cause .undetected flaws* to propagate ari'd cause nonductile failure of the reactor pressure vessel., *a c6.nd it ion that is . unanalyzed: .Since. the P/T are hot OBA; are no* acceptance -limits related fhe PIT l i m.its. Rather, the. PJT limits are limits since they preclude operq ti on in an unanalyzed condition.* * ; **" ( contirfued) -.. , .. '. :, _..,. . . . B :3. Revision No.* J02 BASES APPLICABLE SAFETY ANALYSES (continued) LCO ., -' . **:.* ' PBAPS UNIT 3. RCS PIT Limits B 3.4.9 RCS P/T limits satisfy Criterion 2 of the NRC Policy Statement. The elements of this LCO are: a. -RCS pressure and temperature are within the limits specified in the PTLR and heatup and cooldown rates are within the limits specified in the PTLR; b. The temperature difference between the reactor vessel *bottom head coolant and the reactor pressure vessel (RPV) coolant is within the limits specified in the PTLR during pump startup; -c. The temperature difference between the reactor coolant in the respective recirculation loop and in the reactor vessel is within the limits specified in the PTLR during reci_rculation pump startup; d., RCS pressure and temperature are within the criticality. limits Specified in the-PTLR, prior to ***achfeving criticality; and e. reactor vessel flange and the head flange temperatures are *within the limits specified in the PTLR when tensioning the reactor vessel head bolting studs. These limits define operating regions and permit a large number of operating cycles while also providing a wide . marg.i:n to nonductile: fai_lure.* The rate of chCIJJge of :temperature limits Controls the -thermal: gradi el']t through the v_essel wan* and is used as input for calculating the cooldown:-and 1 eak.ageand hydrostat=i c t\:!sti ng P/T limit: curves. -the LC.O for the rate of change.of temperature Yeslricts stresses caused by.*the_rmal gradients and also ensures.the validity of the. P /T* limit curves. continued .. -*:'.-B 3.4-45 .Revtsfon-No. 102 BASES LCO (continued) APPLICABILITY ACTIONS . *PBAPS UN IT 3 RCS P/T Limits B 3.4.9 Violation of the limits places the reactor vessel of the bounds of the stress analyses and can increase stresses in other RCS components. The consequences depend on several factors' as follows: a. The severity of the departure from the allowable operating pressure temperature regime or the severity of the rate of change of temperature; b*. The length of time the limits were violated (longer violations allow the temperature gradient in the thick vessel walls to become more pronounced); and c. The existences, sizes, and of flaws in the vessel mat er i al . The potential for violating a P/T limit exists at all times, For example, P/T limit violations could result from ambient temperature conditions that result in the reactor vessel metal temperature being less than the minimum allowed temperature for boltup. Therefore, this LCO is ipplicable even when fuel is not loaded* in the core. A.l and A.2 outside the P/T in the PTLR in MODES 1, 2, and 3 must be corrected so that the RCPB is returned*to a condition that has been verified by stress analyses. The *30 minute Completion Time reflects the* urgency of the parameters to within the analyzed range. Most violations will not severe, and the *activity can be accomplished in this time in a controlled Besides restoring operation wfthin limits, an evaluation is required to determine if RCS operation can evaluation must the RCPB integrity remains acceptable and must be completed if continued operation is desired. Several methods may be used, including comparison with pre-analyzed transients in the stress'analyses, new analyses, or inspection of the components. ASME Code, Section Appendix E (Ref. 6), may be used to *support.the evaluation. However, its use is restricted to evaluation of the vessel beltline.
• continued B .3 '.4-46 No: 102 .

BASES ACTIONS *., . PBAPS UN IT 3. A.land A.2 (continued) RCS P/T Limits B 3.4.9 The 72 hour Completion Time is reasonable to accomplish the evaluation of a mild violation. More severe violations may require special, event specific stress analyses or inspections. A favorable evaluation must be completed if continued operation is desired. Condition A is modified by a Note requiring Required Action A.2 be completed whenever the Condition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursinn outside the allowable limits. Restoration alone per Required Action A.l is insufficient because higher than analyzed stresses may have occurred and may have affected the RCPB integrity. B.l and B.2 If a Required Action and associated Completion Time of Cbndition A are not met, the plant must be placed in a lower MODE because either the RCS remained in an unacceptable.PIT region for an extended period of increased stress, or a. sufficiently severe event caused into an unacceptaple region. Either indicates a need for more* careful examination of the event, best accomplished with the RCS at reduced pressure and With the reduced pressure and temperature conditions, the possibility of propagation of undetected flaws is decreased. Pressure.and temperature are reduced by placing the plant in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. *The allowed Completion Times are reasonable, ba?ed on operating .experience, to reach the r*equired plant con di ti ans from full power conditions in an.orderly man.ner ind without systems. C.( and C.2 Operation the P/T limits in the PTLR in other than MODES 1, 2, and. 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses. The Required Actibn without delay and continued until the limits a re restored. continued. B 3.4-A7 Revision No:.102 BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 3

• C.l and C.2 (continued) RCS P/T Limits B 3.4.9 Besides restoring the P/T limit parameters to within limits, an evaluation is required to determine if RCS operation is allowed. This evaluation must verify that the RCPB integrity is acceptable and must be completed before approaching criticality or heating up to> 212°F. SeveraJ methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components. ASME Code, Section XI, Appendix E (Ref. 6), may be used t6 support the evaluation; however, its use is restricted to evaluation of the beltline. SR 3.4.9.1 Verification that operation is within the PTLR limits is required when RCS pressure and temperature conditions are undergoing planned changes. Plant procedures specify the pressure and temperature monitoring points to be used during the performance of this Surveillance. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Surveillance for heatup, cooldown, or inservice leakage and hydrostatic testing may be discontinued when the criteria given in the relevant plant procedure for ending the activity are satisfied. This SR has been modified with a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic testing.
• SR 3.4.9.2 A separate limit in the PTLR is used when the reactor is approaching criticality. Consequently, the RCS pressure and temperature must be verified within the appropriate limits before withdrawing control rods that will make the reactor critical. continued .B 3.4-48 Revision No. 102 BASES SURVEILLANCE REQUIREMENTS ,... ' :.: PBAP-S-UN IT 3 SR 3.4.9.2 RCS PIT Limits B 3.4.9 Performing the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal. SR 3.4.9.3 and SR 3.4.9.4 Differential temperatures within the applicable limits in the PTLR ensure that thermal stresses resulting from the startup of an idle recirculation pump will n6t exceed design allowances. In addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation loop (Ref. 8) are satisfied. the_Surveillance within 15 minutes before starting the idle recirculation pump .provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the idle pump* st a-rt. *An acceptable means of* demonstrating compliance with the differential in SR 3.4.9.4 is to_ compare the temperatures of the operating recirculation loop and the idle . . -' . . . . . SR and SR 3,4.9.4 have been modified by a Note that requires the Surveillance to met only in MODES 1, 2, 3, and 4. In MODE 5, the overall stress on--iimiting components 'is l o,wer.
• Therefore, t1J limits are not required. _ The Note al so stqtes the SR is only required -to be met during a 'reci rcul ati'dn' pump startup, 'since this is whe*n the stresses occur. -. -:---_.SR S'R 3.'4.9.6'. SR 3:'4.-9:7 *Limits iri the PTLR on the reactor flange and head flange' tem'peratu-res are generally bounded by the other PiT-1 imit's during' s.Ystem heatup and .tool down. However, -bperatfons approaching. MODE 4, from MODE 5 and in MODE 4 with RCS.temperature. less than qr equal to certain specified values require assurance that these temper-a tu res meet the_ -_-.L;C6 _.J .j ini t:s*. .. , ... ..* -*
• con-ti nued * ...... B .3. 4-49 --Rev i s i on N o . -10 2 /:.

BASES REFERENCES (continued) PBAPS-UN I_T 3 RCS P/T Limits 8 3.4.9 6. ASME, Boiler and Pressure Vessel Code, Section XI, Appendix E. 7. DELETED 8. UFSAR, Section 14.5.6.2. 9. PRESSURE AND TEMPERATURE LIMITS REPORT. ,*, . 8"3.4-51 Rev i s i .on Na*. 10 2 Reactor Steam Dome Pressure B 3.4.10 B 3.4 REACTOR COOLANT SYSTEM (RCS) B 3.4.10 Reactor Steam Dome Pressure .BASES APPLICABLE SAFETY ANALYSES APPLICABILITY UN IT 3 --*--, The reactor steam dcime pressure is an assumed value in the determination of with reactor pressure vessel overpressure protection criteria and is also an assumed initial condition of design basis accidents and transients. The reactor steam dome pressure of s 1053 psig is an initial condition of the vessel overpressure protection analysis of Reference 1. This analysis assumes an initial maximum reactor steam* dome pre*ssure and evaluates. the response of the pressure relief system, primarily the safety/relief valves, during the limiting pressurization transient. The determinatfbn of compliance wilh the overpressure criteria is dependent on the initial reactor steam dome pressure; therefore, the limit on this pressure ensures that the assumptions of the overpressure protection analysis are conserved. Reference 2 along Reference 1 assumes initial reactor steam dome pressure for the analysis of design basis acci*dents and used tc determine the limits .for fuel cladding integrity (see for LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)") and 1% cladding plastic strain (see Bases for LC.O 3.2.3, "LINEAR

• 1 HEAT GENERATION RATE CLHGR)"). . Reactor steam dome pressure satisfies the requirements of 2 of the NRC Policy Statement. The. specified reactor steam dome pressure l im*i t of. s i053 psig ensures the plant is operated within the assumptions of reactor overpressure protection analysis . . Operation above the limit result in a transient response more severe than analyzed. In MODES.land 2, the reactor steam dome is required to be less than or equal to the limit. In these MODES, the may be generating steam and the events which may challenge the overpressure limits are possible. (continued) B 3 .A .. -52 Revhion No: 50 I, I; I I I I;** .. ;\I * * *. 1' BASES APPLICABILITY (continued) ACTIONS SURVEILLANCE_ REQUIREMENTS REFERENCES PBAPS u*Nrr 3 Reactor Steam Dome Pressure B 3.4.10 In MODES 3, 4, and 5, the limit is not applicable because the reactor is shut down. In these MODES, the reactor pressure is well below the required limit,. and no anticipated events will challenge the overpressure limits. With the reactor steam dome pressure greater than the limit, prompt action should be taken to reduce pressure to below the limit and return the reactor to operation within the_ bounds of the analyses. The 15 minute Completion Time is reasonable considering the importance of maintaining the pressure within limits. This Completion Time also ensures -that the probability of an accident occurring while pressure is greater than the limit is minimized. If the reactor steam dome pressure cannot be restored to within the limit the associated Completion Time, the plant must be brought to a MODE in which the LCD does not
• apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion* Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power tonditions in an orderly manner and* without challenging plant systems. SR 3.4.10.1 Verification that reactorsteam dome pressure is :;; 1053 psig the initial conditions of the reactor _overpressure protection-*analysis and-design basis accident's are met. The Surveillance Frequency is controlled Survei i lance Frequency coritrol Program. 1. 2: NEDC-33566P,_ "Safety Analysis Report for Exelon Pea.eh Bottom Power Station Units 2 and 3, Constant Pressure Power Uprate," Revision o .. UFSAR, Chapter 14. B 3.4-53 Revision No. 1I9 I r -ECCS-Operating B 3.5.1 B 3. 5 EMERGENCY CORE COOLING SYSTEMS ( ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.1 ECCS-Operating* BASES .BACKGROUND P8APS lJNIJ. 3 .-; The ECCS are designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The ECCS network consists of the High Pressure Coolant Injection (HPCI) System, the Core Spray (CS) System,, the low pressure coolant injection (LPCI) mode of the Residual Heat Removal *(RHR) System, and the Automatic Depressurization System (ADS}. The suppression pool provides the required source of water for the ECCS. Although no credit is taken in the safety.analyses for the condensate storage tank (CST), it is capable of providing a source of water for the HPCI and CS systems. On receipt of an initiation signal, ECCS pumps automatically start; simultaneously, the system aligns and the pumps inject water, taken either from the CST or suppression pool, into the Reactor Coolant System (RCS) as RCS pressure is . overcome by the discharge .pressure of the ECCS pumps. Although the system is initiated, ADS action is delayed, allow1ng the operator to interrupt the timed* sequence if the system is not needed. The HPCI pump discharge pressure almost immediately exceeds that of the RCS; and the pump irijects coolant into the vessel to cool the core. If the *break is small, the HPCI System will maintain coolant inventory *as.well as vessel level while the RCS is still pressurized. If HPCI fails, it is backed up by ADS in combination with LPCI and CS.. In this event, the ADS timed sequence would be allowed to time out and open the selected safety/relief valves (S/RVs) depressurizing the RCS, thus allowing the LPCI and CS to overcome RCS pressure and inject coolant into the vessel. If the break is large, RCS pressure initially drops rapidly and the LPCI and CS cool the core. * . Water from the break returns to the suppression pool where it is used again and* again. Water in the suppression pool* is circulated through an RHR System heat exchanger cooled by the High Pressure Service Water System. Depending on the location and size of the break, portions of the ECCS may be (continued) B 3.5-1 Revision No. 0 r r BASES BACKGROUND (continued) . -.:.-ECCS-Operating B 3.5.1 ineffective; however,the overall design is effective in cooling the core regardless of the size or location of the piping break. All ECCS subsystems are designed to ensure that no single active component failure will prevent automatic initiation
• and successful operation of the minimum required ECCS equipment. The CS System (Ref. I) is composed of two independent subsystems. Each subsystem consists of two 50% capacity motor driven pumps, a spray sparger above the core, and piping and valves to transfer water from the suppression pool to the.sparger. The CS System is designed to provide cooling to the reactor core when reactor pressure is low.
• Upon receipt of an initiation signal, the CS pumps in both subsystems are automatically started (if offsite power is .available, A and C pumps in approximately 13 seconds, and B and D pumps in approximately 23 seconds, and .. if offsite power is not all pumps 6 setonds after AC power is available). When the RPV pressure drops sufficiently; CS System fl ow. to the RPV begins.* A ful 1 fl ow test line is
• provided to route from and to the *pool to allowtesting of the CSSystem.wi.thout*spraying water iri the '*. RPV. . . LPCI is an :independent operatfi1g mode of the RHR System. are t.wo LPCl subsystems (Ref .. 2), each consisting of .. two motor driven' pumps and.piping and valves* to transfer* ..
• water from the pool to. the* RPV via the . correspoi1di ng re.ci rcul ati on loop.** The two LPC I pumps and associated m9tor.operated in each .LPCI.subsystem are fr::om separate 4 :kV emergen.cy .buses. *Both pumps in a LPCI subsystem inject water *into the reactor ,vessel through . aconimon*inboard.h1jec:tion*valve and depend on the closure of th_e-}'.'eci rcul ation pump: discharge valve fo Tl owi rig a _LPCl each LPCl subsystems' common fnboard:-injec:tfon valve and*. recirculation pump discharge* ..
• v_al ve* 1$ from c:me of the. two 4-k.V eniergeilcy buses * *'associated with that_ subsysfeni (normal .source} 'and has*the capabi.l itY *:for .automatic transfer to the second 4 kV
• emergenc.Y':bus *associatecj with* that LPCL . The. ability to provide power to the inboard injection valve*and the r!;!Circulatton pump (jischarge valve from *e*ither 4 kV _eiile}"g(;?.ncy bus .:associated with the lPCl *subsystem ensures,* . that _th*e s.ingle .failure of a diesel .genercitor <.(DG) will not* . resultjh the failure *Of i:>oth LPCI pumps .in. one subsystem . '" *> *. .. (continued) .. * . . Revision No; 0 */

, *_ BASES BACKGROUND (continued) -, *-. -..::" PBAPS UN IT 3 ECCS-Operat i ng B 3.5.1 The two LPCI subsystems can be interconnected via the LPCI cross tie valve; however, the cross tie valve is maintained closed with its power removed to prevent loss of both LPCI subsystems during a LOCA. The LPCI subsystems are designed to provide core cooling at low RPV pressure. Upon receipt of an initiation signal, all four LPCI pumps are automatically started (if offsite power is available, A and B pumps in approximately 2 seconds and C and D pumps in approximately 8 seconds, and, if offsite power is not available, all pumps immediately after AC power is available). Since one DG supplies power to an RHR pump in both units, the RHR pµmp breakers are interlocked between units to* prevent operation of an RHR pump from both units on one DG and potentially overloading the affected DG. RHR System valves in the LPCI flow path are automatically positioned to ensure the proper flow path for water from the suppression pooi t6 inject into the recirculation loops. When the RPV pressure drops sufficiently, the LPCI flow to RPV, via the corresponding recirculation loop, begins. The water then enters the reattor through the jet pumps. Full flow test lines are provided for the four LPCI pumps to route water to the suppression pool, to allow testing of the LPCI pumps without injecting water into the RPV. These test lines _also provide suppression pool cooling capability, as described in LCO 3.6.2.3; "RHR Suppression Pool Cooling." ' ' -. The HPCI System (Re(. 3) consists of a turbine pump unft, piping, and to pr6vide steam to the turbine, as* well as piping and valves to fransfer water from the source to via the feedwater system line, 'where the cool ant is distributed within the RPV

• through-the feedwater sparger. for the system .. is pro Vi ded from the CST and the sµppressi on pool. Pump for HPOI is aligned to the CST source to minimize.injection of:suppression pool water into the RPV. However; ff the. cs*T ,water supply *is low, cir if the suppression pool level *is high, an automatic. transfer to the suppt".ession poo_l water source ensures a water supply for continuous* operation of the HPCI System. *The steam supply to the"HPC'I turbih_e*is pi°ped from a main steam line upstream o( the steam isolatiun HPCi ts to provide cooling for a fange of reattor pressures (150 psig to 117Qpsig). I .*. Upofr receipt of' ah signal ,_the HPCI turb1ne *stop valve *and turbine.control valve. cipen and the turbine .. acce1e*rates to*a specified As the*HPCI flow continued .. . Revi si.on No-; !JO 1, i . I *; I' '< BASES . BACKGROUND (continued) . APPLICABLE SAFETY ANALYSES PBAPS UN IT 3 ECCS-Operati ng B 3.5.1 increases, the turbine goverrior valve is automatically adjusted to maintain design flow. Exhaust steam from the HPCI turbine is discharged to the suppression pool. A full flow test line is provided to route water to the CST to allow testing of the HPCI System during normal operation without injecting water into the RPV. The ECCS pumps are provided with minimum flow lines, which discharge to the suppression pool. The valves in these lines open to prevent pump damage due to overheating when other discharge line valves are closed. to ensure rapid delivery of water to the RPV and to minimize water hammer effects, all ECCS pump discharge lines are filled with water. The LPC1 and CS System discharge lines are kept full of water using a "keep fill" system. The. HPCI System is normally aligned to the CST. The height of water in the CST is sufficient to maintain the piping full of water up to the first isolation valve. The relative height of the feedwater line connection for HPCI is such that the water in the feedwater lines keeps the remaining portion of the HPCl discharge full of water. HPCI does not require a "keep fi 11" system when aligned to the CST. A connection* to the CST maintains HPCI full when HPCI is aligned to the torus, and the CST level is at or above elevation 149'-6". (14.5' above tank bottom). The Pressure Rel.ief System consists of 3 safetY valves (SVs) and 11 safety/relief valves ($/RVs). The ADS (Ref. 4) consists. of 5 of the 11 S/RVs. It is designed to provide of the RCS a small break LOCA if HPCI fails or is unable to maintain required water level in the' RPV. ADS .opera ti on reduces the RPV to the operating pressure range of low pressure ECCS subsystems (CS and LPCIJ, so that these subsystems can provide coolant inventory makeup. Each of the S/RVs used for automatic depressurization is equipped with one nitrogen accumulator and associated inlet check valves. The accumulator prcivi_des the pneumatic power to actuate the valves . The ECCS performance is evaluated for the entire spectrum of break sizes for a postulated LOCA. The accidents for which ECCS operation is required are presented in Reference 5. The analyses and assumptions are defined in 6. The analyses-are in 7, 14 and 15. continued B
• Revi.si on Nci .. 127

.. *.: .. BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS WN-IT 3 ECCS-Operating B 3,5.1 This LCO helps to ensure that the following acceptance criteria for the ECCS, established by 10 CFR 50.46 (Ref. 8), will be met following a LOCA, assuming the worst case single active component failure in the ECCS: a. Maximum fuel element cladding temperature 2200°F; b. Maximum cladding oxidation 0.17 times the total cladding thickness before oxidation; c. Maximum hydrogen generation from a zirconium water reaction 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding surrounding the fuel, excluding the cladding *surrounding the plenum volume, were to react; d. The core is maintained .in a coolable geometry; and e. Adequate long term cooling capability is maintained. The limiting single failures are discussed in References 7, 14, and 15. The remaining OPERABLE ECCS subsystems provide* the capability to adequately cool the core and prevent excessive fuel damage.

• The ECCS satisfy 3 of the NRC Policy Statement._ Each ECCS injection/spray subsystem five ADS are required t6 be OPERAaLE. *The ECCS injectibn/spray subsystems are defined the two CS subsystems, the two LPCI and one System: The 16w pressure ECCS injettion/spray are .defined as the two CS and the CPCI Management of . voids is important ECCS injection/spray subsystem OPERABILITY. With less than the number of ECCS iubsystems ... *. * .. OP_ERABLE, the potential exists that during a limiting basis LOtA concurrent with the worst case single failure,
• the limits specified in Reference 8 c6uld be exceeded. All ECCS subsystems must be OPERABLE to satisfy the single by 8. .is ihoperable al{gnment and opera ti-on* f*or. decay heat removal when below the actuaJ *.* RHR shutdown cooling isolation pressure in* MODE 3, sinte .** ..
• transferring from the shutdbwn cooling mode to the LPCI mode.* could r_esu*lt in pump cavitation and voiding-1n the suction . coritinued _.: '.-' B 3.5-5 *Revision ND. 12ff BASES LCO (c9ntinued) APPLICABILITY ACTIONS .. PBAPS WNJT 3 ECCS-Operati ng B 3.5.1 p1p1ng, resulting in the potential to damage the RHR System, including hammer. This is necessary since the RHR . System is required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. At these low pressures ahd decay heat levels, a reduced complement of ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling when necessary. One LPCI subsystem shall be declared inoperable when M0-34A(B) and M0-39A(B) are simultaneously open in the same subsystem (one or both subsystems) with no Emergency Diesel Generators (EDGs) declared inoperable to ensure compliance to References 7, 14, and 15. single failure analyses (Ref. 11). If the M0-34A and M0-39A are simultaneously open, the 'A' *subsystem of LPCI shall. be declared inoperable unless the E-1, E-2, or E-4 EDG is declared inoperable. If the M0-34B and M0-39B are simultaneously open, the 'B' subsystem of LPCI shall be declared inoperable unless the E-1, E-2, or E-3 EDG is declared *All ECCS subsystems are required to be OPERABLE during MODES 1, 2, and 3, when there is considerable energy in the reactor core and core cooling would be required to prevent fuel damage in the event of a break in the primary system piping. In MODES 2 and J, when reactor steam dome pressure is s 150 psig, HPCI is not required to be OPERABLE because .the low pressure ECCS subsystems can provide sufficient flow below pressure. In MODES 2 and 3, when reactor steam dome pressure is s 100 psig, ADS not required to be OPERABLE because the low pressure ECCS subsystems can sufficient flow below this pressure. ECCS requirements for MODES 4 and 5 are specified in LCD 3.5.2, "ECCS-Shutdown." A Note prohibits the application of LCD 3.0.4.b to an inoperable HPCI subsystem. There is an increased risk with entering a MODE or other specified condition in the Applicability with an HPCI subsystem and the provisions of LCD 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCD not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance. continued B 3.5-6 Revision No. 112

! ' I .. *:". BASES ACTIONS (continued) PBAPS UNIT' 3 -* A .1 ECCS-Operati ng B 3.5.1 If any one low pressure ECCS injection/spray subsystem is inoperable, or if one LPCI pump in each subsystem is inoperable, all inoperable subsystems must be restored to OPERABLE status within 7 days (e.g., if one LPCI pump in each subsystem is inoperable, both must be restored within 7 days). In this Condition, the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced, because a single failure in one of the rematning OPERABLE subsystems, concurrent with a LOCA, may result in the ECCS not being able to perform its intended safety function. The 7 day Completion Time is based on. a reliability study (Ref. 9) that evaluated the impact bn ECCS availability, assuming components and subsystems were taken out of service. The results were used to 'calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times (i.e., Completion Times).

• continued .,* ;. . .. . '" ... -*--: '*' --.-, .. ,* -B 3.5-6a. Revision N6. *I BASES ACTIONS (continued) ..,.**.*-,--PBAPS_.lJNIT 3 . EC CS -Opera ti n g B 3.5.1 If the low pressure ECCS subsystem cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 12) and because the time spent in MODE 3 to perform the necessary repairs to restore the syitem to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions full power conditions in an orderly manner and without challenging plant systems. C.l and C.2 If the HPCI System is inoperable and the RCIC System is immediately verified to be OPERABLE, the HPCI System must be restored to OPERABLE status within 14 days. *In this Condition, adequate core cooling is ensured by the . OPERABILITY of the redunHant and diverse low pressure ECCS injection/spray subsystems in conjunction with ADS. Also, the RCIC System will automatically provide makeup water at most reactor operating pressures. Immediate verification of RCIC OPERABILITY is therefore required when HPCI is . inoperable. This may be performed as an* administrative check by examining logs .or other information to determine if RClC is out of service for maintenance or other reasons. It does nbt mean to perform the Surveillances needed to * *.-demonstrate the OPERABILITY of the RCIC System. If the OPERABILITY* of the.RCIC 'System cannot be ve_rified immediately, however, Condition G must be immediately* I entered: If .a sJngle* :gcJ*i"ve component fails concurrent with a design basis JOCA, there *is a potenti"al, .depending on the* specific failure, 1he minimum required ECCS equipment will .noLb.e available. A 14 day Completion Time is based on a li tY study cited' in Reference 9 a_nd has been found to be thFough experiehte. D.1 a*niJ 0;2 IJ anYone low pressureECCS injection/spray*subsystem_is . i n ope r,a b l e i. n add i ti on to an i n ope r a b l e H PC I. Sy s t em , the *inoperabre io*w pressure.E.CCS. injection/spray subsystem *or ... th*e HPCL System must be res:tored :to *OPERABLE status within 72 hqur.s. *rn this Cqndition, -adequate core cooling is .*. :-. (continued){ B .3 .-5 Revis fon No. 89 I ' BAS.ES ACTIONS PBAPS UN IT 3 D.1 and D.2 (continued)
• ECCS-Operati ng B 3.5.1 ensured by the OPERABILITY of the ADS and the rema1n1ng low pressure ECCS subsystems. However, the overall ECCS reliability is significantly reduced because a single failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function. Since both a high pressure system (HPCI) and a low pressure subsystem are inoperable, a more restrictive Completion of 72 hours is required to restore either the HPCI or the low pressure ECCS injection/spray subsystem to OPERABLE status. This Completion Time is based on a reliability study cited in Reference 9 and has been found to be acceptable through operating experience. The LCO requires five ADS valves to be OPERABLE in order provide the ADS function .(Refs. 7, 14, and 15) .. A single failure in the OPERABLE ADS valves results in a reduction in depressurization capability. The. 14 day Completion Time is based on a reliability study cited in Reference 9 and has
• been found to be acceptable thrbugh experierice. F. 1 andF. 2 If any one low press.ure 'ECCS injection/spray subsystem 'is. in additibh to one inoperable ADS valve, adequate core cooling is ensured by the OPERABILITY of HPCI and the remaining low pressure injection/spray subsystem.
• However; overall ECCS reliability is reduced.because a single active combonent failure concurrent with a design basis LOCA could result in the minimum required ECCS equipment not being Since both a high pressure system (ADS) and a low pressure subsystem are inoperable, a more restrictive Completion .Time* of 72 hours is required to restore either the low pressure ECCS subsystem or ADS valve to OPERABLE status.* This Completion Time is based on a reliability study cited in Reference 9 and has been found to be acceptable operating experience. continued B . Revision 101
• I I .";*; .. _..*. *.'" .*I. BASES ACTIONS (continued) SU RV EI LLANCE REQUIREMENTS PBAPS UNIT 3 ECCS-Operat i ng B 3.5.1 If any Required Action and associated Completion Time of Condition C, D, E, or Fis not met, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 12) and because the time spent in MODE 3 to perfbrm the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state; The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant sjstems. H.1 and H.2 If two or more ADS valves are inoperable, there is a reduction in the depressurization capability. The plant must be brought to a condition in which the LCO does not applj. To achieve status, the plant be brought to at least MODE 3 within 12 hours and reactor steam dome pressure reduced to = 100 psig 0ithin 36 hours. The allowed Completioh Times are reasonable, based on operating experience, to reach the required plant. conditions from full power conditions in an orderly manner and* without challenging* plant systems. . . ECCS are inoperable (for reasons ot'her than the second Condition of Condition A), as stated in Condition I, plant'is in a ccihdition outside of the accident analyses. Therefore, LCO 3. O. 3 must' be entered * < .. SR 3.5.1.1 The ECCS injection/spraj flow path p1p1ng and components have.the potential to develop voids and pockets.* of en.trained gases. **Preventing and.managing gas i ntrusi cin
• qncj accumul !3t) on .is necessa.rY for proper operat1 on of the continued.* B 3.5-9 Revision No. l28:

I 1:, *'.** I 1 .*.. .*'. BASES SURVE-I LLANCE REQUIREMENTS* PBAPS UNIT 3 SR 3.5.1.1 (continued) ECCS-Operat i ng B 3.5.1 ECCS injection/spray subsystems and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel . Selection of ECCS injection/Spray subsystem locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. *The ECCS injection/spray subsystem is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the ECCS subsystems are not rendered inoperable by the accumulated gas Ci .e., the system is filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance* criteria limits. ECCS injection/spray subsystem locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow *path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g.; operating parameters, remote monitoring) may be used continued B 3.5-10 Revision No. 129 BASES SURVEILLANCE REQUIREMENTS . ' :-.:* -: _. : *-*--. PBAPS UN IT 3 B 3.5.1 SR 3.5.1.1 (continued) to monitor the location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPfRABILITY during the Surveillance interval. / The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Frequency may vary by location susceptible to gas accumulation. SR 3.5.1.2 Verifying the correct alignment for manual, power operated; and automatic valves in the ECCS flow paths provides *assurance the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, or otherwise secured in position since these

• were verified to be in the. cor.rect posi ti.on prior to locking, sealing, or
• A val0e that receives an initiation is to be in a nonaccident position will automatically reposition in* the *time. riot YequiFe any testing or valve man.ipulation;*rather; it involve$ v.erification that
• those varve's capable of" potentially being mispositioned are in the correct position. This SR-does hot to valves* tha*t carinot be*inadvertently*rilisaligned; such as check .* tor the SR inc1udes
• steam fl ow *path for the turbine and* the. fl ow controller position. For RHR' heat
• exch.irhger inlet.flow 'control valve i_s p*O"sitioned to achieve*. at least .. the minimum flow r.ate required_by SR 3.5.1.7 .. -. . . --. . .. -' . . --.-' -Th e S u r v e i 11 a n ce .Freq u en cy i s c b n t r o l l e d u n de r t h e
• Cont;ol ;Program. . -. . The is fied by a Note which system:* \'.e.:nt .fl ow: paths* opened under.,_admi ni strati ve control. The ..... admi ni st rat i-ve" cOritrol shou:1 d be procedural i zed and incl Ude. stati onirig an i n'dtvi dual who can rapidly cfose the system vent:.fldwp'ath H directed.'** .. *. C-conti nued} -"( B 3 .. 5-lOa RevisionNo.128 I .

BASES S U RV E I L LAN C E REQUIREMENTS (continued) PBAPS UN IT 3 SR 3.5.1.3 ECCS-Operat i ng B 3.5.1 Verification that ADS nitrogen supply header pressure is 85 psig ensures adequate*air pressure for reliable ADS operation. The accumulator on each ADS valve provides pressure for valve actuation. The design pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure (Ref. 10). The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure 85 psig is by the ADS instrument air supply. The *Surveillance Frequency is controlled under the Surveillance Frequency Control.* Program.

• SR 3.5.l.4 Verification that the LPCI cross tie valve is closed. and power to its operator disconnected that each LPCI subsJstem remains independent and a failure of the flow path in one the flow path of the other LPCI subsystem. Acceptable methods of removing power to the operator include de-epergizing breaker control power or racking out or removing the breaker. If the LPCI cross tie va.l ve is. *open or power has not been removed from the valve operator, btith LPCI must be The Surveillarice Frequency is controlled the Surveillihce Control Program:
• continued :-: ,* *.*:--B Rev i s i 6 n . No . i3 7 BASES SURVEILLANCE . REQUIREMENTS (continued) *,.I PBAPS: UNIT 3. SR 3. 5 .1. 5 ECCS -Operating B 3.5.1 Cycling the recirculation*pump discharge valves through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will close when required. Upon initiation of an automatic LPCI subsystem injection signal, these valves are required to be closed to ensure full LPCI subsystem flow injection in the reactor via the recirculation jet pumps. De-energizing the valve in the closed position will also ensure the proper flow path for the LPCI subsystem. Acceptable methods of de-energizing*the valve include de-energizing breaker control power, racking the breaker or removing the breaker, If the is inoperable and in the open position, the associated LPCI subsystem must be declared inoperable. The Frequency of SR is in accordance with the Inservice Testing Program. SR 3. 5 .1. 6 Verification of the automatic transfer between the normal and the alternate power source (4 kV emergency bus) for each LPCI subsystem injection valve and each recirculation pump discharge v_alve demonstrates that AC power will .be available t6 operate valves loss of power to one of the 4 kV emergency buses. The .abilit.y to provide power to the inboard injection va*l ve and. the recirculatiofr pump discharge valve from either 4 kV emergency*bus associated the LPCI subsystem ensures that,the s{ngle failure of an DG will ncit in the (continued) B 3. S--'12.

BASES SURVEILLANCE REQUIREMENTS PBAPS. UNIT 3 SR 3.5.1.6 (continued) ECCS-Operating B 3.5.1 failure of both LPCI pumps in one subsystem. Therefore, failure of the automatic transfer capability will result in the inoperability of the affected LPCI subsystem. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.1.7. SR 3.5.1.8. and SR 3.5.1.9 The performance requirements of the low pressure ECCS pumps are through application of the 10 CFR 50, Appendix K criteria (Ref. 6). This periodic_ Surveillance is performed to verify that the ECCS pumps will develop the flow rates required by the respective analyses., The low pressure ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of Reference 8. The pump flow rates verified against a system head equivalent to the RPV expected during a LOCA. The total system.pump outlet pressure is adequate _to overcome the elevation head pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during a LOCA. These--values may be established by testing or analysis or during preoperational testing. Core spray pump flow surveil*larice -requirements ensure that the flow rates of Reference 7 met. Long term core spray flow requirements (Ref. 13) assured by the of high run out flow -capability. SR 3.5.1.7 _also accdunts-for .any piping leakage. in the system.

• To avoid damaging CS System valves during testing, throttling is not normal1y performed to obtain a system head_ -corresponding to a reactor pressure 105 psig. As such, *SR 3.5-.1.7 is modifieq by a Note to allow use of pump 'curves _ _ to _determine -equivalent varues for -flow .rate and test* pressure for the es in order* to meet the Surveillance Requirement. The Note allows baseline testing at a system -__ head* corresponding to a reactor pressure of 105 psig to be used to an flow value at the normal -pressure. This testing is performed after* any modification or repair that could affect system flow * -character-istics.
• __ The flow,tests for the HPCI System are performed at two _different pressure such that system capability to _ provi-de rated fl ow is tested at. both the higher and l operating ranges of the Additionally, adequate steam flow musi be through the main or turbine bypass -valves to-continue to control reactor C continued) --B Revision'No.-99.

BASES SURVEILLANCE REQUIREMENTS

• PBAPS UNIT 3 ECCS-Operati ng B 3.5.1 SR 3.5.1.7. SR 3.5.1.8. and SR 3.5.1.9 (continued) pressure when the HPCI System diverts steam flow. Reactor steam pressure must be 1053 and 915 psig to perform SR 3.5.1.8 and greater than or equal to the Electro-Hydraul ic Controi (EHC) System minimum pressure set with the EHC System controlling pressure (EHC System begins controlling pressure at a nominal 150 psig) 175 psig to perform SR 3.5.1.9. Adequate steam flow is represented by at least 2 turbine bypass valves open. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Reactor startup is ' allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that HPCI is inoperable. Therefore, SR 3.5.1.8 and SR 3.5.1.9 are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test. The Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.1.10 The ECCS subsystems are required to actuate automatically to their design functions. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCI, CS, and
• LPCI will cause systems or subsystems* to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup and actuation of all automatic valves to their required positions. This SR also ensures that either the HPCI System continued B 3.5-14 Revision No. 132 I. I I I,' I !* .l. 1. 1.! ,* ' : -BASES SURVEILLANCE REQUIREMENTS >-, ,_,-PBAPS UN IT 3 SR 3.5.1.10 (continued) ECCS-Operating B 3.5.1 will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip or, if the initial RPV low water level (Level 2) signal was not manually reset, then the HPCI System will r e s t a rt when t h e RP V h i g h w a t e r 1 e v e l ( Le v e l 8 ) t r i p automatically and that the suction is automatically transferred from the CST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.l overlaps this Surveillance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are and full flow can be demonstrated by recirculation the test line, coolant injection into the RPV is not required during the SR. 3.5.1.11 The' ADS deiignated S/RVs are' tQ actuate *a*utomatically upon receipt of *specific initiation signals. A system functi6nal test is t6 demonstrate that the mechanical porti oils of the ADS *function (i.e. , solenoids) operate as designed.when initiated either by an actual or signal, causing proper actuation 6f _all *the required SR 3.5.l.ll -the LOGIC.SYSTEM-FUNCTIONAL TEST-perfo_rmed fo LCD 3.3.5.l ove-rl ap this. Survei ll a.nee to provi_de complete testing of the assumed' safety function. The _S*Lfrveil l.ance* Frequency-is. controlled under the -Surveill a'nc'e Frequency Cpntrol Program> . ; .. *(continued) . -\ . * ... -,*_ -.. _, ... . .. -B 3.5-15
• Revfs-i on No. 87 BASES SURVEILLANCE REQUIREMENTS < ,* **:.--PBAPS UNIT 3 SR 3.5.1.11 (continued) ECCS-Operat i ng B 3.5.1 This SR is modified by a Note that excludes valve actuation. This prevents an RPV pressure blowdown. SR 3.5.1.12 The pneumatic actuator of each ADS valve is stroked to verify that the second stage pilot disc rod is mechanically displaced when the actuator strokes. Second stage pilot rod movement. is determined by the measurement of actuator rod travel. The total amount of movement of the second stage pilot rod from the valve closed position to the open position shall meet established by the S/RV supplier. SRs 3.3.5.1.5 and 3.5.1.11 overlap this Surveillance to provide testing of the SRV depressurization mode function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. (continued) ..... . --. .:_' . -/* -'_.-*.**-. _.,,--No. 87 ., ..

I 1* I !i ECCS-Operating B 3.5.l BASES (continued) REFERENCES 1. UFSAR, Section 6 .4. 3. ,._._ . -. .; ... P'BAPS UNIT 3 2. UFSAR, Section 6 .4:4. 3. UFSAR, Section 6 .4 .1. 4. UFSAR, Sections 4.4.5 and 6 .4. 2. 5. UFSAR, Section 14.6. 6. 10 CFR 50, Appendix K. 7. NEDC-32163P, "Peach Bottom Atomic Power Station Units 2 and 3 SAFER/GESTR-LOCA Loss of Coolant Accident Analysis," January 1993. 8. 10 CFR 50.46. 9. Memorandum from R.L. *aaer CNRC) to V. Stello, Jr. CNRC), "Recommended Interim Revisions to LCOs for ECCS Components," l, 1975. 10. UFSAR, Section 10.17.6. 11.

• Issue Report 189167, of RHR while in Test Modes/Torus Cooling. 12. NEDC-32988-A, Revision 2, Technical Justification to -Support Risk-Informed Modification to Selected R.equired *End States for .BWR Plants, Decembef 2002. 13. GE Position Sµmmary Post-LOCA Adequate Cor'e .Cooling Requirements CDRF-E22-00135-0l, Revis-ion 0, November 2000). 14. "Peach Bottom.Atomic Power Station Units 2 & 3 GNF2 ECCS-LOtA GE Hitachi Nuclear Energy, 0000-0100-8531-Rl, _March 2011; 15. G-080-VC-272i "Peach Bottom Atomic Power Station LOCA Evaluation for GE14," General Electric Company, GENE-Jll-03716-09-02P, July 2000. -B 3.5-17 Revision No. 101 ECCS-Shutdown B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 ECCS-Shutdown BASES BACKGROUND APPLICABLE SAFETY ANALYSES . LCD PBAPS UNIT 3 . A description of the Core Spray (CS) System and the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System is provided in the Bases for LCD 3.5.1, "ECCS-Operating." The ECCS performance is evaluated for the entire spectrum of break sizes for a postulated loss of coolant accident (LOCA). The long term cooling analysis following a design basis LOCA (Ref. 1) demonstrates that only one low pressure ECCS injection/spray subsystem is required, post LOCA, to maintain adequate*reactor vessel water level in the event of an inadvertent vessel It is reasonable to assume, based on engineering judgement, that while in MODES 4 and 5 one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level. To provide redundancy, a minimum of two low pressure ECCS injection/ spray subsystems are required to be OPERABLE in MODES 4. and 5.
• The low pressure ECCS subsystems satisfy Criterion 3 of the NRC Policy Statement, Tw6. low ECCS injection/spray subsystems are required to be OPERABLE. A low pressure ECCS injection/ spray subsystem of a CS subsystem lPCI
• Each CS*sGbsystem consists 6f two motor driven piping, arid to from the *suppression pool or condensate.storage tank (CST) to the* reactor pressure vessel (RPVJ; Each LPCI subsystem consists of one motor piping, and to transfer from the suppressicin*pool to the RPV. a LPCI. pump is required of the larger injection in relation to a CS subsystem. In MODES 4 and 5, the-LPCI cross tie valve is not required to* be closed; The necessary portions of the Emergency Service
• Water System are also required to appropriate * *
• cooling to each required ECCS subsystem,. as necessary *1* (Reference T_RM *3; li): Management of gas voids ts important .... * *. . to ECCS injection/spray s_ubsystein OPERABILITY.: *
• conti nueci
• B 3.5-18 Revision No. 135.

BASES LCO (continued)

• PBAPS UNIT 3. ECCS-Shutdown B 3.5.2 As noted, one LPCI subsystem may be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned (remote or local) to the LPCI mode and is not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Because of low pressure and low temperature conditions in MODES 4 and 5, sufficient time will be available to manually align and initiate LPCI subsystem to provide core cooling prior to postulated. fuel uncovery. The* following discussion applies when the LPCI cross tie valve (M0-20) is closed: One LPCI subsystem shall not be considered one of the required injection/spray subsystems when M0-34A(B) and M0-39A(B) are simultaneously open in the same subsystem with no Emergency Diesel Generators (EDGs) declared inoperable. As discussed below, an exception to this may be taken if an EOG is declared inoperable. If the M0-34A and M0-39A are simultaneously open, the 'A' subsystem of LPCI shall not be considered as one of the required ECCS injection/spray subsystems unless the E-1, E-2, or E-4 .EOG is declared inoperable. If the M0-34B and M0-39B are simultaneously open, the 'B' subsystem of LPCI shall not be considered as one of the required ECCS injection/spray subsystems unless the E-1, E-2, or E-3 EOG is declared inoperable. The following discussion applies when the LPCI cross tie valve (M0-20) is open: The LPCI cross tie valve (M0-20) cannot be credited for closing during an event to isolate both LPCI subsystems. A pipe break within Primary Containment is assumed when the Reactor Coolant System (RCS) is pressurized. Conversely, a pipe break within Primary Containment is not assumed when the RCS is depressurized. Mode 4 with RCS pressurized: When the Unit is in Mode 4 with reactor steam dome pressure indicating that the RCS is pressurized, then both subsystems of LPCI are inoperable. continued B 3.5-19 Revision No. 96 BASES LCO (continued) *, ,.* P8APS UN iT 3 ECCS-Shutdown B 3.5.2 Mode 4 with RCS depressurized or Mode 5: *.:. . . *'. --, .'. *--,* . ' . * ... M0-34A(B) and M0-39A(B) Closed: When the Unit is in Mode 4 with reactor steam dome pressure indicating that the RCS is depressurized or in Mode 5 AND there are no flow paths that could divert LPCI flow going to the reactor vessel (i.e., M0-34/39 closed), then both subsystems of LPCI can be operable as the required ECCS injection/spray subsystems. M0-34A(8) and M0-39A(8) Open: When M0-20, and M0-39A are simultaneously open, the 'A' subsystem of Core Spray and both subsystems of LPCI cannot be considered as separate ECCS injection/spray subsystems because a single fai-lure (failure of the E-3 EOG) exists that causes the 'A' subsystem of Core Spray and both subsystems of LPCI to be unable to perform their design functions. As a result, the subsystem of Core Spray and both subsystems of* LPCI can only be considered as one of the two required ECCS injection/spray subsystems when aligned in this configurcition. -_ M0-39A simultaneously open with either the E-1, E-2, or E-4 EOG detlared then the 'A' and '8' subsYstems of LPCI credited as being subsystems, since a failure of the E-3 EOG is Ji_ot postt.rl ated'. M0-348, M0-398 simultaneously.open, the 'B' subsystem Of Core Spray and of LPCI cannot be -considered* as separate ECCS injection/spray su,bsystems because a single fai'lure-(failure of EDG}-exi sfs t-hat caus*es the 'B ,. subsystem of --Co.re Spray and' both subsy!:)te-ms of LPCI to unable to perform their design functions.* As a *the ; 8' subsystem of Core Spray and: both of LPCI tan orily as one * &f the: twa _ . 'Subsystems wheir a 1 i gned 1 n this confi gura:ti on: (cont l"nued)
• 8 3.5-19a _ Revision No. 96 -

BASES LCO (continued) APPLICABILITY . . ACTIONS PBAPS UNIT 3 ECCS-Shutdown B 3.5.2 When M0-20, M0-34B, and M0-39B are simultaneously open with either the E-1, E-2, or E-3 EOG declared inoperable, then the 'A' and 'B' subsystems of LPCI may be credited as being *operable, separate subsystems, since a failure of the E-4 EOG is not postulated. OPERABILITY of the low pressure ECCS injection/spray subsystems is required in MODES 4 and 5 to ensure adequate coolant inventory and sufficient heat removal capability for the irradiated fuel in the core in case of an inadvertent draindbwn of the vessel. Requirements for ECCS OPERABILITY MODES 1, 2, and 3 ate discussed in the Applicability section of the Bases for LCO 3.5.1. ECCS subsystems are not be OPERABLE during MODE 5 with the spent fuel storage pool the water level maintained at 458 inches above reactor pressure vessel instrument zero (20 ft 11 inches above the RPV flange), and no operations potential for draining the reactor vessel (OPDRVs) in progress. This sufficient coolant inventory to allow operator action to terminate the inventory loss prior to fuel uncovery in case of an inadvertent draindown. The* Au.tomatic Depressuriz.ation System is not required to be OPERABLE during MODES 4 and 5 because the RPV pressure is s 100 psig, and the CS System .and the LPCI subsystems can provide cooling. without any of the pri ma r.y system. *

• High Pressure Coofant Injection is. not required to OPERABLE during MODES 4 *and 5 sinde the low pressure ECCS can provide sufficient flbw to the vessel . A.l arid B.1 If any low pressure ECCS i nj ecti on/spray. _ is inoperable, inoperable must be *restored to OPERABLE status in 4 hours. *Jn.this Condition,.* .the. OPERABLE subsystem can provide vessel.flooding*capability to recover from:an inadvertent. ve*sse.l draindown. However, o_veralLsystein reliabiHtY is* ***reduced a single failure in the remaining OPERABLE continued . B 3*.5-19b Revi'S.ion No. -9.6* ..

I* !l I .-.:***'* 11., :;.,*.: . .., ':.t .. II . .:'/ .* ,* *: .. .,, BASES ACTIONS -::.**, :. :;*. -.*-.. . . . .... : .. . . -. :,:.* .. :. --. .. -...... _ .. ** '.-*. *-** *,1 __ * ***. * -: .*. A.I and B.l (continued). ECCS-Shutdown

• B 3.5.2 subsystem concurrent.with a*vessel drafndown,could result.in the ECCS not being .able to perform its in.tended function .. , The 4 hour Completfon Time for restoring the required low presst1re ECCS injection/spray subsystem to OPERABLE status
• is based on engineering judgment*that considered the . remaining available subsystem and the low probability of a vessel draindown event.* * . . . . -. With the inoperable subsystem. not restored . to .. OPERABLE status in the required Completion action must be , immediately initiated. to suspend OPDRVs to minimize the: *probability of a vessel draindown and the subsequent
• potential for fission product Actions*must ** continue.until OPDRVs are suspended.
• C. L C'. 2 D .1, D 2; D. 3 . . . With both of *the required ECCS injection/spray subsystems inoperable, all coolant inventory capability maY be unavailable. Therefore, actions must immediately be initfated to suspend OPDRVs to minimize the probab'il ity of* a* vessel draindown arid the subsequent potential for fission . product release. Actions must continue until OPDRVs are suspended. One ECCS .injection/spray subsystem must also be
• restored *to OPERABLE status within 4 . . *
• if at least one Tow pressure ECCS injectiOn/spray subsystem: is . not . restored to OPERABLE* status within the: 4 hour* . CoinpletH>n. Time, .. additional actions are required to minimize any *potentlal fission product release to the *environment .... This*incJudes ensuring secondary containment.ts OPERABLE; one standby gas treatment subsystem for Unit 3. is OPERABLE;
• and* containment isolation capjibility (i.e., one . isolation: valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure ' isolation* capability} in each associated secondary . con'ta i nment penetration fl ow* path not i so 1 ated that is *.assumed to be *isolated to mitigate radioactivity releases. OPERABILITY may be verified by an adminfstrative .check, or by examining logs or other information, to. determirie whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances : neede9 to demonstrate the OPERABILITY *Of the c.omponents .. *;" .. *.* .. (continued) *:* .. -*, Revision No.*: cf * * "* . . *-* . .*-.'*' :.** .. * * . .. , !

I I:. BASES ACTIONS. SURVEILLANCE REQUIREMENTS . ; PBAPS .UNIT 3* C.l, C.2, D.l, D.2, and D.3 (continued) ECCS-Shutdown B 3.5.2 If, however, any required component is inoperable, then it must be Y'estored to OPERABLE status. In this case, the Surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE. The 4 hour Completion Time to restore at least one low* pressure ECCS injection/spray subsystem to OPERABLE status ensures that prompt action will be taken to provide the required cooling capacity or to initiate actions to place the plant in a condition that minimizes any potential fission product release to the environment. SR 3:5.2.l and SR 3.5.2.2 The minimum water level of 11.0 feet required the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CS System and LPCI subsystem pumps, recirculation volume, and vortex.prevention. With the. suppression pool water level less than the required limit, all ECCS injection/spray subsystems are inoperable unless they are aligned to an OPERABLE CST. When suppression pool level is < 11.0 feet, the CS System is .considere.d OPERABLE only:if it can take suction froin ttie CST, and the CST water leVel is sufficient to provide the. required NPSH for the CS pump. a verification that either the suppression pool level is> feet or that CS is aligned -to take suction from the CST and the tST 17.3.feet of water, equivalent to > 90;976 gall-0ns of ensures that CS System can * *.supply at leasf 50,000 gallons 6f water to the The volume of the CST for CS is at the 40;976 * .gallon level. However, as noted,* only one required CS subsystem may take credit for the CST option during OPDRVs. During OPDRVs, the volume .in the CST may not provide . adequate makeup if the RPV were completely drained_. *. Therefore, on 1 y one CS subsystem is a 11 owed to use the CST. This ensures the other required ECCS subsystem has adequate* volume. * * (continued)** * .. *, .. B 3.5-21' Revision No*. 0 : ' BASES SURVEILLANCE REQUIREMENTS PBAPS .UNIT 3 SR 3.5.2.l and SR 3.5.2.2 (continued) ECCS-Shutdown B 3.5.2 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.5.2.3. SR 3.5.2.5. and SR 3.5.2.6 The Bases provided for SR 3.5.1.1, SR 3.5.1.7, and SR 3.5.1.10 are applicable to SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6, respectively. SR 3.5.2.4 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided.the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it *involves verification that those valves capabl.e of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. For the RHR System, verify each RHR heat exchanger inlet flow control valve is positioned to achieve at least the minimum flow rate required by SR 3.5.2.5. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing an individual who can rapidly close the system vent flow path if directed. continued B 3.5-22, Revision No. 128 BASES REFERENCES : ,. _.,*. '* ... . I PBAPS UNIT 3 ECCS-Shutdown B 3.5.2 1. NED0-20566A, "General Electric Company Analytical Model for Loss-of-Coolant Accident Analysis in Accordance.with 10 CFR 50 Appendix K," September 1986. -;., ;. -; , . ... B 3.5-23 *Revision No. 58. .*.** RCIC System B 3.5.3 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.3 RCIC System BASES BACKGROUND . *.----' *-' *': ' .. PB,11.PS *.UNIT 3 --, . The RCIC System is not part of the ECCS; however, the RCIC System is included with the ECCS section because of their similar functions. the RCIC System is designed to operate either automatically or manually following _reactor pressure vessel (RPV) isolation accompanied by a loss of coolant flow from the feedwater system to provide adequate core cooling and control of the RPV water level. Under these conditions, the High Coolant Injection (HPCI) and RCIC systems perform similar The RCIC System design requirements ensure that the criteria of Reference 1 are satisfied. The RCIC System (Ref. 2) consists of a steam driven turbine pump Unit, piping, and valves to provide to the turb'ine, as well as piping and valves to transfer water from thi; suction source to the core via the feedwater system line, where the distributed withi*n the RPV through the feedwater sparger. Suction pipjng is provided from the condensate storage tank (CST) and the suppression _pool. Pump suction is normally aligned to the CST to injection of suppression pool into the RPV. Hoy.iev-er, if the CST water supply is low_, an automatic trans1er to the suppression pool water source water supply for continuous operation of the RCIC System. supply to.the turbine is piped from a main steam line of the* inboard steam line i sol at i on val v-e, . . .-.. : .. ; :. . .... ._ ' ' The RClC_System i.5 designed to provide core cooling for *a wide range of reactor -pressures (150 psig: to 1170 psig).* . I Upo.n receipt of an initiaticiri signal, the RCIC turbine .a.cceierates to*.a specified speed. As* the RCIC flow.

• increases, the turbine governor valv:e .is automatically .. adJustei:Lto maintain design flow. EXhaust steam from the* Rcrc:furbine*is d1sctiarged to the suppression pool: A full *
• f1o0 test line is to route water back to_ CST to , a-llo'{I' testing* of .the* :RC'I c *system during ri_orrha l ope rat idn with ciut inject i rig . water 1° nfo the RPV. (continued) B:3.5-24 110 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES LCO . APPLICABILITY. . PBAPS UN IT 3 RCIC System B 3.5.3 The RCIC pump is provided with a minimum flow bypass line, which discharges to the suppressiOn pool. The valve'.in this line automatically opens when the discharge line are closed. To rapid delivery of water to the RPV and to minimize water hammer effects, the RCIC System discharge piping is kept full of water. The RCIC System is normally to the CST. The height of water in the CST is sufficient to maintain the piping full of water up to the first isolation valve. The relative height of the feedwater line connection for RCIC is such that the water in the lines keeps the remaining portion of the RCIC discharge line* full of water. Therefore, RCIC does not require a "keep fil 1" system. The function of the RCIC System is to respond to transient events by providing makeup coolant to the reactor. The RCIC is not an Engineered Safeguard System no credit is taken in the safety analyses for RCIC System Based on its contribution to the reduction of overall plant risk, h6wever, the system satisfies Criterion 4 of the NRC Policy Statement. The OPERABILITY of the RCIC System provides adequate core cooling such that actuation of any of the low pressure ECCS subsystems is not required in the event of RPV isolation accompanied by a loss of feedwater flow.* Th_e RCIC System has sufficient capacity for maintaining RPV inventory during an isolation event. Management of gas voids important to I RCIC System OPERABILITY: . The RCIC System to be OPERABLE during MODE 1, and 2 and 3 with reactor steam dome pressure > 150 since RCIC is the primary non-ECCS water source for core cooling when the.reactor is isolated pressurized. In MODES 2 and 3 with reactor steam dome 150 psig, and in MODES 4 and 5, RCIC is not required to be OPERABLE since the low pressure ECCS i nj ecti on/spray subsystems. can pro vi de sufficient fl ow to the RPV. (continued) i s i on No . . 12 8 BASES (continued) RCIC System B 3.5.3 ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable RCIC system. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable RCIC system and the provisions of LCO 3.0.4.b, which allow entry into a MODE oj other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance. PBAPS .UN IT 3 A.1 and A.2 If the RCIC System is inoperable during MODE 1, or MODE 2 or 3 with reactor steam dome pressure > 150 psig, and the HPCI System is iffimediately verified to be OPERABLE, the RCIC System must be restored to OPERABLE status within 14 days. In this Condition, loss of the RCIC System will not affect the overall plant capability to provide makeup inventory at high reactor pressure since the HPCI System is the only pressure system assumed to function during a loss of coolant accident CLOCA). OPERABILITY of HPCI is therefore immediately verified when the RCIC System is inoperable. This may be performed as an administrative check, by examining logs or other information, to determine if HPCI is out of service for maintenance or other reasons. It does not mean it is necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the HPCI System. If the OPERABILITY of the HPCI System cannot be verified immediately, however, B must be immediately entered. For certain transients and events with no LOCA, RCIC (as opposed to HPCI) is the preferred soJrce of makeup coolant because of*its small capacity, which.allows easier Control of the RPV water level. Therefore, a limited time is allowed.to restore the RCIC to OPERABLE status. :. . . ' The 1_4 day Completion Time is* based on a reliability 'study (Ref. 3) that evaluated .the* impact on ECCS availability, assuming varioJs components and subsjstems were taken of service. The. results 0ere used to talculate.the average availability of ECCS equipment needed to mitigate the consequences of a*LOCA*as a function *of allowe.d outage times* (AOTs); Because of similar functi.ons of HPCI and RCIC, the AOTs Ci .e., Completion Times) determined for HPCI are also
• applied to RCIC . .ILl If the RCIC System cannot be restored to OPERABLE status withi'nthe.associated CompletionTime,.or if the HPCI Syst.em is simultaneously inoperable, the plant must be brought to: a .cQndition in which the overall plant risk is minimized. To* *I achi e.ve this *status, the pl ant must be brought to at least .. MODE 3 within 12 hours. Remaining in the Appl i ca bi l ity of -I continued .
• B 3.5-26 Revision No .. 67, BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 lL._l (continued) RCIC System B 3.5.3 the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.5.3.1
• The RCIC System flow path p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RCIC System and may also prevent a water hammer, pump cavitation, and pumping of
• noncondensible gas into the reactor vessel. Selection of RCIC System locations susceptible to gas accumulation is based on a review of system design information,*including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. The RCIC System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is *evaluated under the Corrective Action Program. If it is . determined by subsequent evaluation that the RCIC System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or within the acceptance criteria limits. continued B 3.5-27 Revision No. 129

' -.... BASES SURVEILLANCE REQUIREMENTS . . ... PBAPS UNIT 3. SR 3.5.3.1 (continued) RCIC System . B 3. 5. 3 RCIC System locations to gas accumulation are monitored and, if gas i.s found, the gas volume is compared to the acceptance criteria for the location. Susceptible . locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating remote may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and tre.nd*i ng of the results should be sufficient to assure OPERABILITY during the Surveillance interval. The is controlled under the Survetllance Frequency Control Program. The Fretjuency may vary by location susceptible to gas . SR. 3.5.3.2 Verifying* the correct a*1 i gnment for manual , power operated,* and automafic valves in the RCIC flow p*ath provides *

• assurance that th*e proper fl ow path win .exist *for RCIC *operation:; This SR does*not._applf .. to_.valves that are . locked,. 'sealed, or. otherwise secured i ri positfon since these *valves were to be. in. -the correct position prior*to .. loC:king, sealing, or *securing __ A*valv*e that receives an * .* jniti.ation signal is to be in a. nonacc.ident position *. provided' the valve will aiitomatically reposition .in the' .. *.proper.stroke tfme: T_h.i.s sR**.does*not* require any*testing or . va*Tve mani pul a*t ion; rather, *.it.iii vol ves *verffi cat i-on that those valves capable of potentially beihg mispositioned are in tbe correct position .. This SR does not apply tci valves. that* c.annol be inadvertently mi*sa li gned, such as check valves-.;* For the RCIC System, this SR also inc.hides the .steamCfl ow" path for the turbine' and th.e 'fl ow. ccintrol l er p'ositJon, <
• continued B 3 ._5-27a ** Revision No. 128 I BASES SU RV EI LLANCE REQUIREMENTS .... ' *:': . PBAPS UNIT 3 SR 3.5.3.2 (continued) RCIC System B 3.5.3 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance is modified by a Note which exempts system vent flow paths opened administrative control. The control should be proceduralized and include stationing an individual who can rapidly close the system vent flow path if directed. SR 3.5.3.3' and SR 3.5.3.4 The RCIC pump flow rates ensure that the system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated. The flow tests for the RCIC System are* performed at.two different' pressure ranges such that system capability to provide rated flow is tested both at the higher and lower riperating ranges of system. Additionally, adequate steam flow must be passing through the ma{n turbine or turbine bypass valves tb continue to control reactor pressure when the RCIC System diverts steam flow. Reactor steam must be s 1053 915 psig I *to perform SR 3.5:3.3 and greater than or eqUal to the Electro-Hydraulic Control CEHC) System.minimum pressure set with the EHC System controlling pressure (the EHC System begins controlling pressure at a nominal 150 psig) and s 175 psig to perform .SR 3.5.3.4: Alternately, auxiliary steam can be used to perform SR 3.5,3.4. Adequate steam .flow is by at 2 turbirie bypass valves Therefore, time is allowed adequate flow are to perform these SRs. * . slqrtup: i:s' all owed' pfi or to perf.ormi ng the l.ow pressure Survei 11 ance b.e*c:ause the reactor pressure .is low *apd .the allriwed to sattsfactorily the Surve.niance is short. Alternately, the low pr.essure . *. may be prior to an auxiliar:V. *steam supply. The reactor is allowed to be iri6reised to it ts *
• the low Surveillance has been *Sa,tisfactorily Completed.and there is* no indication or reason .to believe that RCIC j s inoperable. Therefore, these SRs are.rnod1fi.ed*hy Notes'that state the Surveillances are .not required to be .Performed until 12. hours after the . reactor .. steam pressure .a.nd flow are adequate. to perform the test.*: '. * . _-,.--cbnt1nued .-:s 3:5-28' Re I/ i. s i on No . 13 2 * * *

,._ BASES SURVEILLANCE REQUIREMENTS :. -'*---* PBAPS UN IT 3 SR 3.5.3.3 and SR 3.5.3.4 (continued) RCIC System B 3.5.3 -The Surveillance Frequency is controlled uhder the Surveillance Frequency Control Program. SR 3.5.3.5 The RCIC System is required to actuate automatically in order to verify its design function satisfactorily. This Surveillance verifies that, with a system initiation signal (actual or simulated), the automatic initiation logic of the RCIC System will cause the system to operate as designed, including actuation of the system throughout its emergency operating sequence; that is, automatic-pump startup and actuation of all automatic valves to their required positions. This test also ensures the RCIC System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level .(Level 8) trip and that the suction is automatically transferred from the CST to the suppression pool on low CST level. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.j.5.2 overlaps to provtde complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Frequency Control Program. SR is modified by a Note that excludes vessel injection during the Surveilla,nce. Since all active testable and full fl6w be demonstrated by-recirculation t h r o u g h th e t e s t -l i n e , cool a n t i n j e ct i on i n to t e RP V i s not during the Surveillance. (continued) B 3-.s*-29 Rev i s i on -No . 8 7 * * - i I BASES (continued) RE FERENC ES PBAPS UN IT 3. 1. UFSAR, Section 1.5. 2. UFSAR, Section 4.7. RCIC System B 3.5.3 3. Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC), "Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975. 4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. B 3.5-30 Revision No.-67 1

• Primary Containment B 3.6.1.1 B 3.6 CONTAINMENT SYSTEMS B . _Primary Containment.* BASES BACKGROUND .**.* . . . PBJ\P.S 'UN JT 3
• The function of the primary containment is to isolate and contain fission products released from the Reactor Primary . System following a Design Basis Accident (OBA) and to confine the postulated release of .radioactive material. The primary containment consists of a steel vessel, which surrounds the Reactor Primary System and provides an essentially leak tight barrier an uncontrolled *release of radioactive material to the environment.
• Portions of the steel vessel are-surrounded by reinforced concrete for shielding purposes ..
• The isolation devices for the penetrations in the primary containment boundary are a part of the containment leak , tight barrier. To maintain this leak tight barrier: a. All penetrations requ1red to be during accident conditions are either:
• 1. capable of being closed by an OPERABLE automatic Containment Isolation System, or
• 2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their closed positions, except as prtivided in LCO 3 .. 6.1.3, "Primary Containment Isolation Va 1 ve s (PC IVs) " ; b. The primary containment air lock is OPERABLE, except as provided in LCO 3.6.1.2, "Primary Containment Air
• Lock"* and ' ' c. All equipment hatches are closed. This Specification ensures that the performance of the primary containment, in the event of a OBA, meets the assumptions used in the safety analyses of Reference 1. SR 3.6.1.1.1 leakage rate are in conformance with 10 CFR 50, Appendix J Option B (Ref. 3), as modified by .approved exemptions. (continued) B 3.6-1 Revision No. 2 7 *
  • • .*' *. Primary Containment B 3.6.1.1 BASES (continued) APPLICABLE SAFETY ANALYSES LCO ': .. --.. -PBAPS UN IT 3 The safety design basis for the primary containment is that it must withstand the pressures and temperatures of the limiting OBA without exceeding the design leakage rate. The OBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environment is controlled by the rate of primary containment leakage. Analytical methods and assumptions involving the primary containment are presented in Reference 1. The safety , analyses assume a nonmechanistic fission product release following a OBA, which forms the basis for determination of offsite doses. The fission product release is, in *turn, based on an assumed leakage rate from the primary containment. OPtRABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded: The maximum allowable leakage rate for the containment is 0.7% by weight of the containment air. *.per 24. hour;s at the design basis LOCA maximum peak containment pressure CPa) .of 49.l psig.-The value_ of Pa (49.l is conservative-with respect to the current calculated peak pressu0e of 48.7 psig (Ref: 2). This value cif 48:7 psig includes operation with 90°F Final Feedwater :f emper;ature *Reduction. *
• Primary containment s*atisfies Criterion 3 of the NRC Policy st'ateme.nt. --. . ' .:-* .. . * . -. . . . I . --... -.-. Primary (ontainment OPERABILITY is mainta.ined by limi"ti_ng * **leakage .to .:s;-1 ." ci *la,. prior to the first* start up afte*r _, perforrnj rig, a --required.:pri ma r_y C_onta ir:iment Leakage Rate -**Testing Program leakage test'. At this time., applicable** leakage limits must be met. In .'additi.on ;* the leakage from the drywe1 l *to the s_uppressi on ch.amber must __ be l i.mi ted to -. ensure -the pressure suppression funct'ion is "accomplished .. 'arid the suppres:sion chamber_ pr;essure does not exceed design ... lfmi.ts ... >CompHahce w'Hh this 'Leo .will'ensure a primary . containment conf1 gurati on'.* {ncl udi rig-equi p[llent .hatches .. t __ hat i*s _str_ucturally.sound and that wil1 limit leakage to those l Efokaire _ _.rates 9s.sumed in :the safety analyses. {cont i mied. * ... "/,. -*.*. . B 3.6-2 Revision No.* 119 .-I !

BASES LCD (continued) APPLLCABI LITY ACTIONS SURVEILLANCE REQUJ REMENTS PBAPS UN IT 3 -Primary Containment B 3.6.1.1 Individual leakage rates specified for the primary containment air lock are addressed in LCD 3.6:1.2. In MODES 1, 2, and 3, a OBA could cause a release of radi6active material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, primary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment. In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour. The 1 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MODES-1; 2, and 3. This time period also ensures that the probability_of accident (requiring primary containment OPERABILITY) occurring rluring periods where primary is inoperable is minimal. -If be t6 OPERABLE status _ wit h i n t h e re q u i red Comp l e't ib n Ti me ,' t h e p l a n t mu s t be brought.to a.MODE in the overall risk is minimized. To achieve this status, the plant must be br6ught at least MODE 3 withiTI 12 Remaining in the Applicability of the LCD is acceptable because the plant risk in MODE 1 is similar to or lower than the risk in MODE 4 and spent in MODE 3 t6 perform the necessary-repairs to r_estore the system -to OPERABLE _ stat us wiJ l be s hdr.L _How-ever', -voluntary *entry into MODE 4 may be-made as it is also-an acceptable_ low-risk state. The _ al l ow e.d Comp l et i on Ti me -i**s . reason ab l e , based . oh opera ti n g experience, to reach the required plant conditions from.full power *concji_tions in .an ord-erly manner and without ch"al l enging pl ant systems* .. _*---*'*:. S R 3 . 6-. i. 1 . 1 -_MaintaJning tre.prtrnary containment OPERABL.E requ-ires _ :complia_nce with the visual examinations* and leakage _rate test requirements of--the Pr'imary _Contaihment Leakage Rate Testing 'Pro:gram*:* _Failure to* meet air lock:::1eakage testing (SR 3-.6--.'l.2.l), or-ma.fo steam isolation -C continued)_ B 3. u -Revi si-on No_. 67

• _.c. BASES SURVEILLANCE REQUIREMENTS . . *. *:: : *, ' PBAPS UN IT 3 .. *.,*._** SR 3.6.1.1.l (continued) Primary Containment B 3.6.1.1 valve leakage (SR 3.6.1.3.14), does not necessarily result in a failure of this SR. The impact of the failure to meet t h e s e S Rs *mu s t b e e v a l u a t e d a g a i n s t t he Ty p e A , B , a n d C acceptance criteria of the Primary Containment Leakage Rate Testing Program. At s 1.0 La the offsite dose consequences are bounded by the of the safety The Frequency is required by the Primary Containment Leakage Rate Testing Program. SR 3.6.1.1.2 Maintaining the pressure suppression function of primary containment requires limiting the leakage from the drywell the suppression chamber. Thus, if an event were to occur pressurized the drywell, the steam would be directed through the downcomers into the suppression pool. This SR i.s a leak test that confirms that the bypass area between the drywell and the chamber is less than or equivalent to a diameter hole .(Ref. 4). This that the leakage paths that would bypass the suppression pool are within allowable limits.
• The Surveillance is controlled under the I Surveillance Frequency Control Program. Two consecutive test failures, would indicate unexpected primary degradation; in this as the Note 'indicates, a"test shall be performed at a.Frequency of once every months until two consecutive tests pass; I' (continued) B 3 .. 6-4 Revision No. 87 Primary Containment I B 3.6.1.i BASES (continued) REFERENCES J* ... . PBAPS U.N IT 3 1. UFSAR, Section 14.9. 2. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 3. 10 CFR 50, Appendix J, Option B. 4. Safety Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 127 and 130 to Facility Operating License Nos. DPR-44 and dated February 18, 1988. 5. NEI 94-01, Revision 3-A and 2-A, "Industry Guideline . for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." 6. ANSI/ANS-56.8-2002, "Containment System Leakage Testing Requirements." 7. Deleted 8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected End States for BWR Plants, December 2002. B 3.6-5 *Revision No. 119:.

11 :1 .. * ' :(. '. ,< I*.-_.* .. l .. I ' . '! Primary Containment Air Lock B 3.6.1.2 B 3. 6 CONTAINMENT SYSTEMS B Primary Containment Air Lock BASES. . BACKGROUND One double door primary containment air lock has been built into the primary containment to provide personnel access to the drywell and to provide primary containment isolation during the process of personnel entering and exiting the drywell. The air lock is designed to withstand the same loads, temperatures, and peak design internal and external. pressures as the primary containment (Ref. 1). As part of the primary containment, the air lock limits the release of . *radioactive material to the environment during normal unit operation and through a range of transients and accidents up to and. including Design Basis Accidents (DBAs). Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a OBA in primary containment. Each of the doors contains a gasket seal to ensure pressure . integrity .. To effect a leak tight the air lock design uses pressure seated doors (i.e., an increase in primary containment internal pressure results in increased sealing force on each door}. Each. a.ir lock is nominally a right circular cylinder, 12 ft in diameter:,. with doors at each end that are interlocked to prevent simultaneous opening. During periods when primary containment is not required to be OPERABLE, the air.lock interlock mechanism may be disabled, allowing both doors of an air lock to remain*open for extended periods when frequent primary containment entry is necessary. Under some conditions as allowed by this LCO, the primary containment may be accessed through the air lock, the interlock mechanism has failed, by manually performing the interlock function. The primary containment air lock forms part of the primary containment pressure boundary. As such, air lock integrity and leak tightness are essential for maintaining primary con_tainment leakage rate to within limits in the event of a -DBA. Not maintaining air lock integrity or leak tightness .-may result in a leakage rate in excess of that assumed in * . the unit safety analysis.* (continued} .. PBAPS UNIT. 3 .. *B 3.6-6 Revision No. 0 ';, I I. I Primary Containment Air Lock B 3.6.1.2 BASES (continued) APPLICABLE SAFETY ANALYSES LCO **':' ' . -:. ;**. PBAPS UNIT 3 The OBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE, such that release of fission products the environment is controlled by the rate of primary containment leakage. The primary containment is designed with a maximum allowable leakage rate CLa) of 0.7% by weight of the containment air per 24 hours at the maximum peak containment pressure CPa) of 49.1 psig. The value of Pa (49.1 psig) is conservative with respect to the current peak drywell pressure of 48.7 psig (Ref. 3). This value of 48.7 psig includes operation with 90°F Final Feedwater Temperature.Reduction. This allowable leakage rate the basis for the acceptance criteria imposed on the SRs associated with the air lock. Primary air lock OPERABILITY is also required to minimfze the amount of fission product gases that may escape primary containment through the air lock and contaminate and pressurize the The primary containment air lock satisfies Criterion 3 of the NRC Policy:Statement. As part of piimary*containmenf, the air lock's safety furictibn. is related to control of containment leakage. rates followin.g a.*DBA. Thus, the air loCk's structural integrity and. leak tightness are* essential to the successful

• mitigati'On 'of suth an e'vent. The pri!Jlary a_ir Tock.Ts requ'tred to be OPERABLE. For the a\r lock*to be considered.OPERABLE, the air lock interlock mechanism-must be OPERABLE, the_ ai.r *1ock must be
• in with.the Type Bair* lock leakage test, and
• b.oth *a i'r lock dcfors rhust .be OPERABLE. *The interlock a 11 ows only air Tock door_ to be: opened at a ti'me; This >provision* E;nsures tha*t a gross bread;' of primary c.ontainment does not exist when primary containmenLis required to be CJosvre of a single door in each air lock is * .suffici.ent to .a leak tight barrier following postul a.ted Nevertheless;* b.oth doors are kept cl cised w h e n J h e : a i r l o c k is h o t be _in g
• u s e d f 6 r n o rm a l e n t r y a n d *exit frorri primary containment .. (continued). . .---, B 3.6-7' Revision No. 119 , , , __J

.. i' r i ' ' ' ' I . ' ,' ..... ------------Primary Containment Air Lock B 3.6.1.2 BASES (continued)

• APPLICABILITY ACTIONS .**.** :-'. -:. . " ' '-*" .. ... " .. -.. -. :: -, ' .' -*.*. r.; .. . " . -*.:* In MODES 1,' 2, and 3, a DBA could caµse a re.lease of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure .and temperature limitations of these MODES .. Therefore, the primary containment air lock is not required to be in MODES 4 and 5 to prevent leakage of radioactive material from primary containment. ' ' The ACTIONS are modified by Note 1, which allows entry and *exit* to perform repa:irs of the affected air component. ,If the outer door is inoperable, then it may be easily accessed.to repa*fr. If the inner door is the one that is inoperable, however, *then a short time exists when the .containment boundary is not intact (during access through the outer. door) . . The ability to open the OPERABLE door, even* if n* means the primary containment boundary is temporarily not-intact, is acceptable due to. the low . probability of an event that could pressurize the primary . contaiilment during the short .time in which. the OPERABLE door is expeeted .to be open.
• The OPERABLE doo.r .must be immediately *Closed after each entry and e)(it. The ACTIONS are modifi'ed*by a second, Note, which ensures appropriate remedial measures are taken when necessa*ry. *Pursuant to LCO 3 actions are not -required, even if . * .. pr.imary containment* is *exceeding *L8*
• Therefore, the Note. is;:added to require *ACTIONS for LCO 3._6.1.1, "Primary to be taken in this event. , * . . . A. i', A.2, arid A:3 *-* :* cotitai'nmeh"i' air lock the OPERABLE dopr closed (Required Action,*A.1) in. the air Tock*; ';Jhfs ensures-that a -*leak-tight primary .. . . . barrier is-.maiiltairle<f by the -u'se of an OPERABLE* . *:air .lock* door. :. This*_.actirin must be .completed within .l. hour;.* , 'the 'r h.o_ur ,Conipl et ion Time. is *conststent<'4ith the ACTIONS. of .*.*.
• LCO. requires* that Primary e:*anta i'nl)lerit. be* -. ..* . . r*e$:tored .to OPERABLE s'tatus -within l_ h()ur:. _" *... . -.
• adc:l-;1:i'on, *the-air *.;sol ated .by Jockl11g closed.the OPEAA.BLE air lockdoor_within--the 24 hour, ..
• __ Comp_letton Time_.; :* *The*'.24 -:hour Completion Time. rs* *consi dere(l . 'l: : , . . . . ' ... : ! '* *;. <>;* **.:* . . -. . . ' . . . . . . '-. *' -.. ...... .. ..-** * .. '* . *.*., .. ** *(continued)
• UNlf'3 ':_ ' ' ....... * .. _.* '.' _*.: :*Revision-No. o .,** .. * ...... -,. *-; .3. Q.:.8_.* < '; ** ' * -*. -* . . __ . .. **;.,-. ,:.': -. *:*. -.

BASES ACTIONS PBAPS .UNIT 3 _.-., ... A.I, A.2, and A.3 (continued) Primary Containment Air Lock B 3.6.1.2 reasonable for locking the OPERABLE air lock door, considering that the OPERABLE door is being maintained closed. Required Action A.3 ensures that the air lock with an inoperable door has been isolated by the use of a locked closed OPERABLE .air lock door. This ensures that an acceptable primary containment leakage boundary.is maintained. The Completion Time of once per 31 days is based on engineering judgment and is considered adequate. in view of the low likelihood of a locked door being mispositioned and other administrative controls. Required Action A.3 is modified by a Note that applies to air lock doors located in high radiation areas or areas limited access due to inerting and allows these doors to be verified locked closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small. The Required Actions have been modified by two Notes. Note I ensures that only the Required Actions and associated Times of Condition C are required if both doors *

• in the air lock are inoperable; With both doors in the air lock inoperable, an OPERABLE door is not available to be closed. Required Actions. C.l and C.2 are the appropriate remedial actions. The exception of Note 1 does nbt affect tracking the Completion Time from the initial entry into : Condition A; only the requi'rement to comply with the
• Required Actions. Note 2 allows use of the air lock for
• entry arid exit for .7 days under admi n i strati ve co ht ro 1 s. Primary containment entry may be required to perform
• Technical Specifications (TS) Surveillances and Required Actions, as well as other activities on TS-required equipment -0r ori equipment that support
• TS-required equipment. This Note is not intended to preclude performing other activities (i.e., non-TS-related activities) if the primary containment was entered, using the inoperable air t6 perform an allowed activity listed above. The administrative controls required consist of the stationing of a dedicated individual to assure clo$ure of the OPERABLE door except during the entry and exit," and assuring the OPERABLE door is re 1 ocked after {continued) B 3 .6..,9 *.*.Revision No. **o BASES ACTIONS PBAPS UNIT-3 A.I, A.2, and A.3-(continued} Primary Containment Air Lock B 3.6.1.2 completion of the containment entry and exit. This allowance is acceptable due to the low probability of an event that could pressurize the primary containment during the short time that the OPERABLE door is expected to be open.. B.l, B.2, and B.3 With an air lock interlock mechanism intiperable, the Required Actions and associated Completion Times are consistent with those specified in Condition A. The Required Actions have been modified by two Notes. Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock inoperable. With both doors in the lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the appropriate remedi.al actions. Note 2 allows entry into and exit from the primary containment under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the performs the -function of the interlock). -Requfred Action B.3 is modified by a Note that applies.to air lock doors located in high radiation areas or areas-with limited access due to irierting and that allows these doors to be verified locked closed by use of administrative* __ controls. *All owing verification by admfoi strati ve controi s is considered since access to these areas_is typically Therefore, the probability of -misalignment_of the it has been verified to be in'. the proper position, is small. C. I. C. 2, and' C. 3 If the air inoperable for reasons other those described in Condition A or B, Required Action C.l requires action to be immediately initiated to evaluate containment.* leakage rates using current leakage test *results. An evaluatfon: is acceptable since it is overly conservative to immediately declare the primary if the overall a*tr loc_k leakage. -is not within ( cont.i nued) . B 3.6-10 -Revision o BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 C.1. C.2. and C.3 (continued) Primary Containment Air Lock B 3.6.1.2 limits. In many instances (e.g., only one seal per door has failed), primary containment remains OPERABLE, yet only 1 hour (according to LCO 3.6.1.1) would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In addition, even with the overall air lock leakage not within limits, the overall containment leakage rate can still be within limits. Required Action C.2 requires that one door in the primary containment air lock must be verified closed. This action must be completed within the 1 hour Completion Time. This specified time period is consistent with the ACTIONS of LCO 3.6.l.l, which require that primary containment be restored to OPERABLE status within 1 hour. Additionally, the air lock must be restored to OPERABLE status within 24 hours. The 24 hour Completion Time is reasonable for restoring an inoperable air lock to OPERABLE status cons,idering that at least one door is maintained closed in the air lock. 0.1 and 0.2 If the inoperable primary containment air lock cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3 . 6. 1. 2 . 1 Maintaining primary containment air locks OPERABLE requires compliance with the leakage rate test requirements of the Primary Containment Rate Testing Program. This SR reflects the leakage rate testing requirements with respect to air lock leakage (Type a leakage tests). The acceptance criteria were established during initial air lock and primary containment OPERABILITY (continued) B 3 .6-11 Rev i s ion No.
• 6 BASES SU RV EI LLANCE REQUIREMENTS : ... * _., __ *>. PBAPS UN.IT 3 SR 3.6.1.2.1 (continued) Primary Containment Air Lock B 3.6.1.2 testing. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary Containment Leakage Rate Testing Program. The SR has been modified by two Notes. Note 1 states that _an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test. This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a OBA. Note 2 requires the results of air lock leakage tests to be evaluated against the acceptance criteria of the Primary Containment Leakage Rate Testing Program, 5.5.12. This ensures that the air lock leakage is properly accounted for in determining the combined Type B and C primary containment leakage. SR 3.6.1.2.2 The lock interlock is designed to prevent opening both doors in the air lock. Since . both the inner .and outer doors of an air lock a re designed to withstand the maximum expected post accident primary c*ontainment pressure, closure*of.either door will support primary conta*inment OPERABILITY ... Thus; the interlock OPERAB1LiTY while the air lo.ck' is being used for *personnel transit in and out of Periodit festing of this .interlock demonstrates that the i'nterlock will function as design.ed and. that simultaneous inner and out.er door opening will not inadvertently otcur._***Th*e Surveil_iance F'requericy is .. ,. controlled urider t'he' Surveillance Frequency Control Program .. (continued) ... :. .">: . *.;: *: ,*. *.*. -B 3.6-12<
• Revi'si on No. 87 ..
• j BASES (continued) REFERENCES ,*_-; PBAPS UN IT 3 --------------------1. UFSAR, Section 5.2.3.4.5. Primary Containment Air Lock B 3.6.1.2 2. 10 CFR 50, Appendix J, Option B. 3. . NEDC-33566P, "Safety Analysis Report for Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 4. Deleted B Revi si.on No. 119 .-:--

1. -' -,'*._. i -_. 1. -PC I Vs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs) BASES BACKGROUND PBAPS UNIT 3 The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment isolation within the time specified for those isolation valves designed to close automatically ensures that the release of *radioactive material to the environment will be consistent.with ihe assumptions used in the analyses for a OBA. The OPERABILITY requirements for PCIVs help ensure that an adequate primary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. Therefore, the OPERABILITY requirements provide assurance that primary containment function assumed in the safety analyses .will be maintained. These isolation devices are either passive or active (automatic). Closed manual valves, de-activated automatic valves secured in their closed posit{on (including_check valves with flow through the valve secured}, blind flanges, and closed. systems are considered passive devices. Check valves and other automatic valves designed to close without operator action fo-llowing an accident, are considered act_ive devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result a loss of isolation or leakage that exceeds ]imits assumed in the safety analyses. One of these -barriers may* be a closed :system. The reactor building-to-suppression chamber vacuum breakers.** _and the scram discharge volume vent and drain valves each serve a dual function, one of which is primary containment. isolation. However, since the olher safety functions of the vacuum breakers and the scram discharge volume vent and drain valves would not be available if the normal PCIV actions-were taken, the PCIV OPERABILITY requirements are not applicable to the reactor building-to-suppression chamber vacuum breaker valves and scram discharge volume and_drain valves. Similar Surveillance Requirements in _the LCD for the reactor building-to-suppression chamber vacuum breakers and the LCO for the scram discharge volume (continued) -B 3.6-14: Revision No.* 0. '* .: .

l .. : .. :f i.-"./. l. --' --:. '* ..... , ., : . .. : . '* ' . .. ; :i I -_BASES BACKGROUND (continued) *.*_.*, .-. ---. ;*_. ,. '*::* '. ----.. PBAPs, :uNn J, .'* PC I Vs. B 3.6.L3 -vent and drain valves provide assurance that the isolation capability is available without conflicting with the relief or scram di.scharge volume vent and drain functions. The primary containment purge lines are 18 inches in diameter; exhaust 1 i nes are 18 inches in diameter. . In addition, a 6 inch line from the Atmospheric Contro.l (CAC) System is al so prov.ided to* purge primary _ cont-ainment. The 6 and 18 inch primary containment purge valves and the 18 inch primary containment exhaust valves_ are normally maintained closed in MODES 1, 2, and 3 to ensure the primary containment boundary is -However, contaiilinent purging with the 18 inch purge and: -exhaust valves is permitted for inert i ilg, de-inert i ng, and pressure control. _ in_ the scope of the de-inerting is the need to purge contai_nment to ensure personne1 safety' -during the performance of inspections beneficial to nuclear safety; *e.g., inspection of primary <;oolant integrity during *plant startups shutdowns. Adjustments in primary -.

• containment pressure to perform tests.such as-to-suppression chamber bypass leakage test are included. within the_ scope of pressure control Purging for --humidity and temperature control using the 18 inch valves is excluded. The *isolation valves on the 18 inch vent lines
• have 2 inch bypass lines around them for use during normal reactor' operation _when the 18 inch valves canriot be opened:'-,c -* Two additional red_undarit, Standby Gas Treatment (SGT) _ isolation valves are_ provided on the vent line upstream *of the SGT System filter trajns. These isolation valves, together with-the PC IVs, \iii 11 prevent-high; pressure from-*--' reaching the SGT System filter trains in the unlikely e_vent .of:a loss of coolant accident (lOCA) durf11g venting.*_---. -.. .. . . . ' The Safety -(SGIG) _-*system pressurized nitrogen. ga_s* (fr_om the_ Coritaiilinent AtmospheriC
• Oilution: (CAD) -*system liquid nitrogen storage tank) as* a* __
• safety grade pneuinatic :source to the CAC:System purge. a11d .. -*._exhaust isolation*: valve' inflatable seals*,_ the reactdr ___ _ build1ng-to-suppressi0n chamber vacuum breaker air operated i so lati on valves arid i nfl atab le seal , and-the_ CAC and *.::. --Systems vent control air-. operated valves .. The SGIG System -__ .thus' performs two di st i net post-LQCA . funC:t ions: ( 1) --_ . -* . supports c_ontai nment i sol at ion and ( 2) --supports CAD System -.vent SGIG System requirements are-addressed .for :' . . . . . . , . . . *, ' . _.,* -(tonti nued) _.* ,** . -. *"" . .* *. . '.* ' . '-. Revi *No.: 0 .... :-** .: .

'_,.'. BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 PC I Vs B 3.6.1.3 each of the supported system and components in LCO 3.6.1.3, "Primary Containment Isolation Valves CPCIVs)," and LCO 3. 6 .1. 5, "Reactor Building-to-Suppression Chamber Vacuum Breakers." For the SGIG System, liquid nitrogen from the liquid nitrogen storage tank passes through the liquid nitrogen vaporizer where it is converted to a gas. The gas then flows into a Unit 2 header and a Unit 3 header separated by two manual globe valves. From each header, the gas then branches to each valve operator or valve seal supplied by the SGIG System. Each branch is separated from the header by a manual globe valve and a check valve. To support SGIG System functions, the nitrogen inventory is equivalent to a storage tank minimum required level 22 water or a technically.justified source of equivalent inventory 124,000 scf at 250 psig, and a minimum required SGIG System header pressure of 80 psig. The PCIVs LCO was derived from.the assumptions related to minimizing the loss of reactor coolant inventory, and establishing the primary containment *boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary .. containment. Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this UO. The DBAs that result in a release of radioactive material and are mitigated by PCIVs are a LOCA and a main steam line break CMSLB). In the analysis for each of these accidents, it is assumed that PCIVs are e1ther closed or close within the required isolation times following event initiation. This ensures that potential paths to the environment through PCIVs (including primary containment purge valves) are minimized. Of the events analyzed in Reference 1, the LOCA is a limiting event due to radiological consequences. The closure time of the main steam isolation valves CMSIVs) is the most significant variable from a radiological standpoint.* The MSIVs are required to close within 3 to 5 seconds after signal generation. Likewise, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled. continued B 3.6-16 Revision No. 91 ...

• BASES -APPLICABLE SAFETY ANALYSES (continued) LCO :. , '. --* .. _.:.:.' " --'. . ' PBAPS. UNIT 3 PC I Vs B 3.6.1.3 The DBA analysis assumes 1that within 60 -seconds of the accident, isolation of the primary containment is complete and leakage is terminated, except for the maximum allowable leakage rate, La. The primary containment isolation total response time or 60 seconds includes signal delay, diesel generator startup (for loss of offsite power), and PCIV stroke times. The single failure criterion required to be imposed in the conduct of unit safety analyses was considered in the original design of the primary containment purge and exhaust valves. Two valves in series on each purge and exhaust line provide a$surance that both the supply and exhaust lines could be isolated even if a single failure occurred. PCIVs satisfy Criterion 3 of the NRC Policy Statement. PCIVs.form a part of the primary containmen't boundary. The .PCIV safety function is related to minimizing the loss of the ... reactor coolant inventory and establishing the primary containment boundary during a DBA. . . . . The pow.er operated, automatic isol_ation valves are required to have isolation within limits and actuate on an a*utomatic isolation signal. . In *addition, for the CAC System. purge and *exhaust i s*ol ati on valves to be considered _ OPERABLE,the SGIG System supplying nitrogen gas to the inflatable seals .of the valves* must be OPERABLE. While the . reactor vacuum breakers and the scram discharge vent and valves isolate primary containment excluded from this Specification:. '-Controls on. thejr isolation are adequately addressed *;n. LCO 3.1.8;.11Scram*Discharge Volume (SDV) Vent and Drai:n Va_lves," and LCO 3.6.1.5, . "Reactor. Chamber Vacuum -The valves covered by thiS-LCO are listed with their' assocjated stroke times in :The *required stroke . time is 'the** stroke t irrie li st:ed *in Reference* 2_, or the * *_ Inservice. Testing Program which::ever more: conservative.* The *normaily. closed PCIV*s are considered OPERABLE when .. manual. valves are' closed or open -iii accordance with .
• controls, automatic valves ar:-e --(confinlied) . * .. -, .: . * *. ', .** . . ; . : . -.* . 8 3;6-17 *
• Reyi.s i ori No. 2 BASES LCO (continued) APPLICABILITY ACTIONS PBAPsiJN Ii-3 . PC I Vs B 3.6.1.3 de-activated and secured in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves and devices are those listed in Reference 2 and Reference 5. MSIVs must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3. 6 .1.1, 11 Primary Containment," as Type B or C testing. This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents. In MODES 1, *2, and 3, a OBA could cause a release of radioactive material to primary containment. .In MODES 4 and S, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, most PCIVs are not required to be OPERABLE.and the primary containment purge and exhaust valves are not required tri be normally in MODES 4 and 5. Certain valves, however, are required to be OPERABLE to reactor vessel draindown. These valves are those whose associated instrumentation is required to be OPERABLE per LCO 3.3.6 . .1, "Primary ContainmEmt Isolation Instrumentation. 11 (This does not include the that the instrumentation.) . The ACTIONS are modified by a Note allowing penetration flow path.(s)'.:exce'pt for pu,rge *or exhaust valve flow path(s) to be unisolated intermittently.under administrative controls. These controls *consist of's:tatii:>ninga dedicated operator at the Controls of the who is in continuous . *. * .. comn:iun i ca ti on with the control . room.
• In this .way, the .. *pE!i°1etratfon can *be rapidly*.isola::ted when a 'ne.ed for primary . containment. isolatfon is indicated .. Due to the size of the primary purge line penetration and the'fact that *exhaust directly *from containment * * *
• atmosphere to the environment, the fl ow path . containing these valves is . not.* a 11 owed to b.e
• operated under administrative * '.',I {continued) .. > ***:**.* -. I

. **:. .BASES ACTIONS (continued) PBAPS UNIT 3 PC I Vs B 3.6.1.3 A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable PCIV. Complying with the Required Actions may allow for continued operation, and subsequent.inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions. The ACTIONS are modified by Notes 3 and 4. Note 3 ensures *that appropriate remedial. actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling Systems subsystem is inoperable due to a failed open test return . valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are Pursuant to LCb 3.0.6, these actions would not be required even when the associated LCD is not met. Therefore, Notes 3 and 4 are added to require the proper be taken. A.I and A.2 With one or more penetration flow paths with one PCIV except for MSIV leakage within limit, the affected. penetration fl ow paths must be isolated. The method of isolation must include the use of at least one

• isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a clcised manual valve, a blind flange, and ii. check valve with flow through the valve secured. For a penetration isolated in accordance with Required Action A.I, the device used to . isolate the penetration should be the closest available valve to the primary containment. The Required Action must be within the 4.hour Completion Time (8 hours for main steam lines). The Completion Time of 4 hours is reasonable considering the time required to isolate the penetration and the relative of supporting primary containment OPERABILITY during MODES 1, 2, and 3. For main steam lines, an 8 hour Completion Time is allowed. The. Completion Time of 8 hours for the ma.in steam 1 ines (continued) B* 3 .. 6"'."19 .** Revisibn O .

BASES ACTIONS . :.: .. PBAPS UNIT 3 A.1 and A.2 (continued) PC I Vs B 3.6.1.3 allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown. For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration flow path(s) must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and no longer capable of being automatically isolated, will be in the isolation position should an event. occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary c6ntainment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low, For the devices inside primary containment, the time period specified "prior .to entering MODE 2 or 3 from MODE 4, if primary was de-inerted while in MODE 4, if not performed within the previous 92 days" is based on judgment and is reasonable in view of the inaccessibility of the devices and other controls ensuring that device misalignment is an* unlikely possibility. Condition A is modified by a Note indicatihg that this Cohdition is only applicable to those penetration flow paths with two PCIVs. flow paths with one PCIV, C6ndition C provfdes the appropriate.Required Actions.

• Required Acti6n A.2 is by two Note 1 ipplies I *. to devices-1otated in areas, and allows them to by use of administrative means. A 11 owi rig verifi ca ti on by admi.ni strati ve means . is considered
• acceptable, since t6 these areas is typically . restritted .. Note 2 applies to isolati6n devjces that locked, sealed, of secured in position and devices to be verif{ed closed by use 6f means. Allowing verification by administrative means *is considered acceptable, the function of sealing', or sect,1ring components is to ensure that these *are not .. the _probability of misalignment' once they have b.een verified, to be iri the proper positfon,*js low. continued B 3.fr-20 Revision No. 58 BASES ACTIONS (continued) PBAPS UNIT 3 PC I Vs B 3.6.1.3 With one or more penetration flow paths with two PCIVs inoperable except due to MSIV leakage not within limit, either the inoperable PCIVs must be restored to OPERABLE status or the affected penetration flow path must be isolated within 1 hour. The method of isolation must include the use of at least one isolation barrier that *cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 1 hour Completion Time is consistent with the ACTIONS of LCD 3.6.1.1. Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two PCIVs. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions. C.1 and C.2 With one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to OPE.RAB LE status or the affected penetration fl ow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. The Completion Time of 4 hours is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The Completion Time of 72 hours for penetrations with a closed system is reasonable considering the relative stability of the closed system reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES l, 2, and 3. The closed system must also meet the requirements of Reference The Completion Time of 72 hours is also reasonable considering the instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration isolation boundary and the small pipe diameter of the affected penetrations. For affected penetrations that have been isolated in accordance with Required Action C.1, the affected penetration flow path(s) must be verified to be isolated on continued B 3.6-21 Revision No. 58 BASES ACTIONS ':*' .. :. *.: -,,* .. *.-PBAPS UN.f T 3 C.1 and C.2 (continued) PC I Vs B 3.6.1.3 a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, and n-0 longer capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown, that those valves outside containment and capable of potentially being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low. For the valves inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was while in MODE 4, if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the valves and other administrative controls ensuring that valve misalignment is an unlikely possibility. Condition C is modified by a Note indicating that this Condition is only applicable to penetration flow paths with only one PCIV. For penetration flow paths with two Conditions A and B provide the appropriate Required Actions. Requfred Ac ti on C. 2 is Hed .by two Notes. Note 1 applies to valves blind flahges located iri high radiation areas and them to be* verified by use of means. Al lowing veri fi ca ti on by admi.ni stratiye means is access to these areas is typical_Jy -restricted. *Note 2 applies .to isolation devices that sealedi. or otherwise in position and a 11 ows these devices to be .veriffed closed by :use of admi ni strati V;e means; . All ow1 ng cati cin by * .. -.
• is considered since(the function of locking, sealing,*or securing components is:to. ensure that.these de.v'ices. are not ir:iadvertent*ly r.epositioned ....
• Jherefo.re", the *probabi l i.ty of mi sal i grirnent of: these valves,. once have b_een verifi ep to be in the p:roper posi tfon' is . 1.pw **' .. D.1 . With.any* r.ate not within limit,* the assumption's of the s*afety_ analys-is are-not met. Therefore, the leakage must be restored t6 wi thi.n 1 i mii within 8 _hours. . * . : Resfo_ratiqn can be* accomplished by isola.ting the penetration that C:a1,1.sed. the Ji mit to be exceeded by use of one clb.sed and .closed manual*.valve;or* blind fiange .. 'When a i's the leakage . . . . . .. (continued) B .3.6-22. Revision No. 58' : -. _* .... '

BASES ACTIONS -'_; PBAPS UN IT 3 * . .; lL_.1 (continued) PC I Vs B 3.6.1.3 rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway of the two devices. The 8 hour Completion Time is reasonable considering the time required to restore the leakage by isolating the penetration, the fact that MSIV closure will result in isolation of the main steam line and a potential for plant shutdown, and the relative importance of MSIV leakage to the containment E.l, E.2.1 and E:2.2 The time that the large containment purge and/or vent valves (6" and 18" vent valves) are open, when reactor pressure is greater than 100 psig and the reactor is in MODES 1 or 2, is limited to 90 hours per calendar year. This will limit the tota.l tlme that a flow path exists through certain containment penetrations .. The design analysis (Reference 7) assumes that the containment remains at atmospheric pressure for determination of ECCS NPSH during a LOCA. Consequently, there exists'minimal impact on risk from challenges to. ECCS NPSH a LOCA while purging.: The 4-hour Time to isolate the penetration is c6nsidered a amount of time to ensure compliance with f6r containment If the penetration is not isolated within the specified 4-hour time period, then the plant must be to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. :The_ a.ll owed Completion Ti mes a re reasonable, based on opera ti rig exp er i enc e ,

• to r*e a ch the re q u fr e d pl ant con d n i 6 n s from fun** power an orderly_ mariner and without cha lJeng frig* pl a rit sy'stems: * -* --. *-F.l
• If any red Act.ion a*nd associated. Compl-eti on Time canr)ot be met in MODE 1,, 2, or 3, the plant-must-be brought to a MODE iri which-he Leo does not apply. To achieve this --status, _the pl ant niust be brought to a,t least MODE-3 within. '12* hours and to MODE4 .within 36 hours. Theailowed Times-are reasonable-, based o*ri operating. -experien.ce, to reach the 'required plaht conditions from full power -coridi hons in an order-1 y: manner and wlthout challenging (.cont i nue'd ). B 3. 6 :23 --. Revisio.r:i No. 119 BASES ACTIONS (continued) . PBAPS*::, UN IT 3 > ,. : .. . ' .. -.,.* G.l and*G.2 PC IVs B 3.6.1.3 If any Required Action and associated Completion Time cannot be met for PCIV(s) required to be OPERABLE during MODE 4 ot. 5, the unit be. placed in a condition in which the LCO does not apply. Action must be immediately initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) to minimize the probability of a vessel draindown and subsequent potential for 1ission release. Actions must continue until OPDRVs' are suspended and are .to OPERABLE status.* If an OPDRV would result in closing the residual heat (RHR)' shutdown cooling isol_ation valves, an alternative Required Action is prbvided to immediately initiate action to restore the valve(s) to OPERABLE stitus. This allows RHR to remain in service 0hile .actions are being taken to restore the valve. (continued) Revis.ion. No: li9. I * ' __ ....

1 ** BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS UNTf 3 .. , SR 3.6.1.3.1 PC I Vs B 3.6.1.3 Verifying that the nitrogen inventory is equivalent to a level in the liquid nitrogen tank 22 inches water column 124,000 scf at 250 psig) will ensure at least 7 days of post-LOCA SGIG System operation. This minimum volume of nitrogen allows sufficient time after an accident to replenish the nitrogen supply in order to maintain the containment isolation function. The inventory is verified to ensure that the system is capable of performing its intended isolation function when required. The Surveillance Frequency is controlled under the Surveillance Frequency

• Control Program. SR 3.6.1.3.2 This *SR ensures that the pressure in the SGIG System header. 80 psig. This ensures that the post-LOCA nitrogen pressure provided to the valve operators and valve seals is adequate for the SGIG System to perform its design function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.3
• This SR ensures that the.primary containment purge and exhaust valves closed"as required or, if open, for an allowable reason. If a purge valve is open in vioiation of this SR, the vaive is. considered inoperable (Condition A applies). The modified by a Note stating that the SR .is nbt to be met when the purge exhaust a re open for the stated reasons. The Note states that these may be for inertirig, de-inerting, control, ALARA or for . entry, or that require the valves to be* open. The 6. inch and JS inch purge valves arid 18 inch exhaust * ... *.* ... *:_. continued * -. B 3. 6-24 .. Revision No::91

'-* ';" BASES SU RV EI LLANCE REQUIREMENTS PBAPS.UNIT.3 . SR 3.6.1.3.3 (continued) PC I Vs B 3.6.1.3 valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. SR 3.6.1.3.4 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment and is not locked, sealed, or otherwise . secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are .in the correct position. Since verification of valve position for PCIVs outside primary containment is relatively easy, the Frequency was chosen to provide added assurance that the PCIVs are in the correct positions. This SR does not apply to that are locked, sealed, or otherwise secured in the closed position, since these valves were verified to be in the correct position upon iocking, sealing, or securing. Three Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by controls is considered acceptable since the primary containment is inerted and access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the *probability of misalignment of these PCIVs, once they have been verified to be in the proper position, is low. A second Note has been included to clarify that PCIVs that are open controls are not required to meet the SR during the time that the PCIVs are open. A third Note states that performance of the SR is not required for test taps with a 1 inch. It is the intent that this SR must sti 11 be met, but actual pedormance is not required for test taps with a 1 inch. The Note 3 allowance is consistent with the original plant licensing bas1s. continued B 3.6-25 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS (continued) SR 3.6.1.3.5 PC I Vs B 3.6.1.3 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For PCIVs inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days" is appropriate since these PCIVs are operated under administrative controls and the probability of their misalignment is This *SR not to valves that are locked, seated, or otherwise secured in the closed position, since these valves were verified to be in the co0rect position upon locking, or securing. Two. Notes have been added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by *use bf administrative controls. Allowing verification by administrative controls is considered sirice the primary is inerted and access to these areas is typtcally restricted during MODES *1, 2, and 3 for ALARA reasons. Therefore, the of of these once ihey have been verified to 'be in the_ir is low. A second Note been to that PCIVs that are .open urider administrative controls ate not required to meet the that the PCIVs *are Qpen. ** *sR 3.6.l.3.6 *.*.' . *-** .. PBAPS UN IT 3 pFcibe (TIP) actLlilted .bY explosive cha-rges. -Survei.l lance of expl bs_i ve -'charge continuitj*provides assurance that TIP* valves w.ill _ actuat'e when .re_qLiired: Other admini.strative controls; such as those'lriat' limit the shei.f*l<ife of the _explosive charges, _mudst oeth.fo.1Slowep1.1: The SFurveillanCce tFreq1uepncy_is controlled_ 1.-un er---* e .urve1-. ance requency on ro rogram . . Veri_fying theco0rect alignment for each manual v.al ve 'i'n the SGIG .System required flow ,paths provides assurance that *the propef'.Jlow*-paths exist 'for sysfem operation. _This SR do_es . not applY-to valves that .are locked or otherwise secured* in continued B :3. 6-26 Revision No. 87 _. J. *. BASES SURVEILLANCE REQUIREMENTS .PBAPS IJNJT 3 SR 3.6.1.3.7 (continued) . PC IVs B 3.6.1.3 *position, sirice these valves were verified to be in the correct position prior to locking or securing. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.8 Verifying isolation time of each power operated automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.9. The isolation time test ensures that .the valve will isolate in a time period less than or equal to that assumed in the safety analyses: The isolation time is in accordance with Reference 2 or the requirements of the Inservice Testing Program which ever is more The Frequency of this *sR is in accordance with the requirements of the Inservice .Testing Program.' SR 3.6,1.3.9 Verifying that the isolatton time of each MSIV is within the specified limits is to demonstrate OPtRABILITY. The isolation test ensures that the MSIV will isolate . in a time period that does not Exceed the times assumed in the This that the calculated radiological consequ'ences of these events remain within 10 CJR 50,67 l i irhts. as-m*Odi tied. 1 n Regulatory Gui de i .183, . Table 6. The Frequency of .*this SR is in accordance with the requireriients of *the Inse:rvice Testing Program. SR 3.E(l.3.10 ,* PCIVs clcise ona p_rimary :containment isolation _*. si gna J tb -prevent lea kqge *of radioactive** materi_a l from* *primary containment following a DBA.* This s*R ensures that each qutomatic pcr'v will *actua.te*to its .isolation position on *a Pr:-imary containment is:olation The LOGIC SYSTEM** continued B 3.6--27 Revision No ... 87 l *. BASES SU RV EI LLANC E REQUIREMENTS SR 3.6.1.3.10 (continued) PC I Vs B 3.6.1.3 FUNCTIONAL TEST in LCD overlaps this SR to complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency* Control Program. SR 3.6.1.3.11 This SR requires a demonstration that a representative of reactor instrumentation line excess flow check valve (EFCVs) is OPERABLE by verifying that the valve actuates to the isolation position on a simulated instrument line break signal. The sample consists of an approximately equal number of EFCVs, such that each EFCV is tested at least once every 10 years (Nominal). In addition, the EFCVs in the sample are representative of the various plant configurations, models, sizes. and operating environments. This that any common problem with a specific type of application of EFCV is detected at the earliest possible time. This SR provides assurance that the instrumentation line EFCVs will perform so that predicted radiological consetjuences will not be exceeded during a postulated instfument line break event. The Surveillance Frequency is controlled under the Surveillance Frequency Control Progr.am . . S R 3 . 6 :1 . 3 . 12 The .TIP shear isolation valves are actuated by eiplosive . An in place functional test is not possible with 'this design. The explosive squib is removed and tested to pr.ovide assurance that the valves will actuate when The replacement tharge for the explosive squib shill be from the same manufactured batch as the one fired Dr from another batch that has been by hiving one of the batch successfully fired. The Surveillance Frequency is controlled under the Surveillance Frequency Program.

• continued B 3*.6-28 *Revision No. 87.* ...
• . '*, BASES SU RV EI LLANCE REQUIREMENTS (continued) PBAPS UN IT 3 SR 3.6.1.3.13 PC I Vs B 3.6.1.3 This SR ensures that in case the non-safety grade instrument air system is unavailable, the SGIG System will perform its design function to supply nitrogen gas at the required pressure for valve operators and valve seals supported by the SGIG System. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.1.3.14 Total leakage through all four main steam lines must bes 170 scfh, ands 85 scfh for any one steam line, when tested. at.* 25 psig. The analysis in Reference 1 is based on treatment of MSIV leakage as secondary containment bypass leakage, independent of the primary to secondary containment leakage analyzed at La. The Frequency is in accordance with the Containment Leakage Rate Testing Program. SR 3.6.1.3.15 Verifying the opening of each 6 inch and 18 inch primary . containment purge valve and each 18 inch primary conta{nmenf* exhaust valve is by a blocking device to less than or equal to the required opening angle specified in the UFSAR CRef. 4) is to ensure that the valves can close OBA conditions within the times in the analysis of Re.ference 1. If a LOCA occurs, the purg.e and exhaust to primary containment leakage wi.thin the values assumed in the accident analysis. At other ti.mes pressur1zation concerns riot present, the purge valves can be *.fully Dpen: is control le& under the Surveillance Control P0ogram.
• continued B 3.6-29 *Revision No.

BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS UNIT 3 SR 3.6.1.3.16 PC I Vs B 3.6.1.3 The inflatable seal of each 6 inch and 18 inch primary containment purge valve and each 18 inch primary containment exhaust valve must be replaced periodically. This will allow the opportunity for replacement before gross leakage failure occurs. 1. UFSAR, Chapter 14. 2. UFSAR, Table 7. 3 .1. 3. 10 CFR 50, Appendix J' Option B. 4. UFSAR, Table 7. 3 .1, Note 17. 5. UFSAR, Table 5. 2. 2. 6. UFSAR, Table 7. 3 .1, Note 14. 7. NEDC-33566P, Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3' Constant Pressure Power Uprate, " Revision 0. B 3.6-30 Revision No. 119 Drywell Air Temperature B 3.6.1.4 B 3 *. 6 CONTAINMENT SYSTEMS B 3.6.1.4 Drywell Air Temperature BASES BACKGROUND The drywell contains the reactor vessel and piping, which, add heat to the airspace. Drywell coolers remove heat and maintain a suitable environment. The average airspace temperature affects the calculated response to postulated Design Basis Accidents (DBAs). The limitation on the drywell average air temperature was developed as reasonable, based on operating experience. The limitation on drywell air temperature is used in the I safety analyses. APPLICABLE SAFETYANALYSES Primary containment performance is evaluated for a spectrum of break sizes for postulated loss of coolant accidents (LOCAs) *(Ref. I). Among the to the design basis analysis is.the initial drywell average air temperature (Ref. I). Analyses assume an initial average drywell air temperature of 145°F. This limitation ensures .that the safety analysis,remains valid by maintaining the expected initial conditions and that the peak LOCA Leo *.. --.. ,: . ' PBAPS UNIT . drywe 11. temperature does not exceed the maxi mum a 11 owab le temperature of 281°F 2) except for a brief peiiod of less than 20 seconds which was determined*to be acceptable in References .J and 3. Exceeding this design temperature may result .in the degradation of the primary containment structure under accident loads. *Equipment inside primary

• containm*ent required to mitigate the effe.cts of a DBA is -designed *to operate and. be cap ab 1 e of under *envit:'omriental. cond1tions expected for the accident. Drywell air satisfies Criterion 2 of the NRC
• Policy Statement. ** ** * :-*-* : --,,. '* ... -. , In the event of a DBA, with. an in it i a r drywel f average air less than or equal to the LCO temperature 1 imi,t, the r.esultarit peak accident temperature is maintained within acceptable limits* for*the drywell.' As a result, the ability of pri mar.Y containment to perf oim its des i gri fun ct ion is . .
• en$Ured; : . . *-** .: ';. .'. ' .. . , B 3.6-31 Revision No. *20* I i i -_ ... ..-., ! .*>'. I I. . : -. *1 .* ,* ' ; Drywell Air Temperature B 3.6.1.4 BASES (continued)
• APPLICABILITY ACTIONS . SURVEILLANCE * . REQUIREMENTS . *:*.:.. , . , ... * : . '-: *' ' .. --.*.:. >; ;*:.' .; .. In MODES 1, 2, and 3, a OBA could cause a* release of radioactive material to primary containment. In MODES 4 and 5, .. the probability and consequences of these events are reduced due to the and temperature limitations of these. MODE$.
• Therefore, maintaining drywell average air temp.erature within the J imit' is not required in MODE 4 or 5. . '
• With* drywel l average air temperature not within the l i mit of *the LCO, drywell average air temperature must be. restored within 8 hours. The Required Action is necessary to return operation to within the bounds of the primary containment analysis.* The 8 hour .Completion Time is acceptable,
• considering the* of the analysis to* variations in this.parameter,*and provides sufficient time to correct
• minor problems. B 1 and. B. 2 . If the *drywe ll average a i*.r temperature cannot be restored to within the limit*within the required Completion Time, the plant must be brought to a MODE in which the. LCO does :not apply* Jo achieve th1s status, the plant ITIUSt be brought.to at Teast'MODE 3 within 12 hours and to *MODE 4 within . 36. * . .The allowed Completion Times are *reasonable, based on operating experience,-to reach plant cqnqhioils from .full power cond_itions jn 11ri orderly manner . and without cha l] engi ng pl ant systems. . . . *' .... ,: . . Jhe LCOJimit* ens*ures that:operation within ;for .*p.r_imary *containment* .. analyses. . * *
• temperature* inonitored in .varJoLis quadrants ..
• and 'at :vari<>>us Due to the shape of the drywel l, a* voi u111etHc average:* is: *used.*to .determine an accurate<} *representation of the actual*average* * ** *. -.-.* '. *--' ' ,' . -. <<* :.::.-. : J ---., . * * .* .. Jcontinued) *,, _ .. ::*: ._._... --* . -* . -;-,*.*. __ ._!* * .. ...... __ c:_.-* -:::._' .... . -: :. __ --. *--;-.. . '-** ::; .. _,*t-, -;:" *. * .. -*;. ..... : ... : . .-._, --' . --::-,,.

BASES SURVEILLANCE REQUIREMENTS REFERENCES . . PBAPS UN n-3 SR 3.6.1.4.1 (continued) Drywell Air Temperature B 3.6.1.4 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. UFSAR, Section 5.2.3.1. 3. Deleted Revision No. 119 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 B. 3.6 CONTAINMENT SYSTEMS B 3.6.1.5 Reactor Building-to-Suppression Chamber Vacuum Breakers BASES BAC_KGROUND . . : PBAPS UNIT .3

• The function of the reactor -building-to-suppression chamber vacuum breakers is to relieve vacuum when primary containment depressurizes below reactor building pressure. If the drywell depressurizes below reactor building pressure, the negative differential pressure is mitigated by flow through the reactor building-to-suppression chamber vacuum breakers and through the drywel l vacuum breakers. The design of the external (reactor building-to-suppression chamber) vacuum relief provisions consists of two vacuum breakers (a check valve and an air operated butterfly valve), located in in each of two lines from the reactor building to the suppression chamber airspace. The butterfly valve is actuated by a differential pressure signal. The check valve *is self actuating and can be manually operated for testing purposes. The two vacuum breakers in series must be closed to maintain a leak tight primary containment boundary. A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, . primary containment spray actuation, and steam condensation in the event of.a primary system rupture. *Reactor buil dirig-to-suppression chamber vacuum breakers prevent an excessive negative differential pressure across the containment boundary. Cooling cycles result in minor pressure transients in.the drywell, which occur slowly arid are normally cqntrolled by heating .. and equipment. _Inadvertent spr.ay actuation results in a
• sighificant negative pressure transient is the design basis event postulated in sizing the external (reactor chamber)-vacuum breakers, * . . . -. . . .. . ,*. . *_ The external vacuum breakers are sized on the basis of the .* ' air fl OW from the secondary containment that is. required. to mitigate the depr-essur.ization transient and limit the . * .. maximum negative containment (suppressiOn chamber) pressure to within design limits. The maximum depressurization rate is a .function of the primary containment spray flow rate and. temperature and the assumed initial conditions of the (continued).*. B 3.6..:34 .
• Reviiiori No.-0 I I

-: .. >** BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAP$ UNIT 3 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 suppression chamber atmosphere. Low spray temperatures and atmospheric conditions that yield the minimum amount of noncondensible gases are assumed for conservatism. The Safety Grade Instrument Gas CSGIG) System supplies pressurized nitrogen gas (from the Containment Atmospheric Dilution (CAD) System liquid nitrogen storage tank) as a safety grade pneumatic source to the CAC System purge and exhaust isolation valve inflatable seals, the reactor building-to-suppression chamber vacuum breaker air operated isolation butterfly valves and inflatable seal, and the CAC and CAD Systems vent control air operated valves. The SGIG System thus performs two distinct post-LOCA functions: (1) supports containment and (2) supports CAD System vent-operation. SGIG System requirements are addressed for each of the supported system and components in LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)," LCO 3.6.1.5, and Reactor Building-to-Suppression Chamber Vacuum Breakers." For the SGIG System, liquid nitrogen from the liquid nitrogen storage tank passes through the liquid nitrogen vaporizer where it is converted to a gas. The gas then flows into a Unit 2 header and a Unit 3 header separated by two manual globe valves. From each header, the gas then branches to each valve operator or valve seal supplied by the SGIG Each branch is separated from the header by a manual globe valve and a check valve. To support SGIG System functions, the nitrogen inventory is equivalent to a storage tank minimum required level of 2 22 inches water column, or a technically justified source of inventory 2 124,000 scf at 250 psig, and a minimum required SGIG System header pressure of 80 psig. Analytical methods and assumptions involving the reactor building-to-suppression chamber vacuum breakers are used as part of the accident response of the containment systems. Internal Csuppression-chamber-to-drywell) and external (reactor building-to-suppression chamber) vacuum breakers continued B 3.6-35 Revision No. 91 ,-. ' BASES APPLICABLE SAFETY ANALYSES (continued) LCO ** _: __ *. . . 'PBAPS *UNIT 3 .. Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 are provided as part of the primary containment to limit the negative differential pressure across the drywell and suppression chamber walls, which form part of the primary containment boundary. *

• The safety analyses assume the external vacuum breakers to be closed initially and to be fully open at 0.75 psid. Additionally, of the four reactor building-to-suppression chamber vacuum breakers (two in.each of the two lines from the reactor building-to-suppression chamber airspace), one is assumed to fail in a closed position to satisfy the single active failure criterion. Design Basis Accident * (DBA) analyses require the vacuum breakers to be closed initially and to remain closed and leak tight with positive primary containment pressure. Three cases were considered in the safety analyses to determine the adequacy of the external vacuum breakers: . . a .. **.A small break loss of coolant accident followed by actuation*of both drywell spray loops; b. Inadvertent actuation of one drywell spray loop during normal operation; and c. *.A postulated OBA assuming 1 ow pressure coo 1 ant
• flow out the loss of coolant accident which *condenses the drywe 11 steam. The results of these three cases' show that the external *vacuum breakers, with. an opening setpoint of 0. 75 psid, are capable.of maintaining the differential pressure within design limits .. * * *** * .chamber vacuum breakers satisfy Criterion 3 of the NRt .Policy StatemenL * * *.All b1.(ilding-to-suppressior:i yacuum breakers >are requi.red to be OPERABLE to. satisfy the assumptions used in the .. safety analyses. 'The requirement ensures that the two vacuum. bre.akers .(check v.alve and air operated butterfly valve) in each of the two lines. fro*m the reactor building to (cont.; nued} 'a 3.6-36,' Revision Noc.a**

BASES LCO (continued) APPLICABILITY ACTIONS* .. *,-PBAPS UNIT. 3 ** Reactor Chamber Vacuum Breakers B 3.6.1.5 the suppression chamber airspace are closed. Also, the requirement ensures both vacuum breakers in each line will open to relieve a negative pressure in the suppression chamber (except during testing or when performing their intended function). In addition, for the reactor chamber vacuum breakers to be considered OPERABLE and closed, the SGIG System supplying nitrogen gas to the air operated valves and inflatable seal of the vacuum breakers must be OPERABLE. .In MODES 1, 2, and 3, a OBA could result in excessive negative differential pressure across the drywell wall caused by the rapid depressurization of the drywell. The event results in the limiting rapid depressurization of the drywell is the primary system rupture, which purges the drywell of air and fills the drywell free airspace with steam .. Subsequent condensation of the steam would result in depressurization of the drywell. The limiting pressure and temper*ature of the primary system prior to a OBA occur in MODES l, 2, an(f 3. Excessive negative pressure inside primarycontainment could also occur due to inadvertent initi atton of the Drywel l Spray System.

• In MODES 4 and 5, the probability and consequences of these events. are reduced .due *to the pressure and temperature limitations in these maintaining reactor building-to-suppression :chamber vacuum breakers OPERABLE is. not required in MODE 4 or 5. A Note has *been added to provide cl.arification that, for the . purpose of this LCO,. Condit ion entry is a 11 owed for
• each penetration flow path. *. A. l * .-.... _.-._.
• With one or niore}lines with one vacuum breaker ntit closed,
• the leak tight. priniary containment boundary may be* *
• threatened ... Therefore, the inoperable vacuum breakers must **be restored to OPERABLE status or *the open* vacuum breaker . *closed within 72 ho*urs. The. 72 hour Completion Ti me is cor'l'sistent with requirements for inoperable* suppression *.*. *chamber,..to-drywe] l vacuum .breakers. in LCO 3. 6 .1. 6, (con tin Lied)
• B 3.6.:37 Revision No. o. *..: .*'

BASES ACTIONS PBAPSUNIT3 !*, Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 A.1 (continued) 11 Suppression Chamber-to-Drywel l Vacuum Breakers. 11 The 72 hour Completion Time takes into account the redundant capability afforded by the remaining breakers, the fact that the OPERABLE in. each of the lines is closed, and the low probability of an event that *would require the vacuum breakers to be OPERABlE during this period . .Ll With one or more lines with two vacuum not closed, primary containment integrity is not maintained. Therefo.re, one open vacuum breaker must be closed within 1 hour. This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restored to OPERABLE status within 1 hour. I_,_l With one line* with one or more vacuum breakers inoperable for opening, the leak tight primary containment boundary is intact. The ability to mitigate an event that causes a containment depressurization is threatened if one or more vacuum breakers in at least one breaker penetration -are not OPERABLE. Therefore, the inoperable vacuum breaker must be restored to OPERABLE status within 72 hours. This is consistent with the Completion Time for Condition A and the fact that the leak tight primary containment boundary is being *maintained.

• D.l If line.has one or more breakers. inoperable for opening and they are not restored within the Completion Time in Condition C, the remaining vacuum breakers in the remaining line can the opening function. The plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must -be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or 1 lower than the risk in MODE 4 (Ref. 1) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is *also an acceptable low-risk state. The Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued) B 3.6-38* Revision No .. 67 I I BASES Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 ACTIONS ..E_,_l (continued) SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 . With two lines with one or more vacuum breakers inoperable for the primary containment boundary is intact.* However, in the event of a containment depressurization, the function of the vacuum breakers is lost. Therefore, all vacuum breakers in one line must be restored to OPERABLE status within 1 hour. This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour. F.1 and F.2 If any Required Action and associated Completion Time for Conditions A, B, or E cannot be the plant must be brought to a MODE in which the LCO does not To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The* allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions .in an manner and without challenging plant systems. SR 3.6.1.5.1 Verifying that 'the nitrogen inventory is equivalent to a level ih the liquid nitrogen tank 22 inches water column 124,0dO scf at 250 psig} ensure at least 7 days of post-.LOCA SGIG System operat{on. This minimum volume of nitrogen allows sufficient time after accident *I to replenish the nitrogen supply in order to maintain the* desigrr function 6f the reactor buildjng-io-suppression. vacuum breakers.* The inventory is verified to ensure that the system is* capable of pert'orll]ing its intended isolation furicti6n when required. Surveil*lance Frequency is under Surveillance Control Program.-SR 3.6.1.5.2 This SR ensures that the pressure in the SGIG System header 80 psig .. This ensures that the post-LOCA nitrogen pressure to the valve operators and valve seals thatis. adequate for the SGIG to.perform its design . *
• functi.ori.* .The .Surveillance Frequency is controlled under the SurVeilJance continued
• B 3. 6-39 Revision.No. 91.

BASES SURVEILLANCE REQUIREMENTS (continued) . PBAPS: UN I.T 3 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 SR 3.6.1.5.3 Each vacuum breaker is verified to be closed to ensure that a potential breach in the primary containment boundary is not present. This Surveillance is performed by observing local or control room indications of vacuum breaker position or by verifying a differential pressure of 0.75 psid is maintained between the reactor building and suppression chamber. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Two Notes are added to this SR. The first Note allows .reactor building-to-suppression chamber vacuum breakers opened in conjunction with the performance of a Surveillance to riot be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable breakers. A second Note is included to clarify that vacuum breakers open due to an actual differential pressure, are not considered as failing this SR. SR 3.6.1.5.4 .*Verifying the correct alignment for each manual* valve in the SGIG System required flow paths provides assurance.that the proper flow paths exist for system operation: This SR does not apply to valves that are locked or otherwise secured in position, since these valves were verified to be in the correct position prior to locking or securing. This SR does not require any or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.6-40 Revision No. 87 I

• -' .*. / BASES SURVEILLANCE REQUIREMENTS (continued) ' : -*-.** . :* *-:-: .. ,,-, .. PBAPS UNIT. 3 * ... *. Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5 SR 3.6.1.5.5 Each vacuum breaker must be cycled to ensure that it opens properly to perform its design function and returns to its fully closed positi6n. This ensures that the safety analysis assumptions are valid. The Surveillance Frequency is controlled under the Frequency Control Program. SR 3.6.1.5.6 Demonstration of air operated vacuum breaker opening setpoint necessary to ensure that the safety analysis assumption regarding breaker full open of s 0.75 psid is valid. Surveillance Frequency is controlled under the Surveillance Frequency Control Program .. SR .. 3.6.1.5.7 This SR ensures that tn case the non-.safety gr.ade i nsfrLJment afr system is :unavailable, the SGJG System will perform its furiction gas at the required * . press'u.re for valve operators *and valve seals supported by theSGIG System. *The*Surveillance Frequency .is contro.lled .. **.1

• under the Surveillance* Frequency Control Prog.ram. 1. ** NEDC-32988'...A, Revision 2, J.ustificati6n to. Support Risk-I l'Jfornied Modificat-i on to Se.l ected Re qui red *. States for BWR Pl ants, Dee.ember Z002 . . .. : . _*._,,_. ,* .. .-. ,*.: *. l_**. ,,'" .. '-.** 8 .3.6-41 *Revision No. 87 .*,*-
• . . . . . . ' : ,;-. .--.*. H * * .. '*; *., ; .** ',:l .** I .,, ' *, *.* (i .** -.: .. --,< *. --. Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 B 3.6 CONTAINMENT SYSTEMS B SuppressionChamber-to-Drywell Vacuum Breakers BASES . -'*:: . '-.:* *-,. *; .. The function of the-suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell. There are 12 1nte_rna l vacuum breakers located on the vent header of the vent system between the drywell and the suppression . chamber, which allow air and steam flow from the suppression chamber to the drywell when the drywell_ is at a negative pressure with respect to the suppression chamber. Therefore, suppression ch*amber-to-drywell vacuum breakers .. prevent*an excessive negative differential pressure across the wetwell drywell boundary. Each vacuum* breaker is a self actuating_ valve,. similar to a check valve, which can be remotely for testing purposes. -. A pressure across the drywell wall is caus.ed by rapid depressurization of the drywell. Events . 'that ca.use-this rapid depressurization are cooling cycles, dryweJl and steam condensation from* sprays or .subcoo led *water refl ood of a break in the event of a
• primary system rupture *. :: Cooling cycles:*result .in minor . pressure 'transients* i.n the drywell that. occur slowly *and are normaJly controlled by* heating and ventilation equipment. _
• Spray.actuati.on.or**spill of subcooled water.out-of a*break
• results::in. more significant pressure transients and becomes import.ant in sizing th(i'nternal vacuum _br_eakers. ',,-* lri th'e of"a *primary. system ruptureL:steam condensation * '.within .the drywell 'results in .the most severe pressure ... *. **.*. -transient .. Foll<>wlng"a.primary system rupture,. air in* the * * :dr;YWell' is' purged Jnto t_he *suppression--chamber free .' . ._ .
• airs pace, . l Jig the
• dr-Yw.e l l. full *.of steam.
• Subsequent* condens*aticfn* of.the 'stean1can be caused in .two'possible * ** * \;lays, Emergency-'to_re Cooling Systems .flow from a ' .... .line 'break, :or :drywell spray 'actuation .*-' *. ;fo]lowfng* aJoss of* coolant. accident These. two *. *cases :-cfetermi,ne t_he ion rate. of the . drywell-> .>.. * ** ** .. * * ;!* .* -.. * .. :**. ,.-ln-in the Mar-k _I Vent SystelTI . downcomer is controlled by the . .-*.'* . r'.: .. chamber differential pressure-.
• If the _drywel 1 pressure is .. < 1 ess than the suppress fon 'chamber pressure' there* will be ' .::*. -,Jricrease in the vent waterJ eg 'Thi$ will/ result in ... ari . *** . * .-,.: .. , , * .: * :.-_': .. :*** :'.,,_. *. _.*:: . *No.* 0 * *-_,. .*.-..:*-i -:: .. ;-.. -._, PBAPS UNIT** 3. * . " **-, .. _ ... : ' .. :::** . ':: .,,._.. *=*--.,.*. ; .* _:-I BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS UN IT 3 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 increase in the water clearing inertia in the event of a postulated LOCA, resulting in an increase in the peak drywell pressure. This in turn will result in an increase in the pool swell dynamic loads. The internal vacuum breakers limit the height of the waterleg in the vent system during normal operation. Analytical methods and assumptions involving the suppression vacuum-breakers*are used as patt of the accident response of the primary containment systems. Internal and external (reactor building-chamber) vacuum are provided as part of the primary containment to limit the negative differential pressure across the drywell and suppression chamber walls that form part of the primary tontainment boundary. The safety analyses assume that the internal vacuum breakers are closed and are fully open at a differential pressure of 0.5 psid. Additionally, 1 of the 9 internal vacuum breakers required to open is assumed to fail in a closed position. The results of the analyses show that the design pressure is not exceeded even under the worst case accident scenario. vacuum breaker opening differential pressure setpoint and the requirement that 9 of 12 vacuum breakers be OPERABLE are a result of the requirement placed the breakers to limit the .vent system waterleg height. The total cross sectional cirea of the main vent system the drywell and suppression thamber needed to fulfill this has been established as a minimum of 51.5 times the total break area. In turn, the vacuum relief capacity the drywell and suppression cha'mber be 1/16 of total main vent cross sectional with the Set to operate at 0.5 psid differential pressure. *This was the original basis for Peach. Bottom, which requ1red 10 18" vacuum breakers to meet the* 1/16 of the total main vent cross sectional area. However, the current design basis requirement for 9 breakers required to be operable, one of which is assumed to fail to open (single active failure), is found in Reference 2. Design Basis Accident (OBA) analyses require the vacuum* breakers to be closed initially and to remain closed and leak tight, until the suppression pool is at a pressure relative to the drywell. All suppression to-drywell breakers are considered closed if a leak test confirms that the bypass area between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole (Ref. 1). The suppression chamber-to-drywell vacuum breakers satisfy Criteriqn 3 of the NRC Policy Statement. (continued) Revision-No. 44
• l* .. "' BASES (continued) Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 LCO Only 9 of the 12 vacuum breakers must be *oPERABLE for opening. All suppression chamber-to-drywell vacuum breakers are required to be closed (except when the vacuum breakers are performing their intended design function). All suppression chamber-to-drywell vacuum breakers are considered closed, even if position indication shows that one or more vacuum breakers is not fully seated, if a leak test confirms that the bypass area between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole. The vacuum breaker OPERABILITY requirement provides assurance that the drywell-to-suppression chamber negative differential pressure remains below the design value. The requirement that the vacuum breakers be closed ensures that there is no excessive bypass leakage should a APPLICABILITY ACTIONS. . '*. * ;* .. PBAPS UNIT 3 LOCA occur.
• In MODES 1, 2, and 3, a OBA could result in excessive negative differential pressure across the drywell wall, caused by the rapid depressurization of the drywell. The event that results in the limiting rapid depressurization of the drywell is the primary system rupture that purges the drywell of air and fills the drywell free airspace with steam. Subsequent condensation of the steam would result in depressurization of the drywell. The limiting press.ure and
• temperature of the primary system prior to a OBA occur* in* MODES I, 2, and 3. Excessive negative pressure inside the drywell could also occur due to inadvertent actuation of the Drywell Spray System. . . ' . . In.MODES 4 and 5, the probability and* consequences of these events are reduced by the pressure and temperature * *
• limitations in .these MODES; therefore, maihtaining . suppression chamber-to:-drywel l vacuum br.eakers OPERABLE is *not required in MODE 4 or 5. ' ' . . . . : With one of the required vacuum breakers inoperable for. . *opening (e.g., the vacuum breaker is not open and may be closed or not wifhin its opening setpoint limit, that it function as designed during an event that depressurized the drywell), the remaining eight OPERAB.LE vacuum breakers are capable of vacuum relief function. However, overall system reliability is reduced *:* . (continued)*, B 3 .6.:44
• Revis1ori 0 BASES ACTIONS PBAPS. UNIT 3 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 A.1 (continued) because a single failure in one of the rema1n1ng vacuum breakers could result in an excessive suppression differential pressure during OBA. Therefore, with one of the nine required vacuum breakers inoperable, 72 hours is allowed to restore the inoperable vacuum breaker to OPERABLE status so that plant conditions are consistent with those assumed for the design basis analysis. The 72 hour Completion Time is considered acceptable due to the low probability of an event in which the remaining vacuum breaker capability would not be adequate. If a required suppression chamber-to-drywell vacuum breaker is inoperable for opening and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized. To achieve this status, the must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating *experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging pl ant systems .. An open vacuum breaker allows between the drywell and suppression chamber airspace, and, as a result, there is the potential for suppression chamber overpressurization due to this bypass leakage if a LOCA were to occur. Therefore, the open vacuum breaker must be closed. A short tfme is allowed to close the vacuum breaker due to the low probability of an event that would pressurize primary containment. If vacuum breaker position indication is not reliable, an alternate method of verifying that the vacuum breakers are closed must be performed within 10 hours.* All suppression chamber-to-drywell vacuum breakers are considered closed, even if the "not fully seated" indication is shown, if a leak test confirms that *.the bypass area between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole (Ref. 1). The required 10 hour Completion Time is considered adequate to perform this test. If the leak test fails, not only must the Actions be taken (close the open vacuum breaker within 10 hours), but also the appropriate Condition.and Required Actions of LCO 3.6.1.1, Primary Containment, must be entered. continued B 3.6-45 Revision No. 67

. ; '.._ *. :'*' BASES ACTIONS SURVLI LLANCE REQUIREMENTS :' :. PBAPS UN IT. 3 D.l and D.2 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6 If the open suppression chamber-to-drywell Vacuum breaker cannot be closed within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.1.6.l Each breaker is verified closed to ensure that this potential large leakage path is not present. This Surveillance is performed by observing the breaker position .ind-ication or by performing a leak test that confirms that the bypass area between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole. -If the bypass test fails, not only must the vacuum *breaker(s) be considered open and the appropriate Cond1tions and Required Actions of this LCO be entered, but al.so the and Required Action of LCO 3.6.l;l must be entered. the Surveillance Frequency is I. controlled under the Frequency Control Program. A is to this $R whfch suppressioh t_o-drywell.-vacuum breakers -opened in conjunct.ion with the Surveillance to not be considered as failing this SR. These of,opening_ vacuum breakers are control led by pl ant-procedures and do not represent breakers. * . " :_,_, SR 3.6.l.6.2 Ea.ch.required breaket *.must be cYtl ed to that* . to.perform its desJgn function and return_s-to tJJe fulJ.Y c_losed position. This ensures that the* . safety,ana}ysis .. assumptions are vali,d .. The. -Frequency ,.is -.cdritrol:led un.der the Survei 11 a nee *Frequency*. Cb n t r pl -P ro g contin'ued . . . .-,',.** -B 3. 6-46 Revision No. 87

• BASES SU RV EI LLANCE REQUIREMENTS (continued) REFERENCES { Suppression Vacuum Breakers B 3.6.1.6 SR 3.6.1.6.3 Veri fi ca ti on i:Jf the vacuum breaker setpoi nt for full opening is necessary to ensure that the safety analysis assumption regarding vacuum breaker full open differential pressure of 0.5 psi-dis valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 127 and 130 to Facility Operating License Nos. DPR-44 and DPR-56, . February 18, 1988. 2. ME-0161; Actual # Wetwell to Drywell Vacuum Breakers Reqd." . ' 3.. NEDC-32988-A, Revision 2, Technical Justification to Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. ... --; -. ,. . ' . .. -_.*. --., .* *. -..,. *-*.*: .,,*_ ,--' ,. ' . .B 3.6-47 *. Revisiori 87 I .. -:>

. * .. Suppression Pool Average Temperature B 3.6.2.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.1 Suppression Pool Average Temperature BASES BACKGROUND The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the decay heat and.sensible energy released during a reactor blowdown from safety/relief valve discharges or from Design Basis Accidents (DBAs). The suppression pool must quench all the *steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment that ensures that the peak containment pressure is maintained below the maximum allowable pressure for DBAs (56 psig). The suppression pool must also condense steam from steam exhaust in the turbine driven systems (i.e., the High Pressure Coolant Injection System and Reactor Core Isolation Cooling System}. Suppression pool average temperature (along with LCD 3.6.2.2, "Suppression Pool Water Level") is a key indication of the capacity.of the suppression pool to fulfill these requirements. The technical concerns that lead to the development of suppression pool average temperature limits are as follows: a. Complete steam condensation-the origin.al 1 imit for the end-of a LOCA blowdown was 170°F, based on the Bodega Bay and Humboldt Bay Tests; b. Primary contai.nment peak pressure and * .design pressure is 56 psig and design temperature is 281°F l); . c. Condensation oscil 1 at:ion 1 oads-maximum a 11owab1 e initi.al temperature is 110°F. APPLICABLE The postulated OBA against which the primary containment SAFETY ANALYSES performance is evaluated is the entire spectrum of postulated pipe breaks within the primary containment. Inputs to the safety include initial suppression pool water volume and suppression pool temperature (Ref. 2) . . An initial pool temperature of 95°F is assumed for the (continued) PBAPS UNIT 3 ,. . B 3.6-48 No: -0 .. *,. ' . BASES APPLICABLE SAFETY ANALYSES (continued) LCO *.*.'. PBAPS UN IT 3 .

• Suppression Pool Average Temperature B 3.6.2 .. 1 Reference 1 and Reference 2 analyses. Reactor shutdown at a pool temperature of Il0°F and vessel depressurization at a pool temperature of 120°F are assumed for the Reference 2. analyses. The limit of 105°F, at which testing is terminated, is not used in the safety analyses because DBAs are assumed to not initiate during unit testing. Suppression pool average temperature satisfies Criteria 2 and 3 of the NRC Policy Statement. A limitation on the suppression pool average temperature is required to provide assurance that the containment conditions assumed for the safety analyses are met. This* limitati.on subsequently ensures that peak primary containment pressures and temperatures do not exceed maximum allowable values during a postulated DBA or any transient resulting in heatup of the suppression pool. The LCO *.requirements are:
• a. Average temperature 95°F when any OPERABLE wide range neutron monitor (WRNM) channel is at 1.00EO % power* or above and no testing that adds heat to the suppression pool is being performed. This requirement ensures that licensing bases initial conditions are b. c. met.
• Average temperature 105° F when any OPERABLE WRNM charine 1 is at 1. OOEO % power or above and testing that adds heat to the suppression pool is being *performed. required value that the unit has testing . flexibility', and .was selected to provide margin below the l10°F l iniit at which reactor shutdown is required .. When testing ends, temperature must be restored to
• 95°F within.24 hours atcording to Required *. Action A.2 .. Therefore, the time period that the. temperature is> 95°F*is short enough not to cause a.* significant in unit.risk.. . * . . . . . . . . 110° F when all WRNM '.*.
• channels are below % power. This requirement* ensures that the unit wil 1 be shut down at > 110° F. . The pool is designed to absorb heat and sensible heat but could be heated beyond design limits by the steam generated if the reactor is not shut down. {continued) : B 3.6-49. Revision *No. 17 BASES LCO (continued) APP LI CAB IL ITV ACTIONS PBAPS UNIT 3 . Suppression Pool Average Temperature B 3.6.2.1 Note that WRNM indication at l.OOEO % power is a convenient measure of when the reactor is producing power essentially equivalent to 1% RTP. At this power level, heat input is approximately equal to normal system heat losses. In MODES 1, 2, and 3, a OBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining suppression pool average temperature within limits is not required in MODE 4 or 5. A.I' and A.2 With the suppression pool average temperature above the specified limit when not performing testing that adds heat to the suppression pool and when above the specified power indication, the initial conditions exceed the conditions assumed for the Reference 1, 2, and 3 analyses. However, *primary containment cooling capability still exists, and the primary containment pressure suppression function will occur at temperatures well above those assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The 24 hour Completion Time is adequate to allow the suppression pool average temperature to be restored below the limit. Additionally, when suppression pool temperature is > 95°F, increased monitoring of the suppression pool temperature is required to ensure that it remains 110°F. The ante per hour Completion Time is adequate based on past experience, which has shown that pool temperature increases relatively slowly except when testing that adds heat to the suppression pool is being performed. Furthermore, the once per hour Completion Time is considered adequate in view of other indications in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition. If the suppression pool average temperature cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the power must be reduced to below 1.00EO % power for all OPERABLE WRNMs within {continued} B 3.6-50 Revision No. 17 . . . . -

BASES ACTIONS . . ' . *---.. 'i PBAPS UNIT3 B.l (continued) Suppression Pool Average Temperature B 3.6.2.1 12 hours. The 12 hour Completion Time is reasonable, based on operating experience, to reduce power from full power conditions in an orderly manner and without challenging plant systems. Suppression pool average temperature is allowed to be > 95°F when any OPERABLE WRNM channel is at l.OOEO % power or above, and when testing that adds heat to the suppression pool is being performed. However, if temperature is > 105°F, all testing must be immediately suspended to preserve the heat absorption capability of the suppression pool. With the testing suspended, Condition A is entered and the Required Actions and associated Completion Times are applicable.

• E.l**and iE.2' ... ** if suppression poo1 **average. cannot be maintained ... ,at the *pl ant must brought to a MODE in which the LCO not apply.* To achieve. this status, the reactor.
• prfi?ssure must be reduced < 200'psig within 12 hours; and the pl must brought to at: least-MODE 4 withitj * . ** _ .. * * * * * ... (contiriued) " ' *_.,,... : . : . B '3.6-51 *** Revision 17 --.-.

,*. BASES ACTIONS SURVEILLANCE REQUIREMENTS REFERENCES . ..,. *, BAPS UNIT 3 Suppression Pool Average Temperature B 3.6.2.1 E.l and E.2 (continued) 36 hou0s. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. Continued addition of heat to the suppression pool with suppression pool temperature> 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure. Furthermore, if a blowdown were to occur when the temperature was > 120°F,*the maximum allowable bulk and local temperatures could be exceeded very quickly. SR 3.6.2.1.1 The suppression pool is regularly monitored to ensure that the required limits are satisfied. The average temperature determined by taking an arithmetic average of OPERABLE suppre$sion pool water temperature channels. The Surveillance is controlled under. the Surve_i 11 ance Frequency Control Program. The 5 minute Frequency durtng testing is justified by the r a t e s a t .w h i c h t e s t s w i 1 1 .h e a t up t h e s Li p p re s s i on p o o 1 , h a s been shown to be acceptable based on operating experience, arid that allowable pool =temperatures not exceeded. The Freque*ncy is further. j usti fi ed in view of other in the control room, tncluding alarms, to alert operator to ari abnormal suppression poo.l average temperature coriditi on. 1. . 5 .i. 2. NED(-33566P; "Safety Analysis Report for Exelon Peach . Atomic Power Untts i, Constarit *Pressure Power:.LJprat_e,_'; Revision o . 3* . .. ... . ,-**. B Revisio.n No*. 119 Suppression Pool Water Level B 3.6.2.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.2 Suppression Pool Water Level BASES BACKGROUND

• PBAPS UNIT 3 The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the energy associated with decay heat and sensible heat released during a reactor blowdown from safety/relief valve (S/RV) discharges or from a Design Basis Accident (OBA). The *suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment, which ensures that the peak containment pressure is maintained below the maximum allowable pressure for DBAs (56 psig). The suppression pool must also condense steam from the steam exhaust lines in the turbine driven systems (i.e., High Pressure Coolant Injection (HPCI) System and Reactor Core Isolation Cooling (RCIC) System) and provides the main emergency water supply source. for the reactor vessel. The suppression pool volume ranges between 122,900 ft3 at the low water level limit of 14.5 feet and 127,300 ft3 at the high water level limit of 14.9 feet. *
• If the suppression pool water level is too low, an insuffici.ent amount of water would be available to adequately the steam from the S/RV quenchers, main vents, or HPCI and RCIC turbine exhaust lines. Low suppression pool water level could also result in an inadequate emergency makeup water source to the Emergency Core Cooling System. The*lower volume would also absorb ** less steam energy before heating up excessively. Therefore,. a minimum suppressiOn pool water level is specified. If pool water level is too high, it could
• result in excessive clearing loads from S/RV discharges and excessive pool swell loads during a OBA LOCA. Therefore, a pool water level is specified. Thii LCO specifies an acceptable range to prevent the suppression pool water from being either too high or too low. (continued) B* 3*.6*53 .. Revision O **

I ;* i ,._ Suppression Pool Water Level B 3.6.2.2 BASES (continued) APPLICABLE Initial suppression pool water suppression SAFETY ANALYSES pool temperature response calculations, calculated drywell pressure during vent clearing for a OBA, calculated pool swell loads for a OBA LOCA, and calculated loads due to S/RV discharges. Suppression pool water level must be maintained w1thin the limits specified so that the safety analysis of Reference 1 remains valid. LCO APPLICABILITY ACTIONS PBAPS UN IT* 3 Suppression pool water level satisfies Criteria 2 and 3 of the NRC Policy Statement. A limit that suppression pool water level 14.5 feet and s 14.9 feet is required to ensure that the primary containment conditions assumed* for the safety analyses are met. Either the high or low water level limits were used in the safety analyses, depending upon which is more conservative for a particular calculation. In MODES 1, 2, and 3, a OBA would cause significant loads on the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. The *requirement for maintaining suppression pool water level within limits in MODE 4 or 5 is addressed in LCO 3.5.2, "ECCS_:_Shutdown". With suppression water level outside the the, conditions .assumed.for the safety analyses are not met. If .*water level is below the minimum level, the pressure *. suppression function still long main vents are HPCI and RCIC turbine covered, and . S/RV quenchers are covered. If suppression pool water leve_l .

• is above the maximum 1eve1 ,
• protection against.*
• overpressurization still *exists due to the *margin in the. . peak containment pressure analysis and the capability of the'
• Drywell Spray System.* Therefore, continued operation for a
• limited time is allowed. The 2 hour Completion Time is
• to restore stippression poril water level to within . 1 i mi ts.
• A 1 so, -it takes into account the low probab.il ity. of ... *an event impa_cting the suppression pool water level .occurring duritig this interval.* (continued).* B 3.6-54 . Revi ston No. 0 ** :.L BASES ACTIONS (continu.ed) SURVEILLANCE REQUIREMENTS REFERENCES . PBAPS 'UN IT. 3 B.1 and B.2 Suppression Pool Water Level B 3.6.2.2 If suppression pool water level cannot be restored to within limits within the required Completion the plant must be brought to a MODE in which the LCD does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. SR 3.6.2.2.1 Verification of the suppression pool water level is to ensure that the required limits are satisfied. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Sections 5.2 and 14.6.3. B 3.6-55 Revision No. 87

'.; ;* '-. *****:: __ . RHR Suppression Pool Cooling B 3.6.2.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.3 Residual Heat Removal (RHR) Su.ppres.sion Pool Cooling BASES BACKGROUND :*:*_-.* .. PBAPS UNIT 3 Following a Design Basis Accident (OBA), the RHR Suppression Pool Cooling System removes heat from the suppression pool. The suppression pool is designed to absorb the sudden input of heat from the primary system. In the long term, the pool continues to absorb residual heat generated by fuel in the reactor core. Some means must be provided to remove heat from the suppression pool so that the temperature inside the pr i ma r y con t a i nm en t rem a i n s wit h i n d e s i g n l i m it s .

• T h i s function is provided by two redundant RHR suppression pool cooling subsystems. The purpose of this LCD is to ensure that both subsystems are OPE.RABLE in applica.ble MODES. Each RHR suppression pool cooling subsystem contains two motor driven pumps, two heat exchangers and a heat exchanger cross .tie line, and is manually initiated and independently The t0o perform the suppression pool cooling functioh by circulating from the pool the RHR heat exchangers and returning it to the suppression* pool via the full flow test lines. *The High Pressure Service Water. CHPSW) System circulating through the tube.side.of the heat exchangers, exchanges heat with the suppression poor.water*and discharges this heat to the external. heat s.ink.
• The heat remov a-l. c apa bi l ity .of one RH R pump and two heat exchange'rs in on*e subsyste,m. ar*e sufficient to meet the -overal'l DBA poOl *cooli hg -requirement for loss of cool ant _accidents (.LOCAs): and. transient events such as a turbine trip or stuck' open safety/.telief valve (S/RV). S./.RV leakage and Hi g[l Pressure Cocil ant: Injection System* and. _Reactor. Core Isolation Cooling .$ystem_ testing.increase* suppression pool * ** temperature more -s fowl y .. -The RHR Suppress ion. Pool Cooling: .**System.is also.usedtolower .. the suppression pool-water bulk -temperature following such ev.ents. ----Each is eq'uippe'd with ah RHR heat. exchanger cross t 1 e 1 i ne,
• rqcate.d down.st re9rrf of ea ch :RHR 'pump* discharge and -ream. of each.-'heat exchanger inlet, which allows ot)e -RHR* . pump to tie aligned tp supply both. RHR heat exchangers in the .. * -same subsystem for' sup_pressi on pool cooling when only one_ RHR ,pump is_availab.le. Th.e RHR, heat exchanger cross tie V.alve is nq.rmally. closed, -and. is ass*umed by basis. analyses to be placed fn. service on.e hour following .a design basis _ 'or .triins'i ent when 'i:r:isuffi tient el ectrtc power js .. --*available (e.g., -single EOG failure) to operate** two RHR pl:Jmps .* iii. a * -' * .*. -* * ',,_' -(continued). , __ -Revision * **'* >**'-;. ' '

I I . , _.* RHR Suppression Pool Cooling B 3.6.2.3 BASES (continued) APPLICABLE SAFETY ANALYSES LCD. APPLICABILITY ACTIONS* PBAPS .l:JNH 3

• Reference 1 contains the results of analyses used to predict primary containment pressure and temperature following large and break LOCAs. The intent of the analyses is to demonstrate that the heat removal cap9city of the RHR Suppression Pool Cooling System is adequate to maintain the primary containment conditions within design limits. The suppression pool temperature is calculated to remain below the design limit. The RHR Suppression Pool Cooling System satisfies Criterion 3 of the NRC Policy Statement. During a OBA, a m1n1mum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below design limits (Ref. 1). To ensure that these req0irements are met, t0o RHR suppression pool cooling subsystems must be OPERABLE with power from two safety related independent power supplies. Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active failure: *An RHR suppression pool cooling is OPERABLE when one of the pumps, two heat exchangers in the same RHR subsystem, the associated heat exchanger cross tie line, two HPSW System pumps capable of providing cooling to the two heat exchangers and associated-pip1ng, valves, instrumentation, and co.ntrols are OPERABLE.* Management of gas voids is important to RHR Suppression Pool Cooling System OPERABILITY.* In MODES 1, 2, and 3, a OBA could cause a release of radioactive material to primary containment and cause a heatup arid pressuriza'tion_-of primary containment. In MODES 4. and 5,. the prohabllity*-and consequences of these are due to. th"e pressure. and temperature l.imi.tations in t_hese MODES. Therefore, th.e RHR Suppression Pbol system to be OPERAaLE in MODE 4 *or_ 5. -* ., A: 1
• one RHR suppression pool-cooling the :inoperable subsystem mustbe .restored. to OPERAB.LE status within*7-days." In_ this Condi.tion, the remctining RHR. sup-pressi""on -pool cooling subsystem is* adequate to perform -the primary containment cooling -function .. However, the continued . -.. 128 BASES ACTIONS UN IT 3 ). A.l (continued) RHR Suppression Pool Cooling B 3.6.2.3* overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment cooling capability. The 7 day Time is acceptable in light of the redundant RHR suppression pool. cooling capabilities afforded by the OPERABLE subsystem and the low probability of a OBA occurring during this period. If one RHR suppression pool subsystem is inoperable and is riot restored to OPERABLE status within the required Time, the plant must be brought to a condition in which the ov.erall plant risk is minimized. To* achieve this status, the plant must be brought to at.least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the System to OPERA&LE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating*experience, to reach the required plant conditions from full power conditions in an orderly manner and without thallenging plant systems.
• C.1 With two *RHR suppression pool cooling subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 houri. Iri this condition, there is a substantial loss of the containment and temperature mitigation functioh.
• The 8 -hour Completion Time is based on this loss of arid is acceptable.due to the low of a OBA and because alternative methods to remove heat from primary containment are available. 0.1 and D.2 If the Required Action and associated Completi,on Time of Condition C carrnot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within* 12 hours and to MODE 4 within 36 hours. The allowed Completi6ri Times are reasonable, based on operating to reach the required plant conditions from full* power conditions iD an orderly manner and without challenging plant systems. (continued) 'ReVi!?iOn No. 6:7' I

,. *. 1,., RHR Suppression Pool Cooling B 3.6.2.3 BASES (continued) SURVEILLANCE REQUIREMENTS . ; ; PBAPS *UN IT 3 SR 3.6.2.3.1 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that valves capable of being mispositioned are in the correct position. This SR does not apply to valves that be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program. SR 3.6.2.3.2 Verifying that each required RHR pump develops a flow rate 8,60D gpm while operating in the suppression pool cooling mode with flow thrbugh the_ associated heat exchanger that pump performance. has not degraded during the cycle. Flow is a riorma l test of centrifugal pump performance ' required by ASME Code (Ref. 3). This test confirms one point on the* pump design curve, and the results are of overall performance. Such inservice -_inspections con.firm component OPERABILITY, trend .--performance, and detect by The Frequency of this SR is in with.the Testing SR 3.6.2.3.3 of manual between the normal and aliernate s9urce emergency'bus) for each RHR flow control valve and RHR cross-tie. motbrcoperated valve demonstrates. that AC power will be. available to operate the required valves following loss power t'o*any si'ngle* 4kVemergency bus.* The ability to> C cont i nueq)

• B 3.6_-59 . Revision No. 119 BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 3. SR 3.6.2.3.3 (continued) RHR Suppression Pool Cooling B 3.6.2.3 provide power to each RHR motor-operated flow control valve and each RHR cross-tie motor-operated valve from either of two independent 4kV emergency buses ensures that a single failure of a DG will not result in failure of the RHR operated flow control valve and the RHR cross-tie operated valve; therefore, failure of the manual transfer capability will result in inoperability of the associated RHR Suppression Pool Cooling subsystem. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.2.3.4 RHR Suppression Pool Cooling System p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR Suppression Pool Cooling Subsystems and may also prevent water hammer and pump cavitation. Selection of RHR Suppression Pool Cooling System locations susceptible. to gas accumulation is based on a review of system design information, including piping and .instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could citherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. The RHR Suppression Pool Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations: If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, *the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Suppression Pool Cooling System is not rendered inoperable by the accumulated gas (i.e., the system is (continued) Revision No. 129*

BASES SURVEILLANCE REQUIREMENTS REFERENCES * .. : .' .-* *-. -. -. ,. .. -.-.-*---.-PBAPS UN IT 3 SR 3.6.2.3.4 (continued) RHR Suppression Pool Cooling B 3.6.2.3 *sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits. RHR Suppression Pool Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not chal.l enge system OPERABILITY. The accuracy of the. method used for monitoring the susceptible locations and trending of the results should be *sufficient to assure OPERABILITY the Surveillante interval . . The. SR.is modified by a Note. The Note recognizes that the* of the limited to the RHR components .. The HPSW system components have been determined *to not be required to be.in the scope of this surveillance due' to operating experterice and the* desi of the system. The Surveillance Frequency is cootrolle.d ynderthe Survei 11 ance Frequency. c.ontrol Program. The Surveillance Frequency may. vary .by l. ocati on suscepti bie to gas accumulation. *

• 1. 2 .. to .. Support* Informed Modifi ca ti on to Selected Required . End Sta.tes for BWR Plants, December 2002..
• _,.:: --*.* .,3; .ASME for *operation and M.aintenance of Nuclear Power Plants.;* B .. Revision No. 128 I .

RHR Suppression Pool Spray B 3.6.2.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray BASES BACKGROUND PBAPS UN-IT 3 .:-** .. Following a Design (OBA), the RHR Suppression Pool Spray System removes heat from the suppression chamber airspace. The suppression pool is designed to absorb the sudden input of heat from the primary system from a OBA or a rapid depressurization of the reactor pressure vessel (RPV) through safety/relief valves. The heat addition to the suppression pool results in increased steam in the suppression chamber, which increases primary containment pressure.' Steam blowdown from a OBA can also bypass the suppression pool and end up in the suppression chamber airspace. Some means must be provided to remove heat from the suppression thamber so that the pressure and temperature inside primary containment remain within analyzed design limits.*. This provided by two redundant pool spray subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES*. Each of the RHR suppression pool spray subsystems two driven pumps, two heat exchangers and a heat exchanger cross tie 0hich are manually initiated and independently controlled. The two RHR pool spray subsystems perform the pool spray function by circulating water from the suppression through the RHR heat exchangers and returning it to the suppression pool spray The only accommodate a small portion of the total RHR pump flow; the remainder of the flow. returns to the suppressiorr pool through the suppression pool cool i n g. return l i n e , * *Thus , both suppress i on . pool cool i n g and pool are when Suppression S.Ys:tem is initiated; High* Pressure Water, circu'lating through the tube. side of the heat exchangers_, exchanges heat with the suppression pool water a*nd di.scharges this heat to the external h-eat sink. Either . RHR suppress1 on pool spray 'subsystem is sufficient to

• co.ridense the steam from srriall bypass leaks from the .dryw*ell to the suppression airspace during the postulated .* OBA,. -. -. . Each suppression pool spr:ay subsystem-:is-equipped _with a .* cr._oss tfeline, 'downstream of each RHR.pumpdischarge*_ and upstr:eam-o-f each heat-*exchanger in1et", whlc:h allows one .. RHR-pump :to _be aligned to sup_ply both RHR heat exchangers in co t inued B 3.6-60 Revisi6n:-No.' 119 *.** .

BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES LCO APPLICABILITY . PBAPS UN IT 3 RHR Suppression Pool Spray B 3.6.2.4 the same subsystem to remove additional heat from the suppression pool when only one RHR pump is available ..

• The cross tie is normally closed, and is assumed by design basis analyses to be placed in service one hour following a design basis accident or transient when electric power is available to operate two RHR pumps in a subsystem. Reference 1 contains the results of analyses used to predict primary containment pressure and temperature following large ahd small break loss of coolant accidents .. The intent of. the analyses is to demonstrate that the pressure reduction capaci*ty of the RHR Suppression Pool Spray System is adequate to maintain the primary containment conditions within design limits. The time history for primary pressure is calculated to demonstrate that the maximum pressure remains below the design limit. The RHR Suppression Pool Spray System satisfies Criterion 3 of the NRC Policy Stateme.nt. In the event of a OBA, a minimum of one RHR suppression pool spray subsystem is required to mitigate potential bypass leakage paths and maintain the primary containment peak below design limits (Ref. 1). To.ensure that .these requirements are met, two RHR suppression pool spray subsystems must be OPERABLE with power from two related independent power supplies. Therefore, in the event of an at least one subsystem is OPERABLt the worst case single active failure. An RHR suppression subsjstem is OPERABLE when one of the pumps, two heat in the same. subsystem, the associated heat exchanger cross tie line, two HPSW System pumps capable of providing cooling to the two:heat exchangers and associated p i p i n g , v a l. v e s , i n st rumen t a t i on , a n d con t r o l s a re 0 P ERA B LE . Management of gas voids is important to RHR Suppression Pool Spray System OPERABILITY. In MODES 1, 2, and 3, a OBA could cause pressurization of primary in MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining RHR suppression pool spray subsystems OPERABLE is not required in MODE 4 or 5. Ccont1nued) B Revision No. 128 i BASES (continued) RHR Suppression Pbol Spray B 3.6.2.4 ACTIONS A.1 PBAPS UN IT 3 *. With one RHR suppression pool spray subsystem inoperable, the inoperable subsystem be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE RHR suppression pool spray .subsystem is adequat'e to perform the primary containment bypass leakage mitigation function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment bypass mitigation capability. The 7 day Completion Time was chosen in light of the redundant RHR suppression pool spray capabilities afforded by the OPERABLE subsystem and the low probability of a OBA occurring during this period. With both RHR suppression pool spray subsystems inoperable,
• at least one subsystem must be restored to OPERABLE status within 8 hours. In this Condition, there* is a substantial loss of the primary. containment bypass leakage mitigation function. The 8 hour Completion Time is based on this loss. of function and is considered acceptable due to the low probability of a OBA and because alternative methods to remove heat from_ primary containment are available. c*. 1 *I
• If *the inoperable RHR suppression pool spray subsystem(s)
• I cannot be restored to OPERABLE status within the associated the plant must be ,to a MODE which-the overall plant risk_ is minimized. *To achieve this .I status, the plant must be brought to least MODE 3 within-12 hours. Remaining ih the Applicabiiity of the LCD is
• acceptable because the plarit risk .in MODE 3 is similar *to or. lower than the risk in (Ref. and because the time in 3 iu perform the necessary repairs to the system to OPERABLE status wi 11 be However,
• voluntary entry into MODE*A may be made as it is also an' acceptable Jow-0isk state; The allowed Completion Time is reasonable. _on operating experience, to reach the required plant conditions from full conditions in an orderly manner and without.challenging *plant systems. ( conti ri"t:ied) . -_. . -.* B 3. Revision No. 67
• RHR Suppression Pool Spray B 3.6.2.4 BASES (continued) SURVEILLANCE REQUIREMENTS. PBAPS UN1T 3 SR 3.6.2.4.1 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR suppression pool spray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This .is acceptable since the RHR suppression pool cooling mode is manually ini.tiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the . Surveillance Frequency Control Program. SR 3.6.2.4.2 This Surveillance is performed to verify that the spray nozzles are not obstructed and that flow will be provided when required. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.2.4.3 Deleted (continued) B 3.6-63 Revision No. 132

• ...

• BASES SURVEILLANCE REQUIREMENTS (continued) .PBAPS UNH 3 SR 3.6.2.4.4 RHR Suppression Pool Spray B 3.6.2.4 RHR Suppress1on Pool Spray System p1p1ng and components have potential to voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR Suppression Pool Spray Subsystems and may also prevent water hammer and pump cavitation. Selection of RHR Suppression Pool Spray System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings; isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the locatiori and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as versus operating conditions. The RHR Suppression Pool Spray System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are est.a bl i shed for the volume. of accumulated gas at susceptible locations.* If accumulated is discovered that exceeds* the-acceptance ctiteria for the susceptible location (or the volume Df accumulated gas at -bne or susceptible exceeds an acceptance criteria for gas volume at the. or discharge of a pump), the is not met. If *the gas is eliminated or brought within **the *acceptance criteria limits durfng performance of the Surveil lanc.e, the SR is* met and pa.st system OPERABILITY is evaluated u'nder the Corrective Action Program. *If it is determined by: subseque.nt.evaluatiori that the RHR Suppression Pool Spray Systeni is .notrenc;Jered inoperable by the accumulated gas ( i '. e .*, the system is suffi ci entl y fi 11-ed * * .. with water), t-he Survei 1.1 ance*.may be decl. a red met. *
• Accuniul ated gas should be :el or.* orought within the .* accet:i.tan.ce.. crite.ri a limitS*. *
• RHR .Supp,ressi on Yooi" .Spray System l oc.ati Olis susceptible to *ga*s accu"mulatioh a re moriitored and, ff ga"s. is found' the. * . . gas volume .. is ccimpa red to the acceptance criteria for 'the location; locations in the sanie system flow .. path*wh.ich iJre subject, tot.he same gas ihtrusion mechanisms* may. be .verified by' monitoring a: representative subset of* st.iscepti b.i e*:*1 ocati ons*, .. Monitoring may n.ot be practical. for *locatlons that.are inaccessible due to"radfol6gical or.***. *. envi ronmentai condi.tions, .fhe pl ant tonfi gurati0n, or *
• safety;. Fbr these allernative methods (e.g:, *operating parameters',* remote monitoring) may be used *. '* *(continued) B3,6-63a* Revision No.:: 129 **'* '

BASES .. e,,c.-, __ *.:-. SURVf I LLANCE REQUIREMENTS -REFERENCES PBAPS UNIT 3--RHR Suppression Pool Spray B 3.6.2.4 SR 3.6.2.4.4 (continued) to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and dete'rmi ned to not cha 11 enge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval. The SR is modified by a Note. The Note recognizes that the scope of the surveillance is limited to the RHR system components. The HPSW system components have been to not be required to be in the scope of this surveillance due to operating experience and the design of the*system. The Surveillance Frequency is c6ntrolled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas *accumulation.

• 1. UFSAR; Sections 5.2 and 14.6.3. 2: 2, Technical Justification to Support Risk-Informed Modi fi ca ti on. to Selected Required End States for BWR Plants, December 2002. ..-si on No*. 128 I . -

RHR Drywell Spray B 3.6.2.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.5 Residual Heat Removal CRHR) Drywell Spray BASES BACKGROUND PBAPS .UNIT 3 Drywell Spray is a mode of the RHR system which may be initiated under post accident conditions to reduce the temperature and pressure of the primary containment atmosphere. The Drywell Spray function is credited in design basis analyses to limit peak drywell temperature following a steam line break inside of the Drywell and may be used to mitigate other loss of coolant accidents of the Drywell. This function is* provided by two Dry0ell Spray subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable_ MODES. of the RHR drywell spray subsystems contains two motor driven pumps, two heat exchangers and a heat exchanger tie line, which are manually initiated and independently controlled. The two RHR drywell spray subsystems perform the drywell spray function by circulating water from the suppression pool through the RHR heat exchangers and discharging the cooled suppression pool water into the drywell air space through the drywell spray sparger and spray nozzles. The spray then effects a temperature arid pressure reduction through the combined effects of evaporative and convecti*ve cooling, depending on the drywell atmosphere. If the atmosphere is superheated, a rapid evaporative cooling pr6cess will If the environment in the drywell is temperature and pressure wil1 be reduced via a convective cooling process. spray sparger line is supplied by independent RHR drywell spray subsystem. If re qui red, a* small portion of the can be to the pool spray sparger and spray noziles. Service Water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water on the shell side of the heat exchangers and discharges this heat to the external heat sink. Eac_h drywell spray subsystem is equipped with_ a RHR heat exchanger cross-tie line, located downstream of each RHR pump discharge and of each heat exchanger inlet, which allows one RHR pump to: be aligned to* supply both RHR heat exchangers in the same subsystem to provide additional containment heat removal capability when only one RHR pump is. available. The RHR heat exchanger cross-tie *is normally closed, and is assumed in the design basis analyses to be placed in* service one hour following a design basis accident cir when insufficient electric power is available to operati; two RHR pumps i'n a subsystem. . (continued)_* Revision No . .rzs. I ,.*I BASES (continued) APPLICABLE ANALYSES LCO APPLICABILITY .. -... .PBAPS UN n* 3 RHR Drywell Spray B 3.6 . .2.5 Reference 2 contains the results of analyses used to SAFETY predict primary containment pressure and temperature response following a spectrum of small steam line break sizes. Steam line breaks are the most limiting events for drywell temperature response, since steam has higher energy content than liquid. These analyses, with primary focus on the drywell temperature response, take credit for containment sprays and structural heat sinks in the drywell and the suppression pool airspace. These analyses demonstrate that, with credit for containment spray (drywell and suppression pool), drywel l temperature is maintained within limits for Environmental Qualification (EQ) of equipment located in the drywell for the analyzed spectrum .of small steam line breaks. The RHR Drywell Spray System satisfies Criterion 3 of the NRC Policy Statement. In the event of a sma 11 steam line break in the drywel l , a minimum of RHR drywell spray subsystem is credited in the design analyses to mitigate the rise in drywell and pressure caused by the steam line break, and to maintain the primary containment peak temperature and pressure below the design limits (Ref. 2). To ensure that these are met, two RHR drywell subsystems (one in each loop) be OPERABLE with power from two iafety related power supplies. in . the event of an at least one is OPERABLE assuming the worst case single failure. An RHR drywell Spray subsystem is OPERABLE when one of the* pumps, .two heat exchangers in the same subsystem, the associated* RHR heat cross-tje line; two HPSW System pumps_ . . capabl,e of providing cooling to the two heat exchangers .and associated piping, valves, instrumentation, control.s .are OPERABLE. Management of gas voids is .important to RHR Drywell Spray -.* ... 1.*. OPERABILITY. In MODES 1, 2, and 3, a_ steam line break in the drywell. could rise in containment temperature and pressure. *In MODES 4 and 5, the probability and of steam line breaks are reduced* due to the pressufe and temperature in MODES. Therefore, maintiining RHR drywell spray subsystems

• dPERABLE is nbt required in MODE 4 or 5: . . (continued) B Revision No. 128 I
• BASES (continued) ACTIONS PBAPS UNIT 3 ** RHR Drywel l Spray B 3.6.2.5 With one RHR drywell spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE RHR drywell spray subsystem is adequate to mitigate the. effects of a steam line break in the drywell. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in ability to mitigate the temperature rise associated with a steam 1 i ne break in the drywel l, for which drywel l sprays are credited. The 7 day Completion Time was chosen in light of the redundant RHR drywell spray capabilities afforded by the OPERABLE subsystem and the low probability of a steam line break in the drywell occurring during this period. With both RHR drywell spray subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours. In this Condition, there is a substantial loss of the ability to mitigate the temperature rise associated with a *steam line break in the drywell, for which drywell sprays are credited. The 8 hour Completion Time is based on this loss of function is considered acceptable due to the low .probabi 1 i ty of a steam 1 i ne break in the drywel 1 and because alternative methods to remove heat from primary containment are available. C.l and C.2 If the inoperable RHR drywell spray subsystem(s) cannot be restored to OPERABLE status within the associated* Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. (continued) B 3.6-63e Revision No. 128 I BASES (continued) SURVEILLANCE REQUIREMENTS --*: ... --PBAPS UN IT 3 SR 3.6.2.5.1 RHR Drywel 1 Spray B 3.6.2.5 Verifying correct alignment for manual, power operated, and automatic valves in the RHR drywell spray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This *is acceptable since the RHR drywell mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not to valves that cannot be inadvertently misaligned, such as valves. Frequency is controlled the Surveillance Frequency Control Program: SR 3.6.2.5.2 This Survei 11 ance is performed to verify that the spray no?zles not -and that flow will be provided when required.** The Frequency is under the Surveillance Frequency Control Program . . . . SR.3;6.2.5.3 DeJeted *(continued) '. '*. --* ;.* B
• 3. 6 -.63f .. , Re vis.ion No. 132 I . I I i:1 BASES SURVEILLANCE REQUIREMENTS (continued) SR 3.6.2.5.4 RHR Drywell Spray B 3.6.2.5 RHR Drywell Spray System p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing managing gas intrusion and accumulation is necessary for proper operation of the RHR Drywell Spray systems and may also prevent water hammer and pump cavitation. Selection of RHR Drywell Spray System locations susceptible to gas accumulation is based on a review of system design information, piping and instrumentation drawings, isometric plan and elevati.on drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or .d.ifficult to remove during system maintenance or restoration. Susteptible locations depend on plant and system configuration, -such as stand-by versus operating conditions. The RHR Drywel l Spray System is OPERABLE wh.en it is sufficiently filled with water. Acceptance triteria are established for the volume of accumulated gas at susceptible locations. If accumulated is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria* for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance cri t.eri a l i m,i ts during performance of the the SR i.s met and past system: OPERABILITY is evaluated under the.Corrective Action Program. If it is determined *by subsequent evaluation that the RHR Drywell Spray is not rendered inoperable by the accumulated gas (i.e ... the. system is suffi ci entl y fi 11 ed _with water)' the Sufveilla:nce.may be: d_e.cl,ared met. Accumulate.d gas shou.ld be el imi n*ated .or*_-br609ht within the. acceptance criteria* limits.. * * -* * -. , _ RHR .Drywell Spray System locations susceptible.to gas accumulatfo.h a re rriorii to red and, if gas is found, the gas volume is.compar.ed .. to the acceptance criteria for the_ location* .. Suscepfi bl e locat.i ons *in the :Same 'systeriL flow*. -path-which:are .. *subjeet-tb the same gas-. intrusion mechanisms .may be-.v-erifi ed by rilohitciri ng *a repre*sentati ve subset of *susceptible lo.cations. Monitoring may not be practical for . -. -locations th,at ar_e inaccessib.le due to radiological or-* envir6n'menta'l conditions,-'ttie. plant configuration, br per'sonne-1 saf_ety. -Fcir these-*locations alternative methods -(e.g., o*perating parameters, remote monitoring) may be used to monitor the susceptible* 1 ocati on. ----Mani tori ng is not * (continued) PBAPS UNIT 3 Revisinn No. 129 BASES SU RV EI LLANCE REQUIREMENTS REFERENCES PBAPS UN IT 3 SR 3.6.2.5.4 (continued) RHR Drywell Spray B 3.6.2.5 required for susceptible where the maximum potential accumulated gas volume has evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the_*results should be sufficient to assure system OPERABILITY during the interval. The SR is modified by a Note. The Note recognizes that the scope of the.surveillance is limited to the RHR system c6mponents. The HPSW system tomponents have been determined to not be required to be in the scope of this surveillance to operating experience and the design of the system. The _Surveillance is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation. 1. UFSAR, Sections 5.2 and 14.6.3. 2. NEDC-33566P, "Safety Report for Exelon Peach -Bottom Station, Units 2 and 3, Constant Pressure Power Uprate," Revision_ 0.
• B .Revision No. 128 -!--,_* .**

B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Deleted CAD System B 3.6.3.1 . THE INFORMATION FROM THIS TECHNICAL SPECIFICATIONS BASES SECTION HAS BEEN DELETED. TECHNI{AL BASES PAGES B 3.6-65 THROUGH B 3.6-69 HAVE BEEN INTENTIONALLY OMITTED. ** .. * ... PBAPS. UN*IT 3 B 3.6-64 Revision No, 81 *._*. .,;--*-Primary Containment Oxygen Concentration B 3.6.3.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.2 Primary Containment Oxygen Concentration BASES BACKGROUND APPLICABLE SArETY ANALYSES PBAPS UNIT 3

• All nuclear reactors must be designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis. The primary method to control hydrogen is to inert the primary containment. With the primary containment inert, that is, oxygen concentration< 4.0 volume percent Cv/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration. The capability to inert the primary containment and maintain oxygen < 4.0 v/o works together with the Containment Atmospheric Dilution (CAD) System to provide redundant and diverse I methods to mitigate events that produce hydrogen. For example, an event that rapidly generates hydrogen from zirconium metal water reaction will result in excessive hydrogen in primary containment, but oxygen concentration remain< 4.0 v/o and no combustion can occur. Long term generation of both hydrogen and oxygen from radiolytic decomposition of water may eventually result in a combustible mixture in primary containment, except that the CAD System dilutes and removes hydrogen and oxygen gases faster than can be produced from radiolysis and again no combustion can occur. This LCD ensures that oxygen concentration does not exceed 4.0 v/o during operation in the applicable conditions. *The Reference 1 calculations assume that the primary containment is inerted when a Design Basis Accident loss of coolant accident occurs. Thus, the hydrogen assumed to be released to the primary containment as a result of metal water reaction in the reactor core will not produce combustible gas mixtures in the primary containment. Oxygen, which is subsequently generated by radiolytic decomposition of water, is diluted and removed by the CAD System more rapidly than it is produced. Primary containment oxygen concentration satisfies Criterion 2 of the NRC Policy Statement. (continued) B 3.6-70 -Revision No. 81 I i I I ,* .. *-' *' -:-, *.**. .. :* ,-;. . . . . ' . __ ,* ,._ **.: :,-.-' ... * /. __ Primary Containment Oxygen Concentration B 3.6.3.2 BASES (continued) LCO The primary containment oxygen is maintained* < 4.0 v/o to ensure.that an event that produces any amount -of hydrogen does not result in a combustible mixture inside APPLICABILITY . . . . ' -primary containment. The primary containment oxygen concentration must be within the specified limit when primary containment is inerted, except as al l_owed by the relaxations during startup and addressed below. The primary containment must be inert in MODE 1, since this is the condition with the highest probability of an event that could py-oduce hydrogen. -:__ . . . Inerting the primary.containment is an operational problem _ -because it prevents_ containment access without an appropriate breathing apparatus. Therefore, the primary containment 'is inerted as 'late as possible in the plant startup and de-inerted as soon as possible in the plant* -shutdown.
• As 1 ong as reac_tor power is < 15% RTP, the potential for an event that generates signi"ficant hydrogen is_ low .and the primary containment need not be inert. _ Furthermore, . the probab.i l i ty of an event that generates ;-... -hydrogen 9ccllrring within the first 24 hours of a startup, or within'the last 24 hours before a shutdown, is low eno1.:1gh -that' _these n_ *when the -primary -c*onta i nment is -not -fnerted; are also justified.* -The 24 .hour time period is a -' ... '* -._. reas*onable amount or t'ime-to. al 1 ow pl ant -personnel -_to -inerting of .de:..in_erting.------. *. ' -ACTIONS-** A.l '_ -------,_., .. -" . Jf *toncentration-_is >* 4.:0. v/o .a*ny while .. . _ __ 'MPOg_J;;. with the the rel
• _ _ _ _, _--allowe(f' during and shutdown;>oxygen* conc,entration __ -, ... -: . ./ -.,,.. . ., .. -iiiust'.be :restored.to<<( 4:.0 v/o withfn 24-hours. 24 hou_r Cc>>mpleti9,n when oxygen **-:'.: _: _ -__ :; ,:* >-4.,Q;.v/C> _be.tause;\of ttfe _availability of other hydroge_n . _ , -: CAD_ System)' arid .. the low * *-.::: . "_ .. * *.: .. :: . -:.. -. -.... . -:, .-,_ .,.. <. * .. *: *' ,** --..*. ,-: .. :* .*-* --PBAPS UNI f 3 ' --.--a:nd,1o*ng of an* event would-_* --. . 'generate,: significant amounts -of hydt:o.gen.otcurti ng' dliri ng' * ' .. :* * -' * * -* -* ----* * * .,**. ' c ;1' .,.. ..*:::. ;' .' -...... , .. :*-,._. ,, :.* ; ._ :: . . -* *: :--. --*.-,.<-j :_ :,_ . -:'* .** ..... :*,*:. ____ _--;.., __ *._ *., *.'-; . ,, _;_._ , .. * (continued) r-:: '.* ' ., -. . -q *-*.--*--' -.. *,. .",'o* . .....

' : -' BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS REFERENCES .*.* -.' ** .. PBAPS UN IT 3 *** Primary Containment Oxygen Concentration B 3.6.3.2 If oxygen concentration cannot be restored to within limits the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, power must be reduced to$ 15% RTP within 8 hours. The 8 hour Completion Time*is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

• SR 3.6:3.2.1 The primary containment (drywell and suppression chamber) must be determined to be inert by verifying that oxygen concentration is*< 4.0 v/o. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Sectfon.5.2,3.9.5. . *.,'* . :*--3.6-72 Revi sjon No .. 87 Secondary Containment B 3.6.4.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.1 Secondary Containment BASES BACKGROUND APP LI CAB.LE SAFETY ANALYSES PBAPS UNIT 3 The function of the secondary containment is to contain and hold up fission products that may leak from primary containment following a Design Basis Accident (OBA). In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves lines penetrate the secondary containment, the secondary containment is designed to reduce the activity level of the fission products prior to release to the environment and to isolate and contain fission products that are released during certain operations that take place 1nside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment. The secondary containment is a structure that completely encloses the primary containment and those components that may be postulated to contain. primary system fluid. This structure forms a control volume that serves to hold up and dilute the fission It is possible for the pressure in the control volume to rise relative to the environmental pressure (e.g., due to pump and motor heat load additions). To prevent ground level exfiltration while allowing the secondary containment to be designed as a tonventicinal structure, the secondary containment.requires support systems to maintain the control volume pressure at less.than the external pressure. Requirements for these systems are specified separately in LCO 3.6.4.2, "Secondary Containmeti.t Isolation Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System." There are two principal accidents for which credit is taken for secondary containment OPERABILITY.. These are a 1 ass of coolant accident (LOCA) (Ref. 1) and a fuel handling accident inside secondary containment (Ref. 2) involving RECENTLY IRRADIATED FUEL.. The secondary containment performs no active function in response to each of these limiting events; (continued)
• Revision. No. 76
• BASES LCD. . . . APP l,.lCA13lLI TY .. :.*** . ,*, *.-. ,.,.. * <'. -. '** -. *.'*-'; *'-.* .. ,. *'*" ; ,* ";, **:, .. /. * ... **_ .' .< .* * .. _'..". "' .* .. -.... however, its leak tightness is required produc:ts entrapped within: the secondary will be treated the SGT' System prior envi ronrnent .. Secondary B 3.6.4.1 to ensure . containment structure to dis6harge to the *secondary containment satisfies Criterion 3 of the NRC Policy Statement. An OPERABLE secondary containment pro,vi des a c;ontrol vo.l.ume into which fission products that 1 eak .from primary or are released the coolant** boundary components located in secondary containment, can be processed prior to releaie to the envj ronment. . For the secondary containment to be considered *.
• OPERABLE, itmust have adequate leak tightness to ensure that the required vacuum can b,e established and maintained. In MODES 1, 2, .. and 3, a LOCA.could lead to a fission product release to primary containment. that .1 ea.ks to. secondary *
• containment.
• Therefore, secondary c.ontai nrnent OPERABILITY . is required* during the operating conditions that .**.require primary containm¢nt OPERABILITY. In MODES 4 and 5, *the pr=bbabi lity and. consequences of the > LOCA are reduced due to the pressure .and temperature ... 1 i mitati.ons in these MODES. . Therefore, mafo.tai ni ng ... * ****
• secondary .containment OPERABLE is .not required.in MODE '4; .. or 5, except for other s*Uuati ens for wl:Ji ch si gni fi ca.nt .* . . *releases of radioactive mated al can be postulated, .such. as . . * ..
• durirlg operations wi.th a' potential 'tor .. the reactor* *. *.*vessel (OPDRVs), or duritig movement of RECENTLY IRRADIATED ., FUEL as*sembl i es *1 n secondary co.ntai nment. However-;. * ...
• out$.ide ground ha:tches (hatches,.H20. throlJgh H24 arid* .. Torus room ac9E}ss: hatch H34.) may hot be bpened during .mc:iv.emel"'!t of irradi.ated fuel:
• This".wil'l maintain CR dose* *
• 1. e.*: ** . * ** .. * ;, **-:* .. _,;* . . . . --.. . . **.*** . . . . .* . . ; .**** . >* .... : . *i.f secondary is inoperable, it must be .resto;ed/' to OPERABLE status within 4 hours. The-'4 hbur Completion. ****. . Time provides a .. period Of time to correct the problem thcit . is .commensurate With the; iniportance of mai ntai ni rig s.econdary .
• dl.ir.fog MODES/1, 2, and 3 .. This ti me peri ad al so
• that the**probafiiiUy o-f*'an a.ccident: (requiring . ** "* . . .. c;ontai"t1ment occur,ri ng during pedpds *wheresec.ondary'containment,js inoperable.isminimar;** *.i ... .';** **'***--.. . *. ..,* ,_:*** -B 3,6-74. :. .
• si * ..... ... *; .. :_ : . .:-.., ... * . *.-:*

I.'. BASES ACTIONS* (continued) PBAPS UNIT .3 Secondary Containment B 3.6.4.1 If secondary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be btought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short.* However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. C.1 and C.2 Movement of RECENTLY IRRADIATED FUEL assemblies in the secondary containment and OPDRVs can be postulated to cause fission product release to the secondary containment. In .such cases, the secondary containment is the only barrier to release of fission products to the environment. Therefore, movement of RECENTLY IRRADIATED FUEL assemblies must be immediately suspended if the secondary containment is inoperable. Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position. Also, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended. Required Action C.1 has been modified by a Note stating that LCO 3. 0. 3 is not applicable,* si nee the movement of RECENTLY IRRADIATED FUEL can only be performed in MODES 4 and 5. (continued) B 3.6-75 Revision No. 76 Secondary Containment B 3.6.4.l BASES (continued) SURVEILLANCE REQUIREMENTS .. -., .. _*, .. -*' PBAPS UNIT 3 SR 3.6.4.1.1 Verifying that secondary containment equipment hatches are closed ensures that the infiltration of outside air of such a magnitude as to maintaining the desired negative pressure does not occur and provides adequate assurance that exfiltration from the secondary containment will not occur. In this application, the term "sealed" has no connotation of leak tightness. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.6.4.'l.2 Verifying that one secondary containment access door in each access openi.ng is closed provides adequate assurance that exfiltration from the secondary containment will not occur. An . access opening contains at least one inner and one outer door. In some cases, secondary containment access openings are shared such that there are multiple inner or outer doors. The intent is to not breach the secondary containment, which is achieved by maintaining the inner or outer portion of the barrier closed. SR 3.6.4.l.2 provides an exception to allow brief, unintentional, simultaheous opening of both an inner and outer secondary cbntainment access door. * .The Sur:vei 11 ance Frequency 'is contr.ol led under .the Survei 11 ance £ontrol Program.

• The SGT *system exhausts* the secondary containment atmosphere to the throµgh appropriate treatment equipment. Each SGT subsystem is'ciesigned_to dt,aw down pressure in the secondary containment to ;:::.*o.2.5 inches of vacuum water gauge ' in ::; 180 seconds and mai ntai )1_ pressure.in the secondary containment 0.25. ihches water* gauge.for 1 hour at a*flow rate ::;. .. 10,soo cfrn. To ensure that all fission * . produ-cts relea.sed. to tlie secm1darY containment are treated, , SR and 'SR 3.6A.l.4 verify that a p'ressure i.n the. setondarY conta.ii1inent this is .less than the i ow.est postu1 a fed -* pressure external the secondary tontainment bbtindary can *rapidly,be established,a.nd maintained. When the-SGT System is operating as designed, the.establishment and m*aintenance. of secondary *C:ontatnment pressure cannot be.accomplished if' the sfi;tond.ary cqntaiiiment bount;tary is not intact. * * . of this pressure As*confirme*d by SR J.6.4.1.3. * ' the secondary containment be' drawn *down to 0.25 inche's*or vacuum water: gauge in ::; 180 continued
• B 3.6-76 *Revision No. 122 _;:.

J'. BASES SURVEILLANCE* REQUIREMENTS REFERENCES PBAP-S UNIT 3 Secondary Containment B 3.6.4.1 3.6.4.1.3 and SR 3.6.4.1.4 (continued) seconds using one SGT subsystem. SR 3.6.4.1.4 demonstrates that the pressure in the secondary containment can be maintained 0.25 inches of vacuum water gauge for 1 hour using one SGT subsystem at a flow 10,500 cfm. The 1 hour test period allows secondary containment to be in thermal equilibrium at steady state conditions. The primary purpose of these SRs is to ensure secondary containment boundary integrity. The secondary purpose of these SRs is to ensure that the SGT subsystem being tested functions as designed. There is a Separate LCD with which serves the primary purpose of ensuring OPERABLITY of the SGT System. The inoperability of a SGT subsystem.does not necessarily constitute a failure of these Surveillances to the secondary containment OPERABILITY. The Surveillance Frequency is controlled under the Survei.l lance Frequency Control Program. 1. . UFSAR, Section 14.6:3. 2. UFSAR, Section 14.6.4. 3 NEDC-32988-A, -Revision 2, Technical Justification to Support Risk-Infbrmed Modificati-0n to Selected End States for BWR--Pl ants-, December 2002. . . :. B-3. 6-77 '. Rev i s i -on No . 9 7 I SC IVs B 3.6.4.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs) BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 The function of the SCIVs, in combination with other accident mitigation sy&tems, is to control fission product release during and following postulated Design Basis Accidents (DBAs} (Refs. 1 and 2). Secondary containment isolation within the time limits specified for those isolation valves designed to .close automatically ensures that fission products that leak from primary containment following a OBA, or that are released during certain operations when primary containment is not required to be OPERABLE or take place outside primary containment, are maintained within the secondary containment boundary. The OPERABILITY requirements for SCIVs help -ensure that an adequate secondary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. These isolation devices consist of either passive or active (automatic) devices. Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the .valve secured}, and blind flanges are considered passive devices. Autoni_ati c SCIVs close on a secondary containment i sol at ion signal to establish a boundary for untreated radioactive material within secondary containment following a DBA or .

• Other penetrations are isolated by the use bf the position or blind flanges. The SCIVs must be OPERABLE to ensure the secondary containment barrier to product is* . established. The principal accidents for which the secondary containment boundary is required are a loss of coolant accident (Ref. 1) and a fuel handling accident inside secondary containment (Ref. 2) involving RECENTLY IRRADIATED FUEL. The secondary containment performs no active function in response to either of these limitingevents, but the (continued) B 3.6-78 Revi_si on No. 76

' I ! *. * . : . '-.. ' :-, *. '. ---I I *: .**:.---":*--.. .. *.-...' :* .** *. '.*'.:.' .':;'. . .. '* .*.** _BASES APPLICABLE SAFETY ANALYSES (continued) LCO ' . '* ', .. ,_._ APPLICABILITY .. "'.; .-*' *.*-; . " . ; *;. SC IVs -B 3.6.4.2 boundary established by SCIVs is required to ensure that

• leakage from the primary containf!1ent is processed by the Standby Gas Treatment (SGT) System before being released to the environment. Maintaining SCIVs OPERABLE with isolation times within limits ensures that fission products will remain trapped inside secondary containment_ so that they can be treated by theSGTSystem prior to discharge to the environment. SCIVs satisfy Criterion 3 of the NRC Polity Statement. SCIVs form a part of the secondary containment boundary._ The_SCIV safety function is related to control of offsite radiation resulting from DBAs. _The power operated automatic isolation valves are OPERABLE when their isolation-times are within limits and the valves actuate on an automatic isolation signal . _ The valves covered by *this LCO, along With thei f associated: l)troke times, are listed in Reference 2 .. -The normally closed isola.tion valves or blind flanges arei considered OPERABl.,.E when. manual_ valves are closed or open j'l accordance with appropriate administrative controls, ---.* -. :automatic are and secured in their closed position, and bll nd fl an9es, are in pl ace.
• These passive -iso.lation vaives* or-devic_es-are listed: ih Reference 2. _ , -,_,* In MODES* 1, _-2, ,3; *.a OBA-could lead ta* a .. fjssion-.. ; rel ease to the* primary containment that to the . . __ .sec'ondary contain1T1ent .. : Therefore, *the OPERABILITY of SCIVs'. red-.* .... -. . . in MODES 4-arid, 1-ity consequences of .-_ ,. are r.educed due to 'pressure' ana' temperature .. * .. -. / 1 i riit tati in -:these_ MODES-;* Therefore, -nia1 ntai ni ng sc!Vs' * * '* OPERABLE 1.s not .fecfui red in MODE 4 or 5,-for o.the,r * >:. situations under '.which significant r_a-dioactive releases ca-n'--be -postulated, such as during operati'ons with a potent-I aJ -* ,_ . -* _ for _drai_ni_ng the . .reactor vessel * (OPDRVs). *or during -'.. -of_ RECENTLY IRRADIATED FUEL assemblies in th.e secondary ---__ corifai rimen:L " . ar¢ only required to be OPERABLE during,. -. .-hahdl-i ng RECEtiTL Y tRRADIATED FUEL. -Moving* *ii-radiated f pe_l'.,: * -*** assembl\es; ii'J _tbe SeCOJldary Containment may. al SO OGG.Ur 1n' , , ,, . -MODES' 1 , 2 , and 3 -. ----. , '
• _:.* . . . ... -.-. . ,.*,.. . ..... . . (continue.Cl) , '*: ,., . -*::'* :;, .. -.

! i I *1" * ..... : .. . *.-; *SCIVs 8 3.6.4.2 BASES (t6ntinued) ACTIONS .. *.: ..

• PBAPS UNlT 3 The ACTIONS are modified by three Notes.
• The first Note allows penetration flow paths to be unisolated intermittently under administrative controls. These controls consist of statiOning a dedicated operator, who is in continuous conununication with the control room, at the control.s of the isolation device. In this way, the penetration.can be rapidly isolated when a need for secondary containment isolation is indicated. The second Note provides clarification that for the .purpose of this LCO separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actionsfor*each Condition provide appropriate . compensatory actions for each inoperable SCIV. Complying *with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent Condition entry and application of associated Required Actions. The third Note ensures appropriate remedial actions are taken; if necessary, if the affected system(s) are inoperable by an inoperable SCIV. A. l and A.2 In the event that there are one or more pen et ration fl ow paths with one SCIV inoperable, the affected penetration flow must be i.solated.
• The method of isolation must include the of at least one isolatibn barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic SCIV, a closed manual valve, and a b 1 ind *flange. For penetrations isolated in accordance with Required Action A.1, the* device used to isolate the penetration should be the closest available device to secondary containment. The Required Action must be . completed within the 8 hour Completion Time. The specified time period is reasonable considering the time required to
• isolate the penetration, and the probability of a DBA, which requires the SCIVs to close, occurring during this short time is very *low .. For affected penetrations that have been isolated in * .. accordance with Required Action A.1, the affected must be verified to be isolated -0n a periodic basis. This is necessary to ensure that secondary * * (continued) B 3.6-80 Revision No. 0 BASES ACTIONS PBAPS UNIT 3 A.1 and A.2 (continued) SCI Vs B 3.6.4.2 containment penetrations required to be isolated following an accident, but no longer capable of being automatically isolated, will be in the isolation position should an event occur. The Completion Time of once per 31 days is appropriate because the isolation devices are operated under administrative controls and the probability of their misalignment is low. This Required Action does not require any testing or device manipulation. Rather, it involves .verification that the affected penetration remains isolated. Required .Action A.2 is modi1ied by two Notes. Note 1 applies to located in high radiation areas and allows them to be verified closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by means is consirlered acceptable, since the function of locking, sealing, or securing components.is to that these devices are not inadvertently * :Therefore, the probability of misalignment, onc'e they have been verified to be in the proper position, {s . B.l With two.SCIVs iii one or more penetration flow paths i noperab.l e, the affected penetration fl ow*. path'. must .be i scil ate,d within 4 ;hours:*. The* method of i sol ati on include the use of at least* one isolation barrier that can"not be adversely affected by a singl.e active failure: Isola*tiori. barriers* tha_t meet*this* criterion are a*closed *and . automatic vaive, a closed*"mantial .. valve, and a blind. f] ange *The. 4 hour Completion Time is *reasonable c:cinsiderirlg" the'time"required to. isolate the and th'e probabjlity of: a OBA, which requires tlie-SCIVs to close, occurr\r:ig. during this short time, -ls very low. . The Conditjon: has been modified by a Note stating that Condftior:i ,*({is only a*ppl*i2able* to pene_tratio)1 flow paths. 'wlth two isolation valves . .'/rhis clarifies that only . Condition A.is enter.ed if one *SCIV is inoperable _in each.of twci'. pi:fri'e,t r'a ti on s. * " . * * * , :cc on ti nu e d) B 3*. 6-81 Revision No. ss*

I BASES ACTIONS (continued) SURVEILLANCE -REQUIREMENTS ,. -* :,. -.' PBAPS UNIT 3 -C.1 and C.2 SCI Vs B 3.6.4.2 If any Required Action and associated Completion Time cannot be met, the plant must be brought to a MODE in which the LCO does not* apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required-plant conditions from full power conditions in an orderly m-anner and without challenging pl ant systems. D.1 and 0.2 If any Required Action and Completion Time are not met, tha plant must be placed in a condition-in which the LCO does not apply. If applicable, the movement of RECENTLY IRRADIATED FUEL_assemblies in the secondary must be immediately suspended. Suspension of this a6tivity shall not preclude c6mpletion of movement of a component to a safe position. Also, if applicable, actions must be immediately initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and the subsequent potential for product release. Actions must continue until OPDRVs are suspended. Required Action D.1 has been by B Note stating that LCO. 3 .. o.:ris not applicable*, sinc_e the movement of RECENTLY IRRADIATED FUEL can only beperformed in MODES 4 and 5. *. SR 3. 6. 4 .. 2. 1 This SR vefifies sec6ndary contaihment manual_ isolatiori_:valve ard bli.rld_.flange. that is not locked, sealed; or otherwis'e sec!Jred: and is required to be closed* during ac6ident conditions is The SR to pbst aticident leakage of fluids outside of _the' se_c;;ondary containment boundary-is wi-thi n design ' limits.* This SR does hcit require any testing or valve -mani ati on. it i rival ves veri_ fi cab on that those -SC IVs in secondary containment--that are capable of being-' mispositioned are in the.Correct position. (continued) .-'*. ,** .... -*. ' .. _ ... -_,-.-Revision .No. 76 BASES SUR VE I L LANCE *REQUIREMENTS PBAPS UN IT 3 -.... SR 3.6.4.2.1 (continued) SCI Vs B 3.6.4.2 The Surveillance Frequency is controlled under the I -Surveillance Frequency Control Program. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon sealing, securing. Two Notes added to this SR. The first .Note applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2,* and 3 for ALARA reasons. Theretore, the of misalignment of these SCIVs, once they been verified to be in the position, is low. A secohd Note has been included to clarify that SCIVs that are open under administrative controls are not required to meet the SR during the time the SCIVs are open. SR 3.6.4.2.2 Verifying that the isolation time of each power operated automatic-SCIV is within limits is required to demonstrate OPERAB-ILITY. The isolation time test-ensures tha-t-the SCIV \rllill isolate in a time period less than or equal to that assumed in the The Frequency of this SR is in accordance with Inservice Testing Program. SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a containment isolation signal is required to prevent leakage of radioactive material from secondary. following a OBA or other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position a secondary containment isolation signal. The LOGIC SYSTEM F_UNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation overlaps this SR to provide complete testing of the safety function. The Surveillance is controlled under the Surveillance Freguency Control Program. continued B -J. 6 "8"3, Revision No. 87

• BASES (continued) REFERENCES 'i .. 1. UFSAR, Section 14.9.2. 2. Technical Requirements Manual. B 3.v-84 SCI Vs B 3.6.4.2 Revision No. 87
• , i ' .... ' {* . 1i:.** -, __ ** SGT System B 3.6.4.3 . . ' ' B CONTAINMENT SYSTEMS* B 3.6.4.3 Standby Gas.Treatment (SGT) System BASES BACKGROUND -. : ., -. *.* "PBAPS UNIT. 3 . The. SGT System is required by'UFSAR design criteria (Ref. l}. The function of the SGT Sys.tern is to ensure that . rad.foact i ve materials that leak from the primary containment into the secondary containment following a Design Basis Accident (OBA) are filtered and adsorbed. prior to exhausting to the environment . . A single SGT System is common to.both Unit 2 and Unit 3 and consists of two fully redundant subsystems, each with its own set of ductwork, dampers, valves, charcoal filter train, and controls. Both SGT subsystems share. a common inlet *plenum. This inlet plenum is connected to the refueling floor ventilation exhaust duct for each Unit and to the suppression chamber and drywell of each Unit. Both SGT subsystems exhaust to the plant offgas stack through a common exhaust duct served by three 100% capacity system fans.. SGT System fans OAV020 and OBV020 automatically start on .Unit 2 secondary containment isolation signals. SGT . System fans OCV020 and OBV020 automatically start on Unit 3 secondary 'containment isolation signals.
• Each*charcoal filter train consists of (components listed in. order of the directfon of the air flow): * . ' a. A demister or moisture separator; b. .An electric heater;* c. . A prefilter; d. A high efficiency particulate air (HEPA) filter; e .. A.charcoal adsorber; and f. A.second HEPA*filter. The SGT System is sized such that each 100% capacity fan will provide a fl ow* rate of 10, 500 cfm at 20 inches water . gauge static pressure to support the control of fission product rel eas.es. . The SGT System is designed to restore and maintain secondary containment at a negative pressure of
• 0. 25 i.nches water gauge relative to the atmosphere following (continued).* B 3.6-85. Revision 0 i' BASES BACKGROUND (continued) APPLICABLE SGT System B 3.6.4.3 the receipt of a secondary containment is.al at ion signal. Maintaining this negative pressure is based upon the existence of calm wind conditions (up to 5 mph), a maximum SGT System flow rate of 10,500 cfm, outside air temperature of 95°F and a temperature of 150°F for air entering the SGT System from inside secondary containment. The demister is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the airstream to less than. 70% (Ref. 2). The prefilter removes large particulate matter, while the HEPA filter removes fine particulate matter and protects the charcoal from fouling. The charcoal adsorber removes gaseous elemental iodine and organic iodides, and the final HEPA filter collects any carbon fines exhausted from the charcoal adsorber.
• The SGT System automatically starts and operates in response to actuation signals indicative of conditions or an accident that require operation of the system. Following initiation, two charcoal filter train fans (OCV020 and OBV020) start. Upon verification that both subsystems are operatiiig; the redundant subsystem is normally shut down . . SAFETY .ANALYSES . . The (:lesign basis for the SGT System is to mitigate the . consequence$ of a 1 ass of cool ant accident and fue 1 handling accidents (Ref. 2) .. For all events analyzed, the SGT System .* is shown to be .... automatically initiated.to reduce, via and adsorptionrthe released ':' LCD . . _.,* .. :* . . . . PBAPS tb the ** *
• The SGT System satisfies. Criterton 3 *of the NRC Pol icy * . statement. . *. * **
• Fol1ow1ng*a D6A, *a 'minimum of one SGT subsystem is required *_to maintain the secondary containment at a negative pressure -with .r.especf tp-the, environment and.to process* gaseous *. -*** : rel eases: .. Meeting the for two OPERABLE* .. subsystems ensures* opera ti on* of at 1 east one SGT subsystem. in a single-active failure. > c '* (continued) .. _,., *, . >:::, R Revi slon No .. 0 * .z:.

BASES LCO (continued) APPLICABILITY ACTIONS :'.*. PBAPS UN IT 3 .* SGT System B 3.6.4.3 For Unit 3, one SGT subsystem is OPERABLE when one charcoal filter train, one fan (0CV020) and associated ductwork, dampers, valves, and controls are OPERABLE. The second SGT subsystem is OPERABLE when the other charcoal filter train, one fan (0BV020) and associated ductwork, damper, valves, and controls are OPERABLE. In MODES 1, 2, and 3, a OBA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, SGT System OPERABILITY is required during these MODES. In MODES 4 and 5, the probability and of these events are due to the pressure and temperature

• limitations in these Therefore, maintaining the SGT System in OPERABLE is not required in MODE 4 or 5, except.for other situations under which significant releases of radioactive material can be such as during crperatiDns with a potential for draining the reactor vessel dr during of RECENTLY IRRADIATED FUEL assemblies in the secondary containment. The SGT System is only requifed to be OPERABLE during OPRDVs or handling of RECENTLY IRRADIATED FUEL. With one subsystem the inoperable subsystem must be restored to in 7 days.. In Condition, the SGT subsjstem is adequate to perform the required radioactivitj release control functi_on. However, .the* overall system reliability is reduced because a single failure in the OPERABL'E subsystem could re::;ult' in the release control function not being ad.equateiy performed. The 7 day_ Completion_ Time is *based on *COnsideratio.ri Of SUCh factors as the .av.ailab.Hity .of the OPERABLE ret:tundant SGT subsystem and the low pr:oJ)api l ity. cit a OBA bcct.irri ng dur_i ng th.is period. If *the *SGT subsystem be restored to OPERABLE status witnin .. the required Completion Time in MODE L 2, or 3, the *.pl ant: must be brpught' to. a MODE* i I') which .the* overall pl anf .ri.sk is minimized ..
• To achieve this s*tatus, the plant must*be bro_ught*to at least MODE *J wHhin 12 hours. >Remaining inthe cont1 rwed. ' B' 3.6-87 *. Revision No.: 76

',. -* .. _._'.:'.-*** *.*(.'* -*** *--;-BASES ACTIONS '** ... *, . SGT System. B 3.6.4.3. B.1 (continued)* Applicability of the. LCO is accept.able because the plant risk in MODE 3 .*is si mi 1 ar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MOOE 3 to perform the necessary repairs to restore .. the system to OPERABLE stat us *

• wi 11 be short. However, . voluntary entry-into MODE 4 may be made as it is also an acceptable low-risk state .. The allowed Completion Time -is reasonabie, on operating experience, to reach the requifed pl ant conditi ans from full power * * .. conditions in ah orderly*manner and challenging plant systems, * *
• C.1 .. and . ------.--.---.. . . . . . .* . --* . . : Dur:i ng of RECENTL'( IRRADIATED FUEL as:sembl i es,
• i i1 the secondari containment or during OPDRVs, when Required ActioriA:1;cannot within the required Time, the OPERABLE SGTsubsystem should immediately be placed in operation; This action *ensures that* the.remafni ng subsystem :is OPERABLE'; that no .fa; 1 ures 'that could prevent . . ... automatic -actuation tiave occurred, and that .any .*other faifore. * ... would: detected> * * . * * * . * * * * . * ** *,' > * * * * * ** *--An. teitiat:J\,e. td 8equi.reci Acfio'n :(: .1 is to .*iminedi ately . *suspend that:fepreseht a potential.for* releasing*. f:adi oac.ti:ve tct the. thus' . >* ..... ,* .:.: .:' * .. ' placil"\g'the.plarit in a: c0.ndit*ion thcit niir\iiliizes risk. 'If . *applicable\ movement of .. RECENTLY IRRADiATEb FUEL assemblies:* * .. * .must i'mmetftateJy. * . . . . /.-._' -.. ;-_-. -.:* . .-**;; .. _, .. , :-.** . : ude :*cornp tet i oh of .. mo\iernefrt 6'( a cornpo.nent : to a acfidns:mu.st . '*.* :. ;. *-;imn:iedfateJy:be.inftiated J:cf. suspend bPbRVs,i.n o,rder :to' *minimize :the prC>.6abi:i'1.ty'. of:a:'.\iess*e i
• df7aindown :and .. ** *. . .. *** * , .
• for .f.issfon product. rel.ease. :Actions .* ... mus.t *continue until *.OF?DRVs* *are suspended.. . . '--* ... :. "":.: . .*. -*, .. '.** . *. . .:. *,' . ' .,.. *., ... _:-.* .o'.f";condj ti oh. c: mbcfi .f i ed ** t>Y a. ;3.0:*3*js hot appl5cab:le;:*;since . . niovemeJ1t)df. RECENTLY lRRADIAJED:: FU.EL cah only be perf ormeo in : . ..:. .. 4: *anc{ 5-_-.-.. .;*:;: -'. -* * * * ** * --'.. . . . . . ; : : :: .. : .*: ;_;_::, 0 *-** '* * * ( ** ** ',_'(. ..> ' ;.' \,;*.'. '* ., . *,;.,, < *****. } .. ' ., . . . .. ** *:. * * (tonfi nued L .;.* ***.-*-*.-..... ... PBAPs' urJr:i:: 3 . **:* .. "' si on No. * . -;r. '* . ......... c*v . ::.. ,.-' . .-.:-. .,.,_ .. .: .. **.* .*. ": :*:." ,'"*. '"

BASES SGT 'system B 3.6.4.3 . ACTIONS .Q_.J_ (continued) SURVEILLANCE REQUIREMENTS . *, .. * -. .... ' -PBAPS -UN IT-3. If both SGT subsystems are inoperable in MOOE 1, 2, or 3, the SGT System may not be capable of supporting the required radioactivity *release control function. Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at MODE 3 within 12 hours. Remaining in the Applicability of the LCD is acceptable because the plant risk in MODE 3 is sim1lar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore* the system to OPERABLE status will be short. However, entry into MODE 4 may be made as it is also an low-risk state. The allowed Completion Time is reasonable; based on operating experience, to. reach the required plant c6nd1tions from full power conditions in an orderly manner and without challenging plant systems. E.l* and E.2 When two SGT subsystems are inoperable, if applicable, movement of RECENTLY IRRAO.IATED FUEL assemblies in secondary must immediately be suspended. Suspension of this shall not completion of movement of a component to a safe*position. Also, if applicable, actions must immediately be initiated to suspend OPDRVs in order to minimize the probability *Of a vessel draindown and sub.sequent potentiaJ for fission product Actions must continue until 0 PD RVs a re s us pended . * . Required Action E.l has been modified by a Note stating that 3.0,3 is not applitable, since-the movement of IRRADIATED FUEL can only be performed in MODES 4 and 5. ' . SR 3.6.A.3'1 ** .. -. . . Operating>each. SGT subsys.tem .(including each filter train fan) for* :2'.'.J5>mtnutes ensures tha.t both subsystems *are OPERABLE' and tha't a1r*as.sbci'ated controls are funct1 oni rig, properly. It also ensubes:that fan oi failure, or* excessive. vibratioh can be dHected for correctiv.e actiort. 6perati'on.with the heater's on.(autorilatic heater cycling to maintain temperature) . for *15 mi riutes peri odl'cally i s .. suffi c.i ent to .eliminate moisture on t.he adsorbers *arid HEPA filters si nee d.uri ng idle periods . *Jnsfr.ufnent afr is 1 nJecte.dj nto the filter plenum to keep 'the ... filters: 'The Surveil la nee Frequency is .. controlled under the 1 ** ** Survei ila.nce Frequency Confrol' Program. . -.. -continued

• B '3;6c89
• Revisfon No. 87

' . BASES SU RV EI LLANCE REQUIREMENTS (continued) REFERENCES '.',*,. UN IT 3 SR 3.6.4.3.2 SGT System B 3.6.4.3 *This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program CVFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow .rate, and the physical properties of the activated charcoal use and following specific operations). Specific test frequencies and additional information are in detail in the VFTP. SR 3.6.4.3.3 This SR verifies that each SGT subsystem starts on receipt of an actual or simulated initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary. Containment Isolation Instrumentation," this SR to complete testing of the function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .. 1. UFSAR, Section 1.5.1.6. 2 . *. . U FSA R , Se ct. i on 14 . 9 . 3. Revision 2; Technical Justification to Support Risk-Informed to Selected Required End States for-BWR Plahts, December 2002. *::' : .* *,".'*.

.... HPSW Sy.stem B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 High Pressure Service Water (HPSW) System BASES BACKGROUND PBAPS UN n--3 The HPSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shutdown following a Design Basis Accident (OBA) or transient. The HPSW System is operated whenever the RHR heat exchangers are required to operate in the shutdown cooling mode or in the suppression pool cool1ng or spray mode of the RHR System. The HPSW System consists of two independent and redundant subsystems. Each subsystem is made up of a header, two 4500 gpm pumps, a suction source, valves, piping and associated instrumentation. Either of the two subsystems is capable of providing the required cooling capacity with one pump operating to maintain safe shutdown conditions. The t0o subsystems are separated from each other by a normally closed motor operated cross tie so that failure of one subsystem will. not affect the OPERABILITY of the other subsystem. The normally closed cross tie valve is supplied with redundant safety related power supplies to _ensure that _ a single failure will not prevent it from being opened wheh -* re qui red du r i n g a des i g n: bas j s event . A l i n e connect i n g the H P SW Sy s t em o f e a c h u n it i s a l s o p r o v i d e.d . Sep a r a t i _o n of the two units HPSW is by a series of two locked closed, manually o-perated valves. The HPSW System is designed with suffi-cient redundancy so that no single active component failure can it from achieving its functi6n. The HesW is in .the UFSAR, Sect i_on 10. 7, _Reference i -; *_Normal c6oiing watar is by the kPSW pumps froITT the *

• Conowingo Pond through the tube side of the RHR heat . ex c h a* n g e r s , a n d d i_ s c h a r g e s. -fo t h e d i s c h a r g e po rJ d . Th e re q level for the HPSW pumps in the pump bay of pump structure 98. s: ft* Conowi ngo Datum* (CD) and :::;*113 ft CD. The minimum level ensures net positive suction head and the maximum level corresponds to the level in the p ump b a y
• w i t h w a t e r s o l i d u p t o t h e mot o r b a s e p l a t e . -An _-_ alternate supply and discharge path (from-the emergency sink) i:s available in the unlikely event the Conowingo dam. the pond floods. This lineup, has to be manually aligned.*
• continued* -B 3. 7 Revision No. 119 BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES PBAPS U.N IT 3
• HPSW System B 3.7.1 The system is initiated manually from the control room. If operating during a loss of coolant accident (LOCA), the system is automatically tripped to allow the diesel generators to automatically power only that equipment to reflood the core. The system (using a single HPSW pump) is assumed in the analysis to be manually started 10 minutes after the LOCA. At one hour after the LOCA, a second HPSW pump is assumed to be started, with the HPSW cross tie line placed in service if required to provide cooling water to two RHR heat exchangers. The RHR System design permits the system to be initiated as early as 5 minutes after LPCI initiation. The HPSW System removes heat from the suppression pool to limit the suppression pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment can perform its function of limiting the release of radioactive materials to the environment following a LOCA. The ability of the HPSW System to support long cooling of the reactor or primary containment is discussed in References 2 and 3. These analyses explicitly assume that the HPSW System will provide adequate cooling support to the equipment required for safe shutdown. These include the evaluation of the long term primary containment response after a design basis LOCA. The safety analyses for long term cooling were performed for various combinations of RHR System failures. The worst case single failure that would affect the performance of the HPSW System is any failure that would disable one HPSW subsystem. As discussed in the UFSAR, Section 14.6.3 (Ref. 4) for these analyses, manual initiation -0f the OPERABLE HPSW subsystem and the associated RHR System is assumed to occur 10 minutes after a DBA. Manual alignment of the HPSW cross tie is assumed at 1 hour after a DBA, with a failure of a single diesel generator, to ensure that two HPSW pumps are available to provide the required cooling flow to two RHR heat exchangers within. a containment cooling/spray subsystem. Opening of the cross tie motor operated valve removes separation between the two HPSW subsystems; however, -because the cross tie valve is opened only after a single diesel generator failure has occurred, an additional failure *does not need to be considered, and independence of the two
• HPSW subsystems is not required following the DBA with a . single diesel generator failure. continued B 3.7-2 Revision No. 119

' .. .. :"' ' BASES APPLICABLE SAFETY ANALYSES (continued) LCO HPSW System B 3.7.1 The HPSW flow assumed in the analyses is 4500 gpm per pump with two pumps operating providing flow through the two required RHR heat exchangers. In this case, the maximum chamber water temperature and pressure are less than or equal to 188°F and 43 psig, respectively, well below the design temperature of 281°F and maximum allowable pressure of 56 psig. The HPSW.System satisfies Criterion 3 of the NRC Policy* Statement. Two HPSW and HPSW cross tie line (which allows two HPSW subsystems within the same unit to be connected) are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post accident heat loads, assuming the worst case single active failure occurs coincident with the 'loss of offsite power. A HPSW subsystem is considered OPERABLE when: . ' ' a. Two pumps a re ciP E_RAB LE; a n*d b. An OPERABLE flow path is capa'ble of taking suction from the pump and the water to* ttie requ*i red RHR heat exchanger at'. the assumed fl ow .Additionaliy, the HPSW cross_ tie Jalve Cwhith a:i Tows ,the two HPSW. subsystems to be connected) rnust so of one will not affect the OP ERAB IU TY of the other *subsystems. The:*HPSW.cross:tie is OPERABLE wheri: .. * . ,. . a: The HPSW tross "tie is OPERAB:LE; and . PBAPS UNIT 3

• b. . .. _An *OPERABLE.fl ow path is-capable o*f cross corinecti ng or .., i scil ati ng the two HPSW _subsystems.:. * * .. * .. : Ari'. adequafe SL.i'chori source is (lo( addressed i.n this LCO since the_ min1rnum .net positive suttion head (98:5 ft Conowingo*oatum (CO)*in_the pump bay).and.normal heat sink *temperature requirements are bounded by the emergency sefvite w"ater pump and ,notmal sink requirements
• crco .. *3, 7.:z, *"Emergency ServH:e Water CESW) Sy.stem and Nor'ma1 * *Heat Sink"'):* * * * * * -;: ' **--_..*-( c;onti m;ed) .. *:.-'** *' *B 3.7-3 Revision No. 119 ;: -

HPSW System B 3.7.1 BASES (continued) APPLICABILITY ACTIONS * . : ' *. PBAPS UN LT 3 In MODES 1, 2, and 3, the HPSW System is required to be OPERABLE to support the OPERABILITY of the RHR System for primary containment cooling (LCD 3.6.2.3, "Residual Heat Removal CRHR) Suppression Pool Cooling," and LCD 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool Spray") and decay heat removal CLCO 3.4.7, "Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown"). The Applicability is therefore consistent with the requirements of these systems. In MODES 4 and 5, the OPERABILITY requirements of the HPSW System are determined.by the systems it supports, and therefbre1 the requirements are not the same for all facets of operation in MODES 4 and 5. Thus, the LCOs of the RHR shutdown cooling system, which requires portions of the System to be OPERABLt, wfll govern HPSW System operation in MODES *4 and 5. . With,cine HPSW subsystem inoperable, the inoperable HPSW subsystem must be restored tn OPERABLE status within 7 days. With the unit in this condition, the remaining OPERABLE HPSW is adequate to perform the removal . function. However, the_ overall reliabillty is reduced because a single fai.lure in the OPERABLE HP.SW subsystem could result _in loss of H°PSW function. The: Completion Time is on the redundant capabilities afforded by the OPtRA&LE subsystem and the low of an event o c c u r r i n g r.e q u i r i n g H P SW d u r i n g t h i s p e r i o d . Action is by a Note fndicatirig that the applkable Co.nditi*ons::qf LCD 3.4.7, be*en.tered and

• Required :Actio'ns*'laken if :an.inoperable* HPSW subsystem. re.sul ts **in. an inoperable* RHR shutdown co"ol i ng subsystem. This is .an* exception "to LCO 3.0.6" and ensu:res the proper-** .actions a:re taken fo.r these'C:cimponents. * . 'With an _inoperable cross ti.e line, the HPSW cross tie \irie must . be. restwed .to an OPERABLE *status w.i thin 7 Q'ays.
• With. an ._ . *inoperabJe**Hpsw cross tcie '1foe, H no additional*failures occur,' and two HPSW *subsystems a re OPERABLE, then the two OPERABLE . pumps and flow paths pumps are ** .. :', (cont inUed) B* 3. i-4 .. Revi s*i on No. 119

. BASES ACTIONS PBAPS UN IT 3 B.l (continued) HPSW System B 3.7;1 provide adequate heat removal capacity following a design basis accident. However, the overall reliability is reduced because a single failure in the HPSW System could result in a loss of System function. Therefore, continued operation is permitted only for a limited time. The Completion* Time is based on remaining .heat removal and the low probability of a OBA occurring during this period. If one HPSW subsystem or the HPSW cross tie is inoperable and nbt restored within the provided Complet{on Time, the plant must brought to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within.12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or l-0wer than the risk MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable., based on operating experience, to reach the required plant conditions from.full power conditions in an orderly manner *and without challenging plant systems. With both HPSW subsystems inoperable, System i*s not capable of performing its intended At least ohe subsystem must be .res to red to 0 P ERAB LE *stat us within 8 hours. The 8 hour Completion Time for restoring one HPSW to status, is based on the Completion Times provided for the RHR pool cooling and spray functions.

• The Required Action is modified by a Note indicating that applicable Cbnditions of LCO 3.4.7, be entered and Required Actions taken if inoperable HPSW subsystem in an inoperable RHR shutdown cooling subsystem. This is exception to LCD 3.0.6 and ensures the proper actions are for these components. continued Revision No. 119 i I '** ... BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS . ; ,. PBAPS UNIT 3 HPSW System . B 3. 7. 1 E.l and E.2 If the HPSW subsystems cannot be restored to OPERABLE status within associated Completion Time of Condition D, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. SR 3.7.1.1 Verifying the correct alignment for each manual and power operated valve in each HPSW subsystem flow path provides assurance that the proper flow paths will exist for HPSW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be realigned to its accident position. This is acceptable* because the HPSW is a manually initiated system. This SR does not require any testing or valve manipulation; rather, it involves veri.fication that those valves capable.* of being mispositioned are in the correct position. This* SR not apply to valves that cannot* be misaligned, such as check valves.
• The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. . . Verification of manual transfer between the normal and alte.rnate power source (4kV emergency bus) for the HPSW cross-tie each RHR exchanger*HPSW outlet valVe demtinstratei that AC will be available tci operate the valVes following loss of power to any single 4kV emergency bus .. ' The ability to provide to the HPSW cross-tie valve and. each RHR heat exchanger HPSW outlet valve from either of two independent 4kV emergency a single failure of DG not failure of,a required HPSW syitem flow . p'ath; therefore,-failure of the manual transfer capability will .
• result: i ri in.operability of t.he *associ.ated HPSW subsystem.> The
• Surveillance Frequency is conttolled under* the,SurVeillance Frequency Control Program. , . .. (continued) . . B 3.7-5a Revision. No'. 119 .. 1 BASES (continued) REFERENCES -.. .' PBAPS UNIT 3 ** 1. UFSAR, Section 10.7. 2 . UF SAR, Ch apter 14 . . HPSW System B 3.7.1 3. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0. 4. Section 14.6.3. 5. Revision 2, Technical Justification to Support Risk.Informed Modification to Selected Required End States for BWR Plants, December 2002. B
• Revf sion No. 119
• I ESW System and Normal Heat Sink B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 Emergency Service Water (ESW) System and Normal Heat Sink BASES BACKGROUND The ESW System is a standby system which is shared between Units 2 and 3. It is designed to provide cooling water for the removal of heat from equipment, such as the diesel generators {DGs) and room coolers for Emergency Core Cooling System equipment, required for a safe reactor shutdown following a Design Basis Accident (OBA) or transient. Upon receipt of a loss of offsite power signal, or whenever any diesel generator is in operation, the ESW System wil 1 provide cooling water to its required loads.
• The ESW System consists of two redundant subsystems. Each of the two ESW subsystems consist of a 100% capacity 8000 gpm pump, a suction source, valves, piping and associated instrumentation. Either of the two subsystems is providing the required cooling capacity to support the required systems for both.units. Each subsystem provides coolant in s'epar*ate piping to common headers; one* each for the DG coolers, Unit 2 safeguard equipment coolers, and Unit 3 safeguard equipment coolers. The design is such
• that. any single* active fa i 1 ure wi 11 not affect the ESW System_ from providing coolanttQ the required loads. Cooling-water is pumped. from the normal heat sink. (Conowingo Pond) v*i a the pump structure bay by t.he ESW pumps to the essenttal components .. After removing heat from the components-, the water i,s discharged to_ the discharge pond, or the emergency cooling tower .in. certain . test a 1 i gnments. An**alter;nate suction supply and path {from the
• emergency heat sink) i.s<available in the unlikely event the Conowfngo : dam:-fa i 1 s or :the pond floods. This l i*neup, however,*. has to be man ti ally * *, -:, :-APPLICABLE*_ .. -Suffic*i,ent .. inventory 1s all *Esw System SAFETY ANALYSES
• post LOCA' -cooling* reqlii r.ements for a 30 day period with no* --, -additional makeup water source available .. The ability of ... the. Esw* =system to support *1 ong term coo 1 i ng_ of the reactor : ,--**_ ... PBAPS UNIT 3
• containment is as-sumed in evaluations of the equipment
• rJ!qutred" for safe reactQt presented* in the UFSAR, -.Chapter:14 {Ref.-I). These-analyses Jriclude the evaluation* -**--*of** the* res*P!J.nse :_after basis. --* , .. . *:: }"" '(continued). B .3.7-6 No. 4 *' -

1: I --. , .. _.-BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS LINT( 3 ESW System and Normal Heat Sink B 3.7.2 The ability of the ESW System to provide adequate cooling to the identified safety equipment is an implicit assumption for the safety analyses evaluated in Reference 1. The ability to provide onsite emergency AC power is dependent on the ability of the ESW System to cool the DGs. The long term cooling capability of the RHR and core spray pumps is also dependent on the cooling provided by the ESW System. ESW provides cooling to the HPCI and RCIC room coolers; however, cooling function is not required to support HPCI or RtIC System operability. The ESW System, together with the Normal Heat Sink, satisfy Criterion j of the NRC Policy Statement. The ESW subsystems are independent to the degree that each .ESW pump has separate controls, power supplies, and the of cine does not depend on the other. *In the event of a DBA, one subsystem of ESW is required to provide the minimum he-at removal capability-assumed in the safety analysis for the system to which it supplies cooling water. To. ensure met, tw6 _of ESW must be OPERABLE. At i*east one subsystem will operate, if ihe w6rst single .occurs with the -loss of offsite power . . , . . A subsystem is considered-OPERABLE when it has an OPERABLE normal heat sink, one OPERABLE pump, and ari OPERABLE flow path Capabl-e o-f takJrig -suction from the pu-mp structure and transferring the water to the appropriate equipment. . . . -' . . . The OPERABILITY of the-n6-rmal heat sink -is based on having a mini mum and maximum \evel _in the __ pump bay _Of 98. 5 ft Conowingci Datum and _l-1"3 ft CD respectively and a -maximum bf 92°F. -. -The: i of the ESW .System to components* or systems may render those systenis i noperab l but -doe_s not affect: :the-OPERABILfTY of the_ ESW System: . . . _ rn MODES L, and 3_, the TSW System and. he-at sink are re-quired to tie-OPERABLE. to. sup.port OPERABILITY of-the __ serviced by th'e ESW System. Therefore, the . --_-ESW S_ystem-and norma-1 heat sink are required to be 0-PERABLE in these* -MODES.' -, -._ .. :" cohtihued . . ,-: .-.* . B 3.7:-7 . Revision No. 109 * -*, -*. . ' . BASES APPLICABILITY (continued) ACTIONS SURVEILLANCE REQUIREMENTS PBAis UN IT 3 . .. ,**.** ESW System and Normal Heat Sink B 3.7.2 In MODES 4 and 5, the OPERABILITY reqµirements of the ESW System and normal heat sink are determined by the systems they support, and therefore the requirements are not the same for all facets of operation in MODES 4 and 5. Thus, the LCOs the systems supported by the ESW System and normal. heat sink will ESW System and normal heat sink OPERABILITY requirements in MODES 4 and 5. With one ESW subsystem inoperable, the ESW subsystem mDst be restored to OPERABLE status within 7 days. With the unit in this*condition, the remaining OPERABLE ESW subsystem is adequate to perform the heat removal function. However, the civerall reliability is reduced because a single failure in the OPERABLE ESW subsystem. could result in loss of ESW function. The 7 daY Completion Time is based on the redundant ESW System capabilities afforded by the OPERABLE subsystem, the low probability of an event occurring during this time period, and is consistent with the allowed Completion Time for restoring an inoperable DG. B.1 and If the ESW System cannot be restored to OPERABLE status within associated Completion Time, or both ESW subsystems are or the normal heat sirik is ihoperable, the unit must .be placed in a MODE in which the. LCO does not apply. To athieve this stitus, the unit must be in at least MODE 3 within 12 hours. and in MODt 4 within 36 hours .. The allowed Completion Times are reasonable, based on operating experience, to the* unit conditiDns from power conditions in an orderly manner and without challenging unit SR 3.7.2.1 This SR verifies the water level in the pump bay of the pump be sufficient for the proper operation of the ESW (the pump's ability to meet the minimum flow rate and.anticipatory actions required for flood conditions are considered in determining these limits). The Surveillance Frequenfy is under * * (continued) ., B 3.7-8 *Rev.ision No. *109 * .*,-. f' ;. ,,** BASES SURVEILLANCE REQUIREMENTS (continued) * ... .;*.* PBAPS UN.IT 3; SR 3.7.2.2 ESW System and Normal Heat Sink B 3.7.2 Verification of the normal heat sink temperature ensures that the* heat removal capability of the and HPSW systems is within OBA analysis. The water temperature is determined by using instrumentation that averages multiple inputs that measure the normal heat sink temperature. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Additionally, to ensure that the 92°F normal heat sink temperature is not exceeded, this surveillance requires hourly monitoring of the normal heat sink when the temperature is greater .than 90°F. The once .per hour monitoring takes into consideration normal heat sink temperature variations and the increased monitoring frequency needed to ensure design basis assumptions and equipment limitations are not exceeded in this condition. *SR 3.7.2.3 Verifying the correct alignment for each and power operated valve in each ESW subsystem flow path provides assurance that the proper flow paths will exist for ESW operation. This SR does not apply to valves that are locked, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet . *.considered in the correct position,*provided it .can be automatically realigned to its accident within the required time. This SR does not retjuire any testing or . valve manipulation; father, it ierification those valves capable of being mis.positioned are in the*. 'correct positi6n. This SR does not apply to valves that

• cantiot be in.adverte11tly misaligned, such as. check valves. This SR is.m6d1ffed by a Note indicating cif the ESW to or may render those components or systems inoperable' but does not affect the *..*. OPERABILITY of the ESW. System. As such, when all ESW pumps; and piping are OPERABLE, but a branch connection off the main header -is i_solated, the ESW System is still OPERABLE.* The. Frequency is contfolled under .the SurVeillance-Frequericy .Control Program. continued* B 3:7-9 Revision 109 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES PBAPS'UNIT.3 SR 3.7.2.4 ESW System and Normal Heat Sink B 3.7.2 This SR verifies that the tsw System pumps will automatically start to provide cooling water to the required safety related equipment during an accident event. This is demonstrated by the use of an actual or simulated initiation signal. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. l. UfSAR, Chapter 14. 2. NEDC-32988-A, Revision 2, Justification to Support Risk-Informed Modification to Selected Required* End States for BWR. Plants, 2002. . B 3. 1:0 Revision No. 87 I -._. ...... _ Emergency Heat Sink B 3.7.3 B 3.7 PLANT SYSTEMS B 3.7.3 Emergency Heat Sink BASES BACKGROUND .. _;. : . .-' **:-, . __ *:-* "*
• PBAPS UNIT 3 The function of the emergency heat sink is to provide heat rem6val capability so that the Unit 2 and 3 reactors can be* safely shutdown in the event of the unavailability of the normaJ heat sink (Conowingo Pond). The emergency heat sink supports the dissipation of sensible and decay heat so that the two reactors can be shutdown when the normal heat sink is unavailable due to flooding or failure of the Conowingo dam. This function is provided via the Emergency Service Water CESW) System and the High Pressure Service Water System ( HPSW). The emergency sink consists of an induced draft three cell cooling tower with an integral storage reservoir, three emergency cooling tower fans, two ESW booster pumps, valves, and associated.instrumentation. The emergency cooling tower, equipment, valves, and piping of the emergency heat sink.are designed in accordance with seismic Class t .. Standby power is provided to ensure*the emergency heat sink of operating during a loss. of
• offsite po0er.
• the heat sink.(Conowingo Pond) is lost.or when flooding .occurs, slui*ce.9ates in the pump structure housing the_ ES:W.:pumps an*d HPSW purnps *are .. Water is .the::n provj ded *: thr.ough two* gravity fed lines from the emergency heat sink reservoir into the pump structure pun:ip bays. The ESW ahd HPSW pumps pump cooling water to heat ex:Change,rs required Jo bring the ;U,,nit 2 3 reaCtors to safe .shutdown* coridi t'i ons Returri. water. from the HPSW.:System . flows 6irectly to bf the three cells. of emergency* tower. the tSW System through. one oLthe tw.o ESW booster pumps a*nd is pumped i'nto o'ne of. the e*me_rg,ency :i::ool.i ng towe.r eel J s used by the HPSW . . *.System. i .. Thi scorlfigi:lratioh *.al lows for closed Cycle
• Oi:foration *of the ESW. and. HPSW :sy:sfems. * * * * . Suffici eht capacity .'{3. 55 fni l lion ga U ons of water) *is available; when the minimum water level is 17 feet above .. the b'oftom of t:he emergency .. heat nk reservoir, "t.o support .. shutdown of Units. 2 .and 3'fqr 7 days W-ithout. -*-rTiake_up_ -:A.fter* 7 dayS*;-*m*ake*up *_wil*l **-be provide.d fr.0111 the .Susquehanna River or from* tank trucks. * * (continued). '-* -B 3;7-11 *Revision No. 68*: **-*.-. ,-.:** -. j Emergency Heat Sink B 3.7.3 BASES (continued) APPLICABLE SAFETY ANALYSES LCO : .. ' . . '.*,' '*) PBAP.S UN IT 3. The emergency heat sink is required to support removal of heat from the Unit 2 and 3 reactors, primary containments, and other safety related equipment by providing a seismic Class i heat sink for ESW and HPSW Systems for shutdown of the reactors when the* normal non-safety grade heat sink (Conowingo Pond) is unavailable. Sufficient water inventory is available to supply all the ESW and HPSW System cooling requirements of both units during shutdown with a concurrent loss of offsite power for a 7 day period with no additional makeup water The ability of the emergency heat sink to support the shutdown of both Units 2 and 3 in the event of the loss of the normal heat sink is presented in the UFSAR CRef. 1). The Emergency Heat Sink satisfies Criterion 3 of the NRC Policy In the event the normal sink is unavailable and offsite power is lost, the emergency heat sink is required to provide the minimum heat removal capability for the ESW and to safely shutdown both units. To ensure this requirement met, the emergency heat stnk must be OPERABLE; The emergency heat itnk is considered for.Unit 3 when it has an OPtRABLE flow path from the ESW System with one OPERABLE ESW booster pump, in OPERABLE:flow path from the Unit :3 HPSW Systeni, two of the three cooling tower cells and two of the three associated fans OPERABLE; one OPERABLE gravityfeed line from the emergency heat sink reservoir into structure bays with the tapability to the Unff 2 and 3 pump' structure bays, or one *OPERABLE gravity feed line from th.e emergency heat .sihk to the Unit* 3 pump structure bay w'ith ttif Un'it 2 and 3 pump structure bays . not"corinected, and. the capability exists to manually isolate** t_he. ESW .arid HPSW pump* _stru*cture bays from: t_he Conowi ngo: _**Pond.*. *v,alites in the required 'fl ow paths are considered .* OPERABlE.:1f.they* ca.n be manually aligned to their correct posi'tiori. The OPE.R.ABILiTY 'of the emergency beat sink al so a, minimum* water level :iri the hea*t sink. res'ervoir of .17 feet .. . ( conti-n'ued) . .*.r . ' . ' . . :: . .. -., ::-* Revision No. *92

. ,.**. BASES LCO (continued) APPLICABILITY ACTIONS PBAPS UN IT 3 * *--. Emergency Heat Sink B 3.7.3 Emergency heat sink water temperature is not addressed in this LCD since the maximum water temperature of the emergency cooling tower reservoir has been demonstrated, based on historical data, to be bounded by the normal heat sink requirements (LCD 3.7.2, "Emergency Service Water CESW) and Normal Heat .Sink"). In MODES 1,* 2, and 3, the emergency heat sink required to be OPERABLE to provide a seismic Class I source of water to the ESW and HPSW Systems when the normal heat sin.k is Unavailable. the emergency sink required to be OPERABLE in these MODES. In MODES 4 and 5, the OPERABILITY requirements of the emergency heat sink are determined by the systems it in the event the normal heat sink is unavailable. With required emergency cooling tower fan inoperable, action must be taken to restore the required eme0gency cooling tower to OPERABLE within 14 days. The 14 day Completion Time is based on the remaining heat removal capability, the fow probability of ah event occurring requiring the inoperable emergency cooing to0er fan to function, and the capability of the remaini.ng emergency cooling tower fan. With the emergency heat sink inoperable. for reasons other thah Condition A, 'the emergency heat sink must be restored to OPERABLE status within 7 days. With the unit in this condition, the normal heat CConowi ngo Pond) is adequate to perform the heat removal function; however, the *overall reliability is reduced: The 7 day Com0letion Time is based on the remaining heat removal capability and the low probability of an event occurring requiring the emergency heat sink to be OPERABLE during this time period. continued ' ' . . ' B RevisionNo. 1 >. ,I BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS REFERENCES C.l and C.2 Emergency Heat Sink B 3.7.3 If the emergency heat sink cannot be restored to OPERABLE within the associated Completion Time, the unit must. be placed in a MODE in which the LCD does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operatihg experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit SR 3.7.3.1 Thii SR ensures adequate long term (7 days) cooling can be maintained in the event of flooding or loss of the Conowingo Pond. With the emergency heat sink water source below the minimum level, the emergency heat sink must be declared. inoperable. The Surveillance Frequency is controlled under* *1 the Surveillance Frequency tontrol Program. SR 3.7.3.2 Operating each required emergency cooling tower fan for ;;:: 15 minutes ensures that all require.d fans are OPERABLE*and that all controls are functioning properly. It.* also ensures .that or motor failure; or vibration, can be detected: for correct i.ve *.*action.* The

• ts cohtrolled under the Frequency Control Program. 1.
• UFSAR, Section 10:24. . **> : . , , B 3.7-14 Revision No. 87

  .:* MCREV System B 3.7.4 B 3.7 PLANT SYSTEMS B 3.7.4 Main Control Room Emergency Ventilation CMCREV) System BASES BACKGROUND -PBAPS .UN IT 3 The MCREV System provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke. The MCREV System consists of two independent and redundant high efficiency air filtration subsystems and two 100% capacity emergency ventilation supply fans which supply and provide emergency treatment of outside supply air and a CRE boundary that limits the inleakage of unfiltered air. Each filtration subsystem consists of a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, a second HEPA filter, and the associated ductwork, valves or dampers, doors, barriers and instrumentation. Either emergency ventilation supply fan can operate in conjunction with either filtration subsystem. HEPA filters remove particulate matter, which may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay. A dry gas purge is provided to each MCREV subsystem during idle periods to prevent moisture accumulation in the filters. The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. This area encompasses the control room, and may encompass other areas to which other frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected during normal operation, natural events, and accidents conditions. The CRE boundary is the combination of walls, floor, roof, ducting, dampers, doors, penetrations and equipment that physically form the* CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the in leakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing bases analyses of design basis accident (OBA) consequences and chemical hazards t6 CRE occupants. Since the equipment required and the allowable inleakage is different for radiological and chemical events, _the CRE boundary distinguishes between the boundaries required for each event. The CRE and its boundaries are defined in the Control Room Envelop Habitability Program. continued B 3.7-15 Revision No .. 114

',;' . *'*-BASES BACKGROUND (continued) MCREV System B 3.7.4 The MCREV System is a standby system that is common to both Unit 2 and Unit 3. The two MCRfV subsystems must be OPERABLE if conditions requiring MCREV System OPERABILITY exist in either Unit 2 or Unit 3. Upon receipt of the initiation signal(s) (indicative of conditions that could result in radiation exposure to CRE occupants), the MCREV System automatically starts and pressurizes the CRE to minimize infiltration of contaminated air into the CRE. A system of dampers isolates the CRE along the radiological boundary, and outside air, taken in at the normal ventilation intake, is passed through one of charcoal adsorber. filter subsystems for removal of airborne radioactive particles .. During normal control room ventilation system restoration following operation of the MCREV system, the automatic initiatioh function of MCREV will briefly be satisfied by actions and controlled procedural steps. If all normal ventilation and air conditioning were lost, the contr61 room operator would initiate an emergency shutdown of equipment and lighting to reduce the heat generation to a Heat removal would be accomplished by conduction through the *floors, ceilings, and walls to . adj a cent rooms* (!nd to the envi.ronment. Additionally, the 'MCREV System is desighedto maintain a h.abitable environment in th*e CRE *for a 30 day c6nti nuous occupancy (\ft er a DBA without exceeding 5 rem total effective dose equivalent subsystem will pressurize the *CRE .. relative to* the external. adjacent* to the CRE boundary tri mihimtze infiltrat1on of air all:. surrounding adjacent to the CRE r9diological boundary, MCREV Syst{.em operation in main.taini'r1g CRE _habitability _is discL1ssed in the UFSAR, *Chapters 7; 10, and 12;° 1-, *2;. and 3; respectively)._ APPLICABLE .* :, Jhe-**abi'l it:Y .. of tbe MCREV ,System to maintain the habitabi 1 ity .* SAFETYANA.LYS.ES-a-f* is an explic.it a!)sumption.for:the*safety. analy.ses ** Jhe UFSAR, Chapters* 10 12 (Refs: 2 and.3,

• respective.ly),* TheMCREV System is as?'Llmedto operate* *following as discussed in the UFSAR,.Section 14.9 *.(Ref. 4). The radiqlo_gical doses to*the CRE occupants as a *result of*. the variousDBAs are summarized in Reference* 4. ** :*: . ".*, . . '.** :**' PBAPS .UNXT J sin.gl.e:'a'ctive or. pass i v.e electrical .:fai 1 wil 1 caus.e *'l'hE! Toss .. of. oUts1 de* or recfrtul'atecJ alr .from the CRE ... * * ,.**. B 3.7-16 ... .-.. .*'**. lied) .*: ' . Revi si-on* No. 114** J BASES APPLICABLE SAFETY ANALYSES .(continued) LCO MCREV System B 3.7.4 The MCREV System provides protection from smoke or hazardous chemicals to the CRE occupants. A periodit offsite chemical survey,-and procedures for controlling onsite chemicals, are essential elements of CRE protection against hazardous chemicals. The system design is based on low of offsite sources of toxic gas, based on a chemical survey of the surrounding areas. Those offsite sources of toxic gas with a greater than low probability are evaluated in accordance with Regulatory Guide 1.78 (Ref. 10) or Regulatory Guide 1.95 (Ref. 11) and tletermined to be acceptable for continued habitability. The offsite chemical survey is conducted perfodically to determine any change of condition that may.need to be addressed. The onsite chemicals are controlled procedurally such that they do not affect CRE habitabllity adversely.* the MCREV system does not have a toxic gas mode, evaluations have been performed to assess the impact of toxic gas *on i::ontrol room habitability. The evaluations hav*e that based on either the low probability of hazardous chemical events occurring or operator action to don Contained Breathing Apparatuses CSCBAs) and secure the control room additionai protection from offsite ts not required. Only or changes in quantities of chemicals identified as part of the chemical *-survey will be anal,yzed furthe,r for control room habi tabi;li ty purposes.*.
• The MCREV System satisfies: Crit:eri on 3 of the NRC Policy Statement. *
• twci the MCREV to be OPERABLE to enstire.*tha't at least one is available, if a sir:igle active fa1lure d1s:a*b',res the othe-r subsystem.* Total MCREV System failure, from a loss of both ventilation . sub.systems or frqm an inoperable CRE boundary, could result in a dose of 5'rem total effective dose equivalent (.JEDE) .to* the CRE qccupants 1n* .the .eVent of a OBA or fo,r toxic gas everlts,
• resu].t j n i :of the CRE ** . . .
• inh_abitants. * * * * .. * .. *'
• PBAP.s UNIT 3 .**. *. E_acti'MCREV subsystem is 'co,nsidered OPERABLE when the ind*ividual components *necessary to l imlt CRE o,cc;upaht radiatiorr exposure .. are A subsystem .is consideredDPERABLE. when: . _,. -.. .. a; ., ,.*-'* on*e fan. is. OPERABLE; .. *_* . . ( . .. _'*-'.-_. __ _ . _ .. ;-**, __ :*. -_;_. -.. . " -*.B 3.T"-16a No. 114 BASES LCO (continued) PBAPS* UN IT 3 b. MCREV System B 3. 7 .4 _ filter and charcoal -adsorbers not excessively restricting flow and are capable of performing their filtration and c. Ductwork, valves, and dampers are OPERABLE, and air flow can be maintained. A subsystem may be considered operable using either the A or B fan combined with either the A or B Filter bank. In order for the MCREV subsystem to be considered OPERABLE, the CRE radiological boundary must be maintained such that the CRE occupant dose from the large radioactive release does not exceed the calculated dose in the basis consequence analyses for DBAs. -In order for the MCREV subsystem to be considered OPERABLE, the CRE boundaries must be maintained OPERABLE, including the integrity of the walls, floors, ceilings, and ductwork. Temporary seals may be used to maintain the boundary. For hazardous chemical events, the CRE chemical boundary is OPERABLE when the CRE occupants can be protected from hazardous chemicals. The in leakage limit for hazardous chemicals is defined and established in the hazardous chemical analyses (Ref. 12 and 13). If measured inleakage is greater than the limit established in the analyses, or if a new.hazardous chemical (not meeting the screening criteria of Reference 10 or Reference 11) or increased quantity of an existing chemical is determined to exist, then the CRE chemical boundary is considered inoperable, unless continued habitability is evaluated as being acceptable (Ref. 10, 11). For smoke events, the*CRE boundary is OPERABLE the CRE
• occ.;upants -can be protected from smoke events external or internal ta the plant._ For smoke events, no limit* exists for the amount of smoke all owed i-n the CRE. -However, if .sm-oke enters the CRE such that mitigating actions are requiredi then the CRE boundary is considered-inoperable. The LCO is modified by a Note the CRE boundary to be opened intermittently under administrative controls. This Note only applies to in CRE boundary that can. be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. -For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls should be proceduralized and consist of stationing .a dedicated individual at the opening who is in continuous communication with. the operators in the CRE. This individual will have a method to-rapidly clbse the opening and to restore the CRE boundarf to a condition *equtvalent to the design condition when* a for CRE isolation is indicated. -(continued) . . Revision N_o. 123 BASES (continued) APPLICABILITY ACTIONS: . < -. '(.:'* PBAPS UNIT 3* MCREV System B 3.7.4 In MODES 1, 2, and 3, the MCREV System must be OPERABLE to ensure that the CRE will remain habitable during and following a OBA, since the OBA could lead to a fission product release. In MODES 4 and 5, the probability and consequences of a OBA are reduced because of the pressure and temperature limitations in these MODES. Therefore, maintaining the MCREV System OPERABLE is not required in MODE 4 or 5, except for the following situations under which significant radioactive releases can be postulated: a. During operations with potential for draining the reactor vessel COPDRVs); b: During CORE ALTERATIONS; and c. During movemerit of irradiated fuel assemblies in the secondary containment. With one subsystem inoperable, for reasons other than. inoperabl*e CRE bounaary, the inoperable. MCREV must be restored tp OPERABLE status within 7' days. With the unit in this conditfon; the remaining OPERABLE MCREV .. subsystem is adequate to maintain crintrol room and to perform the CRE protection *function.
• However, the overa 11 .. rel i abi 1 i ty is reduced because a failure in the could result in loss of the MCREV*System fuhctiori,* The 7 day Ccimpleti'on Time-is. 'based on the low.probability of a OBA this time. and that the can provide *
• B.L B.2 and B.3 If the unfiltered inleakage of potentially.contaminated air' a CRE boundary the CRE can result in CRE . I radiological dose greater than the calculated dose of the. licensing* basis analyses of DBA consequences Caliowed to up to 5 rem total, effective dose equivalent CTEDE)),, or inadequate protectioh of CRE from * . chemi ca 1 s or smoke that _have been 1 i censed to occur, the .C-RE b*oundary is inoperable: Actions must be taken to restore '.an 0 P ERA B LE C RE -b o u n d a r y w 1 t h i n -9 O d a y s . . *ccontinuecir ** B 3:7-17 Revision-Nci. Il4 -

BASES ACTIONS PBAPS -UNIT 3 B.l. B.2 and B.3 (continued) MCREV System B 3.7.4 During the period that the CRE boundary is considered inoperable, .action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke (Refs. 6, 7, 10 and 11). Action must be taken within 24 hours to verify that in the event of a DBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of DBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke as required. These mitigating actions Ci .e., actions that are taken to offset the consequences of the inoperable CRE *boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional. The 24-hour Completion Time is reasonable based on the low probability of a DBA occurring during this time period, and the initiation of mitigating actions. The 90 day Completion Time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective that may adversely affect their ability to control the and maintain it in a safe shutdown condition in the event of a OBA. In addition, the 90 day Completion Time is a reasonable time to diagnose, plan and repair, .and test most problems with the CRE boundary. In MODE l,* 2, or 3, if the inoperable MCREV subsystem or the CRE boundary cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes overall plant risk. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours. Remaining in the Applicabil1ty of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be ihort. However, voluntary entry into MODE 4 may be made as it js also an acceptable low-risk -_state. The allowed Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. continued _ B 3.7-18 Revision No. 114 _I -* BASES *ACTIONS (continued) :* .:* .. .-PBAPS UNI_'J;' 3 .. !?..:.h_!? .. : 2 . 1, !? .. : 2 . 2, and !?..:. 2 . 3 MCREV System B 3.7.4 The Required Actions of Condition D are modified by a Note indicating that LCO 3.0.3 does not apply. If moving 'irra<;!iated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated.fuel assemblies is not sufficient reason to require a reactor shutdown. During movement of irradiated fuel assemblies in the secondary containment,, during CORE ALTERATIONS, or during OPDRVs, if the inoperable MCREV subsystem cannot be restored to OPERABLE status within the required Completion Time, the OPERABLE MCREV subsystem may be placed in operation. This action ensures .that the remaining subsystem is OPERABLE, that no*failures thatwould prevent automatic actuation will occur, and that any active failure will be readily detected. An *alternative to Required Action D.1 is to immediately suspend activities that present a potential for releasing radioactivity that might require isolation of th.e CRE. This places the_ unit in a condition.that minimizes the accident risk. If applicable, CORE ALTERATIONS and movement of irradiated .fuel assemblies in the secondary co'ntainment must be suspended immediately. Suspension of these activities. shall not preclude completion of movement of a component to a safe pos.i:tion* .. Also, if applicable, actions must-.be initiated immediately to suspend OPDRVs to minimize the .probability of 'a vessel draindown and the subsequen_t potential for fission product release. 'Actions must continue until the OPDRVs are suspenc),ect:

• E:1-_*If*both MCREV in MODI;: 1, 2, or.3 for reasons other than-an inorierable CRg boundary (i.e;r C:.ondition B.) the>.MCREV System may not capable of
• pe*r-formin'g the .. intended function*-Therefore,: the plant.:must be_ br()light tC? *a* MODE in which_ the ove.r:ai.l :pla:t;,t risk is' To achieve -this status;.-the-plant must 'be brought. to at least MODE within 12
• Remaining {n: the
• Applicab:(.fity .*of' the LCO is acceptable the plant-risk in MODE 3 is similar to .or* lower than the risk in MODE 4 .(Ref. s*i _and .the time spent in -MODE 3. to perfo-rm the . _ necessary rep.airs to rest:Ore' t:he *system -to OPERABLE status ,will :be 'short. . However I vO'luntary' eh try into .MODE 4 may be-ma<;ie as' ' it is also_ a:ri acceptable low-:risk state. The allowed _ Compl,etion Tii:ne_ ii rea-sonable; base!=l* 'on operating experience, -to_ reach -the required plant conditions from full, power: ' in ari .orderly .manner and chaiienging plant systems .. < .* (continuedi-* B 3-; 7-19 Revision Nc:i:. 69 I I BASES -ACTIONS (continued) SURVEILLANCE REQUIREMENTS . *;_:;-' _PBAPS UNIT l: MCREV System B 3.7.4 F.1. F.2 and F.3 The Required Actions of Condition Fare modified by a Note indicating that LCO 3.0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not reason to require a reactor shutdown. During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, .with two MCREV subsystems inoperable or with one or more MCREV subsystems inoperable due to an inoperable CRE boundary, -action must be taken to suspend activi-ties that present a potential for releasing radioactivity that might require isolation of the CRE. This places the_Onit in a condition that minimizes the accident risk. If applicable, CORE ALTERATIONS and movement of irradiated fuel in the secondary containment must be immediately. Suspension of these activities shall not preclude completion of movement of a component to a safe position .. If applicable, _actions must be initiated imme.diately to suspend OPPRVs to minimize the probability of a vessel draindown and for fission product release. must continue until the OPDRVs are suspe:nded. SR 3.7.4.l-----This SR verifies that .a subsystem in a sta,ndby mode starts on and continues to operate for 15 minutes. Standby should_be checked periodically to ensure that and function properly. As tbe environmental* and nor*mal operating* c;ond.ition_s of thi*s system are not severe, testing _each .subsystem periodically provides an_ adequate . check bn this sy sl.em.
• The Su rveiJ l *an ce _ Frequency is controlled.under-the.Surveillance Frequency Control * ,_* .. ; . . . **.!.:-*** -SR 3. 7A.2 Thi.s *sit verifies* MCREV. 15 *
• performed in. atcor9ance with_ the Ventilation* Filter Testing Program (VFTP). The VFTP includes filter performance, cha rca,a.l adsorber efficiency, mini mum* system -,fl ow:rate, and the phys i ca i* properties *of the* activated _ cha rccial: (general . use and f 0-11 owing' specific ope rat lon$) . . *Specific.test frequencies-an'd additi'on_al information are -_discuss*ed *in detail-in the .VFTP. : '. (continued)--' >> _B .:3. 7-20. *Revision* No. 87 .-".-.-,_.'*.* .. _____ J

' i' i"-* ,. ,. BASES SU RV EI LLANCE REQU lREMENTS (continued) *--. ,.' '**' *sR 3.7.4.3 MCREV System B 3.7.4 This SR verifies that on an actual or simufated initiation signal, each MCREV subsystem starts and operates. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.4 this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.7.4.4 This SR verifies the OPERABILITY of the CRE boundary by testing for unfiltered air 'i nl eakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program. The CRE is considered habitable when the radiological dose to CRE occupants in the licensing basis analyses of OBA consequences is no more than 5 rem whole body dose or its equivalent to any part of the body and the CRE occupants are protected from hazardous and smoke.that have licensed to occur .. SR verifies that the unfiltered air inleakage into the CRE through the radiological and chemical boundaries is no greater than the flow rates assumed in the licensing basis of OBA consequences and control room habitability evaluations for hazardous-chemitals. When unfiltered air inleakage is greater than the assumed flow rate, Condition B must be Required B.3 allows to restore the CRE boundary to OPERABLE status provided mitigating actions can *ensure that the CRE remains. withiri the licensing basis habitability limits for the occupants following an accident. Mitigating actions. discussed in Guide 1.196, C.2.7.3, tRef. 6) which with exceptions, NEI 99..:03, Sectfon 8 A and Appendix F (Ref. 7). These also be used as mitigating actions as required by Required Action B.2. Temporary analytical methods may also be used as .compensatory measures to restore OPERABILJTY 9). Options for restoring the CRE . boundary to OPERABLE include changing the licensing basis OBA consequence or chemical habitability analyses, .I repairing the CRE or a combination of these Depending upon the nature of the problem and corrective act.ion, .a full scope inleakage test may not be necessary to estatilish that the CRE has been to . . ;;' (continueq) B 3., 7-20a . Revision No. 114 : BASES (contin0ed) REFERENCES -;*.* . -,. PBAPS UNIT 3* 1. UFSAR, Section 7.19. 2. UFSAR, Section 10.13. 3. UFSAR, Section 12.3.4. 4. UFSAR, Section 14.9. MCREV System B 3.7'.4 5. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002. 6. Regulatory Guide 1.196, "Control Room Habitability at Light-Water Nuclear Power Reactors", May 2003. 7. NEI 99-03, "Control Room Habitability Assessment", June 2001. 8. TSTF-448, Rev. 3, "Control Room Habitability" dated 8/8/06 and "Corrected Pages for TSTF-488, Rev. 3, Control Room Habitability", dated 12/29/06. 9. Letter from Eric J. Leeds (NRC) to James W. Davis (NEl) dated January 30, 2004, "NEI Draft White Paper, Use of Generic Letter. 91-18 process and Alternative Source Terms in ihe Context of Control Room Habitability." 10 .. NRC Regulatory Guide 1.78, Evaluating Habitability -of a Nuclear Power Plant Control Room during Postulated Hazardous Chemical Release, .Rev. 0. 11. NRC RegDlatory 1.95, Protection of Nuclear Power 'Pl ant Control .Room Op_erators Against an Accidental_-., Chlorine Release, Rev.-0; 12. Calculation PM*1085, "Peach Bottom Atomic Power Statton C_ontrol Room Habitability Analysis for th'e Off-sit.e

• Chemicals." I
• 13 .. Cal cul ati on PM: 1175, "Control Room Habitability for* Chemicals Stored Onsite." '. :. " . 1-* *. B Revision No. 1°23 -*

Main Condenser Offgas B 3.7.5 B 3.7 PLANT _SYSTEMS B 3.7.5 Main.Condenser Offgas BASES BACKGROUND unit operat1on, steam from low pressure turbine is exhausted directly into the condenser. Air and noncondensible gases are collected in the condenser, then exhausted through the steam jet air ejectors (SJAEs) to the .Main Condenser Offgas System. The offgas from the main condenser normally includes radioactive gases. The Main Coridenser Offgas System has been incorporated into the unit design to reduce the gaseous radwaste emission. This uses a catalytic recombiner to recombine radiolytically dissociated hydrogen and oxygen. The gaseous mixture is cooled and water vapor removed by the offgas recombiner condenser; the remaining water and condensibles are stripped out by the cooler condenser and moisture separator. The remaining gaseous mixture (i.e., the offgas recombiner effluent) is then-processed by a charcoal adsorber bed prior to release. _APPLICABLE The main condenser offgas gross gamma activity rate is an SAFETY ANALYSES initial condition of the Main Condenser Offgas System LCO PBAPS UNIT. 3

• event, discussed in the UFSAR, Section 9.4.5 (Ref. 1). The analysis assumes a gross in the Main Condenser Offgas System that results in the rupture of the Main Condenser Offgas System pressure boundary. The gross gamma activity rate is controlled to ensure that, during the event, the calculated 6ffsite doses will be well within the 1 imits of 10 CFR 100 (Ref. 2) or the NRC staff approved licensing basis.
• The main condenser offgas limits satisfy Criterion 2 of the NRC Policy Statement. To ensure compliance with* the assumptions of the Main Condenser Offgas System failure event (Ref. 1), the fission product release rate should be consistent with a noble gas -release to the reactor coolant of 100 µCi/MWt-second after decay of 30 minutes. The LCO is established consistent * (continued) B 3.7-22 Revision No. o

-, _; * -! BASES LCO (continued) APPLICABILITY ACTIONS ;*_, ,-. **. -_.. ' --.-' PBAPS UN IT. 3 Main Condenser Offgas B 3.7.5 with this requirement (3293 MWt x 100 µCi/MWt-second = 320,000, µCi/second) and is based on the original licensed rated thermal power. The LCO is applicable when steam is being exhausted to the main condenser and the resulting noncondensibles are being processed via the Main Condenser Offgas System. This occurs during MODE 1, and during MODES 2 and 3 with any main steam line not isolated and the SJAE in operation. In MODES 4 and 5, steam is not being exhausted to the main condenser and the requirements are not applicable. If the offgas radioactivity rate limit is exceeded, 72 hours is allowed to restore the gross gamma activity rate to within the limit. The 72 hour {ompletion Time is reasonable, based on engineering judgment, the time required to complete the Required Action, the large margins associated with permissible dose and exposure and the low probability of a Main Condenser Offgas System

• rupture. B.1. B.2. and I . B.3 --. . ' . . . -If" the gamma is not restored to wiihin the:limtts in the ass6ciated Completion,Ttme, all main lilies o*r the SJAE must be isolated.* This i.so,lates the Main Condenser Off gas System fr Om the *source of t'he rad.i oact i ve steam .. }he ,mafo Jines are considere'd isolated. if. at .least*one main steam isolation valve in each main steam line 1s closed; ar1d at ieast ohe .main steam line drain.*valve* in dfa)n line of steam isolation . ** The* 12 h_our<.completionTim'e is reasonable,* based.* .. cin ope*r.ating experience, to:. perform. the actions from full* power: conqitioris .in 'an orderly manne'r an*d without .. chal.iengingunit systems. -*.An *-l1 to Required. Actiohs B'.1 and B. 2 is to place *the unit-i.n a MODE in whic'h the overall plant risk is rrrini.rnized;.
• To ach.ieve this status, the unit must be placed *=in aflea:st MODE3within12 ho*urs .. *Rema.ining in the -*
• A.pplTcabi l,i ty of, *the is e because" the plant* riSk<1hMODE3 is similar'loor-lower ttian the riskfn:_**_ MOOE 3) .and because the time.spent in MO.OE *3 t_o .* .:* continued B .3. 7 -23: Revision No. 67 .-

BASES ACTIONS SURVEILLANCE REQUIREMENTS RE F E RE N C ES . *. . . . " -.. -,. .. *.*. Ji BA PS U NJ T 3

• B.1. B.2. and B.3 (continued) Main Condenser Offgas B 3.7.5 perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without unit systems .. SR 3.7.5.1 SR.requires an isotopic analysis of an offgas sample to ensure that the required limits are satisfied.* The noble to sampled are Xe-133, Xe-135, Xe-138, Kr-85m,* Kr-87, and Kr-8ff. If the measured rate of radioactivity i nc re a s e.s s i g n i f i c a n t l y ( by 5 O % a ft e r co r re ct i n g fo r exp*ected in.creases due to changes in THERMAL POWER), an isotopic analys{s is also performed within 4 hours after the is noted,. to ensure that the increase is not indicative of a sustaine& increase in the rate. The Surveillance Frequency is controlled under the Surve.il lance Frequency Control Program. . . Th"i s .. SR is modified *by a Note i ndi cati ng that the SR *is not requi.red to 31 days.after any main steam line is not isolated and the SJAE is in operation. Only in t h i s: co nd it i on c a n r a d i o a ct i v e
• f i s s i o n g a s e s b e i n t he Ma i n Condenser Off gas System at si gni fi cant rates.
• 1.. *ufSAR; Secti.on 9.4.5 . 2. .. 3 . . ***. . -* 10 CFR *-.'* 2, Techn1cal .Justification to *.supp_ort Rf sk-Inforrried. Modification -to: selected Required . *** Ey,d.-State_s for BWR Plants, December 2002 . *-*J. *-_: __ .. B
• 3. .. '7 -24
• Revisiun Nb. 87 Main Turbine Bypass System B 3.7.6 B 3.7 Plant SYSTEMS B j.7.6 Main Turbine Bypass System BASES BACKGROUND -_APPLi{ABLE SA°FETY ANALYSES PBAPS-UNIT 3--,*., " ,._.** The Main Turbine Bypass System is designed control steam pressure when reactor-steam generation exc2eds turbine requirements during unit startup, *sudden load reduction, and cooldown. *It allows excess steam flow from the*reactor to the condenser without going through the turbine. The bypass capacitj of the system is 22.4% of the Nuclear Steam Supply System rated steam flow. Sudden load reductions the capacity of the steam bypass can be accommodated without safety relief valves opening or a reactor scram. The Bypass System consists of nine modulating type hydraulically actuated bypass valves on a valve manifold. The manifold is *connected with two steam lines to the four main steam lines upstream of the turbine stop valves. The bypass valves are controlled by bypass control unit of the Pressure Regulator and Turbine Generator_ Control System, .discussed in the UFSAR, Section 7.11.3 (Ref. 1). The bypass valves a re norm a 11 y closed. However, if the total steam fiow signal exceeds the turbine control valve flow signal of the Pressure Regulator and Turbine Generator Control System, the bypass coritrol unit protesses these and wiil output a bypass flow signal to the bypass vaJ ves.
• The bypass valves wi 11 then open sequentially to bypass the excess flow connecting piping and. a pressure reducing orifice to the condenser. The Main.Turbine Bypass System is expected to function during the electrical load -rejection transie_nt, the turbine tr{p transient, and the feedwater controller failure maximum demand transient, described in the UFSAR, Section-14.5.1.1 (Ref. 2), Section 14.5.1.2.1 (Ref. 3), and Sectibn 14.5.2.2 (Ref. 4), _ Howevej, the feedwater controller maximum demand transient is the limiting licensing transient which defines the MCPR operating if the Main Turbine Bypass System is inoperable. Opening the bypass valves during the pressurization events mitigates the increase in reactor vessel pressure, which affects the MCPR during the event. The Main Turbine Bypass System satisfies Criterion 3 of the NRC PolicY Statemerit. (continued) . . . -B 3:7-25-Revision *Na: *_119 -* -., ..

(, -, . I' ...... !' Main Turbine Bypass System B 3 .7. 6 BASES (continued) LCO The Main Turbine Bypass System is required to be OPERABLE to limit peak pressure in_ the main steam lines and maintain reactor pressure within acceptable limits during events that caµse rapid pressurization, so that the Safety Limit MCPR is not exceeded. With the Main Turbine Bypass Svstem inoperable, modifications to the APLHGR limits --APPUCABI'LITY ACTIONS PBAPS UN IT 3 '-* .. ., CLCO 3.2.1, "AVERAGE PLANAR LINEAR RATE CAPLHGR).), the MCPR operating limits CLCO 3.2.2, "MINIMUM CRITICAL POWER RATIO CMCPR)"), and the LHGR operating limits (LCD 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)") may be applied to allow this LCD to be met. The operating limits for the inoperable Main Turbine Bypass System are specified in the COLR. An OPERABLE Main Turbine Bypass System requires the minimum number of bypass valves, specified in the COLR, to open in response to increasing main steam line pressure. This response is within the assumptions of the applicable analyses (Refs. 2, 3, and 4). The Main Turbine System is required to be OP[RABLE at 23% RTP to ensure that the fuel cladding integrity Safety I -Limit and the cladding 1% plastic strain limit are not _ violated during the applicable safety analyses transients*. As discussed in the Bases for LCD 3.2.3, "LINEAR HEAT G E N ERA T ION RA TE ( L H GR ) ' II a n d L c 0 3 . 2 . 2 ' s u ff i c i e n t ma r g i n t ci -these 1 imits exists at < 23% RTP. -Therefore, these requirements are only ne*cessary when operating at or above this power level._ --If the Main Turbine Bypass System is inopetable Cone or more -required bypass valves as specif.ied ih the COLR inoperable), or the required tharmal an inoperable Main Turbine System, as specified in the COLR, are .not-applied, the assumptions of the -design basis transi'ent may not tie met. __ Under such c1rc0mstances, prompt .. _ action *should be taken to restore the Main Turbine Bypass. ____ --system to OPERABLE -status_: or adjust the t_hermal operattng accordingly .. tiour Completion Time is reasonable; based on the-time to compl the Required Action and the low probability of an event occurring during this period requ_iring the Main Turbine *Bypass System. -continued B 3.T-26 Revision No. 119 -, :. ,.-,. BASES ACTIONS (continued) SU RV EI LLANC E REQUIREMENTS *. *' PBAPS UN IT 3. ** Main Turbine Bypass System B 3.7.6 If the Main Turbine Bypass System cannot be restored to OPERABLE status or the required thermal operating limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must* be reduced to < 23% RTP As discussed in the Applicability section, operation at< L3% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel during the applicable safety analyses transients. The 4 hour Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner without challenging unit systems. SR 3.7.6.1 Cycling each main turbine bypass valve through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will function when required. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.7.6.2 The Main Turbine Bypass System is to actuate iutomatically to perform its design function. This SR demonstrates that, with the required system initiation signals, the vaives will actuate to their required position. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. continued B 3.7-27 Revision No. 119 1.: i' ': BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES ,.._-. : . *-* . .,. _**--PBAPS"UNIT" 3 *. . " SR 3.7.6.3 Main Turbine Bypass System B 3.7.6 This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analyses. The response time limits are specified in COLR. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, 2. UFSAR, 3. UFSAR, 4. UFSAR, 5. Deleted ,._ .. _. .. _-*. ,. *: .,-:. Section 7 .11.3. Section 14. 5 .1.1. Section 14 . 5 . 1. 2 . 1. Section 14.5.2.2. ,'*;:, .. . . '-.-. --. ..*-,. *_,, Revis io.n No. 111 I I . ,*.' l . ,1 _-.--; -* :, -_. :I ... :. .. _.** ; ,*_ . , : . rf *:' I Spent Fuel Storage Pool Water Level B 3.7.7 B 3. 7 PLANT SYSTEMS . B 3.7.7. Spent Fuel Storage Pool Water Level BASES ... '*.: APPLICABLE *SAFETY.ANALYSES * . ... .... *,,* . -* *LCO .. . -.* .:* /i,' The minimum water level ih the spent*fuel storage pool meets the* assumptions of iodine decontamination factors following a fuel handling.accidantf A genetal description of the spent fuel storage pool design is found in the UFSAR, Section 10.3 (Ref. 1). The assumpti ans of the fuel handling accident *are.* found in the UFSAR,* Section 14.6.4 '(Ref. 2). ' . The water 'level above the 1rradiated fUel assemblies is an imp 1 i cit assumption of the fue 1 handling accident. A f ue 1 accident is *evaluated to ensure the radiOl ogi cal consequences* are .:well below the guidelines .set forth .in'10.CFR 50.67 (.Ref.* 3) as modified.in Regulatory

• Gui de.1 .1.83, ',Table .6. A 'fuel handling acci d.ent could . rel e.ase* a fraction of the_* fission product inventory by breach'iiig th.e: fuel rod .cladding as discussed.in Reference 2 .. _., *.' . , . . . . . -. -. . ---The .handli:ng lS evaluated. for the drc)ppi ng. of an fuel orito the The. the spent fuel storage* pool are i than .those* of, the fuel handling 'acci the .reactor.:*:coi::e .. The water OCi evel in the
• spent *fuel-storage pool . provides for absorption of water.
• fission 'product gases before being .. re'i eased to the . secondary* 6ontai riment .atmosphere. Noble gases are not . *refaiiied* i'n:the water arid pat_ticulates are.*retained (.RG 1 . 1'.*as,:
• Append1 x. os ,_ rieni, 3} ,_ * * * * * . . * * * ... . . -; -: ... :_.:::_ .. ...... .. *. . --***, fuel stora*ge pq_ol.'water levei. satisfie.s :crHe.ria 2 *
• and *3.-of :*the NRC .. Policy * -. -.* '** . : -. . . .. . " -* --. . . *--. *. ---. '**: . .. . ' . . :-'. . ; ' -: ' -. >. -:.* _. **--.... . '. .. The spec) f1'ed '1 eyel. °(232. *:ft" 30;.i nches .pf ant el*e.vciJ:ton I 1khi ch, i valent to *22* H 9ver the 'top '.-O:f i rradi.ated -'fuel* .. .asseinb1ies:* :seate*ci , in* spent f ue 1 i?torage poo 1, .racks) * .*.pres'erves_*tt1e'assumptions of *the f'Ue1: ha-ndling . . --*. £*** ** ? * . -. ' .. . ahalysJs:'(Hef; 2J:' ';A,s such, *it is th'e :mjhiinum r_eq'Uired for *:.* . : *::. ' _.'.:fLiel>.tno)t_einept. wi*th1-n the_*s'pent Juet. sto,fagei pool , . ' _, ' . . ' * .. :. ; .. *,_ _ .. --;*--',--* *.;-; *,,,_.:,: ._* *-:-.. --;.,.-:.-'-----:.,-'.=::_:* . : : ! . -. ' .. --. *-* .'*:'_.;: .. * ., .-.. -. ' ... '., ... .,**. *--.:< -.; :,*. ,_. *. PBAPS UNIT 3:: . * .. .-*.: ' .'. * ... ... *, .. , . '. -_-::_ . -.-... .*.,, ; . --....... * .. , *\ " . ..... .. *.* *.* -**,. *. :*' . . ' -' -**-.. *.*._ .,, _*. -... : . . .
• Revi s.i-on . No. 76 -. -' .. . / . ':.'"'* .. .. __ . --:.-.*: I ...

I !*. ! : *BASES (continued) APPLICABILITY ACTIONS SUR V E I L LANCE

• REQUIREMENTS REFERENCES RBAPS UN IT 3 Spent Fuel Storage Pool Water Level B 3.7.7 This LCO applies of fOel assemblies in .the spent fuel storage pool si.nce the potential for a release of fission products exists.
• Required Action A.l is modified by a Note indicating that LCO 3.0.3 does not apply. If moving fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore; inability fo movement of fuel is not a reasbn to require a reactor shutdown. When the initial conditions for an accident tannot be met, action be taken to preclude the accident from occurring. If the spent f0el storage pool level ts less than required, *the movement of fuel assemblies in the spent fuel storage pool is suspended immediately. *Suspension of this activity shall not preclude completion of movement of a fuel assembly to a safe position. This effectively a spent fuel handling actident from occurring. SR .3.7.7.1 T h i s S R v'e r if i'e s t h a t s u ff i c i en t w a t e r i s av a il a b l e i n t h*e event of a fuel handling accident. The level in the spent fuel stbrage pool must be checked periodically. The Surveillance Frequehcy is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Se.ction 10.3. 2 .. UFSAR, Section 14.6.4.* 3. 10 CFR 50.67. B 3.}-30 *Revision No. 87' *
• AC Sources-Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources-Operating BASES BACKGROUND PBAPS. UNIT. 3. The unit AC sources for the Class lE AC Electrical Power Distribution System consist of the offsite power sources, and the onsite standby power sources (diesel generators CDGs)). As required by UFSAR Sections 1.5 and 8.4.2 (Ref. 1), the design of the AC electrical power system provides and redundancy to ensure an available source of power to the Engineered Safety Feature CESF) systems. The Class lE AC distribution system is divided into redundant load groups, so loss of any one group does not prevent the minimum safety functions from being performed . . Each load group has conriections to two qualified circuits that connect unit to multiple offsite power supplies and a single OG. The two qualified circuits between the offsite transmission network and the onsite Class lE AC Electrical Distribution System are supported by multiple, independent offsite sources. One of these qualified circuits can be connected to' either of two offsite sources: the preferred offsite is.the 230 kV which supplies the plant through the 230/13.8 kV. *startup emergency auxiliary transformer no. 2; thee alternate.offsite is the C500/23Q kV) qt North Substation *which feeds a 230/13.8 kV regulating tra'risformer Cs ta rt up and emergency auxiliary . *transformer no. 3), ihe 3SU regulatlng transfo.rmer .* s'witchgear, the 2SUA switchgear. The' aligned source is. further stepped down vi a the 2SU startup tr'ansformer . switchgear through the. 13. 214 .16 kV emergency auxiliary rio. 2. Qualified circuit can connected to either of two offs ite source.s :* the preferred . 'offsite source is the 230 kV Peach Bottom-Newlinville -l'ine .. whi.ch supplies a 230/13.8 kV transformer (startup ... transformer no. 343); alternate offsite source is the. kV) at North Substation whjch . feed s. a 2 30 /13 . 8. kV reg u l a t i n g t r a n s f o r iri e r ( s t a rt up a n d emerge:ncy auxiliary transformer no. 3) and. the 3SU . regulating transformer :switchgear. The aligned source is via the.343SU transformer switchgear*. continued B 3.8-1 Revision No, 83 BASES BACKGROUND (continued) PBAPS UNIT 3. AC Sources-Operating B 3.8.1 the 13.2/4.16 kV emergency auxiliary transformer no. 3. In addition, the alternate source can only be used to meet the requirements of one offsite circuit. A detailed description of the offsite power network and circuits to the onsite Class lE ESF buses is found in the UFSAR, Sections 8.3 and 8.4 (Ref. 2). A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class lE emergency bus or buses. The determination of the operability of a qualified source of offsite power is dependent upon grid and plant factors that, when taken together, describe the design basis requirements for voltage regulation. The combination of these factors ensures the offsite which provide power to the .plant emergency buses, will be fully capable of the equipment required to achieve and maintain safe shutdown during postulated accidents and transients. The plant factors consist of the status of the Startup Transformers' (2SU, 343SU, 3SU) load tap changers CLTC's), the status of the Safeguard*Transformers (2EA and 3EA) and the alignment of the emergency buses on the Safeguard Buses COOA019 and OOA020}. For an offsite source to be considered operable, its LTC's must be in service and in automatic. The grid factors consist of actual grid voltage levels Creal time) and the post trip contingency voltage drop percentage value.
• The minimum offsite source voltage levels are established by the voltage regulation calculation. The transmission system operator <TSO) will notify Peach Bottom when an agreed upon limit is approached. The post trip contingency percentage voltage drop is a calculated value determined by the TSO that would occur as a result of the tripping of one Peach Bottom generator. The TSO will notify Peach Bottom when an agreed upon limit is exceeded. The regulation* calculation establishes the acceptable percentage voltage drop based upon plant configuration. continued . B 3. 8-2: Revision No. 90 BASES BACKGROUND (continued) -.-'. _,*:** * . ... :-. .,. .. ::'*.-* **-* . -. .* PBAPS UNIT 3 .** AC Sources-Operating B 3.8.l Due to the 3SU source being derived from the tertiary of the #l Auto Transformer, its operability is influenced by both the 500 kV and 230 kV systems. The 2SU and 343SU sources operability is influenced only by the 230 kV system. Peach Bottom unit post trip contingency voltage drop percentage calculations are performed by the PJM Energy Management System CEMS). The PJM EMS consists of a primary and backup system. Peach Bottom will be notified if the real time contingency analysis capability of PJM is lost. Upon receipt of this notification, Peach Bottom is to request PJM to provide an assessment of the current condition of the grid on the tools that PJM has The determination of the operability of the offsite sources would consider the assessment provided by.PJM and whether.the current condition of the grid is bounded by the grid studies previously performed for Peach Bottom. Vari*ations to any of these factors is permissible, usually at the of another factor, based on plant conditions. Specif1cs regarding these variations are controlled by plant of by condition.specific design calculations. Adescription of the Unit 2 offsite power sources is* _provided_ in the Bases for Un.it 2 LCO. 3.8.1, .AC Sourtes-. Ope rat i r:ig .". the descri ptfon is i denti cal wi.th the exception that the. two offs1te .. circuits provide power to the Unit 2 4 kV Ci .Unit 3 offsite circuit is commcrn to 1ts respeC:tive Unit 2 offsite cfrcuit. exce.pt for. the 4 .kV emergency bu*s .feeder breakers) .. *(continued) -._ .. ' .:*.,* .. * -.--.' .. '. .. -;:. *-... *, .. -*"" , .. -. ,*.: '-,, .**,* Revision No. 90 **

BASES BACKGROUND (continued) '.:* PBAPS WNIT 3 AC Sources -Operating B 3.8.1 The onsite standby power source for the four 4 kV emergency buses in each unit consists of four DGs. The four DGs provide standby power for both Unit 2 and* Unit 3. Each DG provides standby power to two 4 kV emergency one associated with Unit 2 and one associated with Unit 3. A DG starts automatically on a loss of coc10 t accident (LOCA) signal -Ci .e., low reactor water le 1 signal or high drywell pressure signal) from either Unit 2 or Unit 3 or on an emergency bus degraded voltage or undervoltage signal. After the DG has started, it automatically ties to its respective bus after offsite power.is tripped as a consequence of emergency bus undervoltage or degraded voltage, independent of or coincident with a LOCA signal. The DGs a1so start and operate in the standby mode without tying to the emergency bus on a LOCA signal alone. Following the trip of offsite power, all loads are stripped from the emergency bus. When the DG is tied. to the emergency bus, loads are then sequentially connected to its respective emergency bus by individual timers associated with auto-connected load following a permissive from a -voltage relay monitoring each emergency bus. In event of a loss Of both offsite the ESF loads are automatically connected to the DGs in sufficient time to provide for safe shutdown of both 0nits and to the consequences bf a Design Basis (OBA) a LOCA. Within 59 seconds _ after thi initiating* signal is ail automatically connected loads needed to* recover the unit or maintain -it in a condition are to service. failure-of any one PG does not impair shutdown each DG serves .ah independent, 4 kV emergency bus for each unit. The remaining and emergency have sufficient capability _to mitigate the consequences of a OBA, support -of the Dther unit-, and maintain both units in a *safe condition'. ' Rat_i ngs for *-oGs *,sab *s:*:i;y-_the -requi*rements -of Regulatory Guide L.9 CReL 12}. -Ea'ch o'f the four DGs have the following -----a.-2.60'0-k_W :_-continuous , -b. 300_0 kW:--200.0 ---*.*. c. 3100 kW-200 hours, -*a. * *32?0. kw_""' JO mi'nutes. (continued) . _,_,.. ;B -8--3: .. * .. _-, .. --Revision' No. 119 I -_J AC B 3.8.l BASES (continued) APPLICABLE The initial conditions of DBA and transient analyses in the SAFETY ANALYSES UFSAR, Chapter 14 (Ref. 4), assume ESF systems are OPERABLE.

• LCO. ', .. PBAPS UNIT 3 _-.i-.-*: _.-. ' .. The AC electrical power sources are designed to provide sufficient capacity, capability, redundan*cy, and rel i abi 1 ity to ensure the. availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.5, Emergency Core Cooling Systems (ECCS) and Re.actor Core Isolation Cooling (RCIC) System; and Section 3.6, Containment Systems. The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident and is based upon meeting design basis of the . unit. This includes maintaining the onsite or offsite AC sources OPERABLE during accident conditions* in the event of: a. An assumed loss of all offsite .power or all onsite AC power; and b. A. worst case single failure. AC sources satisfy Criterion 3 of.the NRC Policy Statement. **Two qualified circuits between the offsite transmission network. and the orisite Class IE Distribution Sys.tern and four separate and independent DGs ensure availability of the
• required. power to shut down the reactor and maintain it in a *safe shutdown conditiori after an abnormal operational or a. postulated DBA. In since some
• equipment. required by Unit 3 is powered from Unit 2 sources Containment Atmospheric Dilution System, Standby Gas Treatment System, Emergency Service Water System, Main . Control Room Emergency Ventilation System, and Unit 2 125 VDC battery chargers), qualified.circuit(s} between the offsite transmission Tietwork and the Unit 2 onsite Class IE distribution subsystem(s) needed to support this equipment must a 1 so be OPERABLE. . . An OPERABLE qualified Unit 3 offsite circuit consists of the incoming breaker and disconnect to the startup and emergency auxiliary transformer, the respective circuit path to the emergency auxiliary transformer, and the circuit path to at least three Unit 3 4 kV emergency buses including feeder * (continued}-** B .

BASES LCO (continued) PBAPS 1JNTT 3* AC Sources -Operating. B 3.8.1 breakers to the three Unit 3 4 kV emergency buses. If at least one of the two circuits does not provide power or is not capable of providing power to all four Unit 3 4 kV emergency buses, then the Unit 3 4 kV emergency buses that. each circuit powers or is capable of powering cannot all be the same (i.e., two feeder breakers on one Unit 3 4 kV emergency bus cannot be inoperable). If two feeder breakers are inoperable on the same 4kV bus, then Condition A (and Condition E if an inoperable DG exists) must be entered for one offsite.circuit being inoperable even if both offsite circuits otherwise provide power or are capable of providing power to the other three 4kV buses. An OPERABLE qualified Unit 2 offsite circuit's requirements are the same as the Unit 3 circuit's requirements, except that the circuit path, the feeder breakers, is to the Unit 2 4 kV emergency buses required to be OPERABLE by LCO 3.8.7, "Distribution Systems -Operating." Each offsi te circuit must be capable of maintaining rated frequency and voltage, and accepting loads during an accident, while. connected to the emergency buses: Each DG has two ventilation supply fans; a main supply fan and a supplemental supply fan. The supplemental supply fan provides additional air cooling to the generator area. Whenev.er outside air temperature is greater than or *equal. to S0° F, each DG's main supply fan and suppiemental supply are required to be OPERABLE for the .associated DG to be* OPERABLE. Whenever, outside air temperature is less than 80° F, the supplemental* supply fan .is not requir,ed to be OPERABLE for the associated DG to be OPERABLE, however, the.*. main .. supply fa.n .is reqµired to be OPERABLE for the associated.DG to be OPERABLE . . Each DG must be capable of starting; accelerating to rated* speed and voltage, and. connecting. to its. Unit 3 4 kV emergency bus on. detec.tion of bus. tage.. This -sequence must be accompl':is:hed.within 10 seconds. Each DG must also be capable'bf accepting required' loads within, the assumed loadi'ng interval.s, and must continue: *i::o. . . *operate until. offsi te P.C>wer can be* restored to the emergency buses. are be met fr6m a* variety of* initial such as DG in standby with . the engine hot arid DG in standby with the engine at . . condition. Addi.tional DG capabilities must be demonstrated to meet requ.irec;i Surveillances,.' e.g., cap.ability of the DG

• to re"i.rert *to stanpby s.tatus. on an ECCS signal while operating 'in parallel *test .mode. . sequencing of loads, incl"Q,ding tripping of all loads, is;a required function.for DG*OPERABILITY. ( .* B 3.8-5 Revision 7 4 BASES LCO (cont.in ued) APPLICABILITY ACTIONS 1,*: PBAPS. UNIT° 3 AC Sources-Operating B 3.8.1 In addition, since some equipment required by Unit 3 is *powered from Unit 2 sources, the DG(s) capable of supplying the Unit 2 onsite Class lE AC electrical pnwer distribution subsystem(s) needed to support this equipment must be OPERABLE. The OPERABILITY requirements for these DGs are the same as described above, except that each required DG must be capable of connecting to its respective Unit 2 4 kV emergency bus. (In addition, the Unit 2 ECCS initiation logic SRs are not applicable, as described in SR 3.8.1.21 Bases.) The AC sources must be separate and independent (to the extent possible) of other AC For the DGs, the separation and independence are complete. For the offsite AC sources, the separation and independence are to*the extent practical. A circuit may be connected to more than one 4 kV emergency bus division, with automatic transfer capability to the other circuit OPERABLE, and not viol.ate separation criteria. A circuit that is not connected to at least three 4 kV emergency buses is required to have OPERABLE automatic transfer interlock mechanisms such that it can provide power to at least three 4 kV emergency buses to support OPERABILITY of that circuit. The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that: a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of abnormal operational transients; and b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained . in the event of a postulated OBA. The AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Sources-Shutdown." A Note prohibits the application of LCD 3.0.4.b to an inoperable DG. There is an risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCD 3.0.4;b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in *this circumstance.
• To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the availability of the remaining offsite circoits on a more frequent basis. Since the Required Action specifies.* "perform," a failure of SR 3.8.1.1 acceptance criteria does (continued Revision No. 53 BASES ACTIONS ' .. * '.,-*_ :'.'-. ; . : .. -* .. ' -.. PBAPS UNIT 3 A.l (continued) AC Sources -Operating B 3.8.1 not result in a Required Action not met. However, if a second circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition D, for two offsite circuits inoperable, is entered. Required .Action A.2, which only applies if one 4 kV emergency bus cannot be powered from any offsite source, is intended to provide assurance that an event with a coincident single failure of the associated DG does not result in a complete loss of safety function of. critical systems. These features (e.g., system, subsystem, division, component, or device) are designed to be powered from redundant safety related 4 kV emergency buses.
• Redundant required features failures consist of inoperable features associated.with an emergency bus redundant to the emergency bus that has no offsite power. The Completion Time for Required Action A.2 is i.ntended to* allow time for the operator to evaluate and repair any* discovered This Completion Time also
• allows an exception .to the normal "time zero" fo.r beginning **the allowed outage time "clock. 11 .. In this Required Action the Completion Time only begins on discovery that .both: .. A 4 kV, emergency bus.ha,s* no offs.ite power supplying. *.its loads; _and
• b .. A feature.on another 4.kV emergency . .. bus is: inope_rable.
• If, at* any 'time duting ex_istence of this (Qrie offsite circuit inoperable) required *feature subsequently . inoperable, .this Completion Ti111e.would begin to be * * ** * * * * * * . . ' . .:: ... .. *.,_. Di scoverj hg no offs tfe .. power tti. orie 4 kV .. bus* of the onsite* Class .lE Power Distribution System cofocident . *with 'one or*more inoperable required .support or supported *.features, or both, that are associated with any other . emergency 0bus th.at .has offsite power, results in: starting .. . the-: comp'l eti on for* Required. Act ion. Twenty-four . . hours is acceptable because:* it minimizes r.i s k while a, l lowing t:ime-.for.restoration before the unit is.subjected to.*
• trans1 en ts associated with>s.hutdown. * '*" * * * *.*. *_*, -.. -. ,* _, .... ' B 3.8-7 .. Revision 5.

BASES ACTIONS . -:*-. .PBAPS UN IT *3: . **.-. A.2 (continued) AC Sources-Operating B 3.8.1 The remaining OPERABLE offsite circuits ahd DGs are adequate to supply electrical power to the onsite Class lE System. Thus, on a component basis, single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 hour Completion Time takes into account the component OPERABILITY of.the redundant counterpart to the inoperable required Additionally, the 24 hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for-repairs, and the low probability of a OBA occurring during this period. The 4 kV bus design and loading is sufficient to allow.operation to continue in Condition A for a period not to exceed 7 days. With one offsite circuit inoperable, the reliability of the offsite system is and potential for a*loss of offsite power is with for a challenge to the plant safety systems. In this tcindition, however, the remaining OPERABLE offsite circuits:and the four DGs are adequate to supply electrical power to the onsite Class lE Distribution The Tday Completion Time takes into account the redundancy, capaGity, and of the remaining AC sources,* for the low probability of a OBA octurring

• cont1nued **.* .* .. :-*.* ".'*I . -,: __ . B 3 8
• Revision.No, 86

! I;

• BASES ACTIONS (continued). ' ' ' * *P:BAPS UN IT 3 .* .... AC So.urces-Operating
• B 3.8.1 The 33 kV Conowingo Tie-Line, using a separate 33/13.8 kV trahsformer, can be to supply the circuit normally supplied by startup and emergency auxiliary transformer no. 2. While not a qualified circuit, this alternate source is a direct tie to the Conowingo Hydro Station that provides a* highly reliable source of. power because: . the line and transformers at both ends of the line are dedicated to the. support of PBAPS; the tie line is not subject to damage from adverse weather conditions; and, the tie line can be isolated from other. parts of the grid when* necessary to* ensure availability and stability to support PBAPS .. The availability of this .highly reliable source of offsite power permits extension of the allowable out of service time for a DG to 14. days from the discovery of failure to meet LCD 3.8.1.a 6r b (per Required Action B.5). Therefore, when a DG is inoperable, it is necessary to verifY the availability of the Conowingo Tie-line immediately and once per 12 hours thereafter. The Completion Time of "Immediately" reflects the fact that in order to ensure that the full 14 day Completion Time of Required B.5 is available for completing preplanned* maintenance of. a DG, prudent plant practice at PBAPS dittates that the availability of the Conowingo Tie-Line be verified prior to making a DG for preplanned maintenance. The Conowingo Tie"Line is available and satisfies the . bf Required Action B.l if: 1) the Conowingo line is iupplying power to the 13.8kV SBO Switchgear OOA306; 2) all equipment required, per SE-11, to connect power from t.he* Conowingo T1e-Line to the emergency 4kV buses and to . isolate all loads from the Conowingo Tie-Line available and accessible; and 3) communications with th.e Conowingo control room indicate that required equipment' at is If Required B.1 is not met *or the. ***'.; continued Revision. No. 86 I, ,:: .*:*:; *' . . .. .*. -. . *. . . * .. *:*' : . *. :'. :*.:.: .. -:: . .:..._: .. BASES ACTIONS :,:. *.* .... : . ** .. *:* * . . *. . .. : .. ; . . : .. ; . ,. -. . .. ; . .,-_._*. ::. ' _ ..... _. '. ,-.: . *.* :* .' ****. *t ' .. , ... * -**., .*** . ... * ._, .. ,1,., ;-:* B.1 (continued) AC Sources -Operating
• B status.of the Conowingo Tie-Line changes after Required Action B.1 is initially met, Condition C must be immediately . entered. *. To ensure a highiy reliable power source remains with one DG inoperable, it is necessary to verify the availability of
• the required offsite circuits on a more frequent Since the Required Action only specifies "perform," a .. ** fa i 1 ure of SR 3. 8 .1.1 acceptance criteria does not result in* a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. -Upon offsite circuit inoperabil ity, additional Conditions must then be entered. B.3 Requfred Action B.3 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety
• function of*crjtical systems. These features are designed. to be powered from redundant safety related 4 kV emergency* buses. Redundant* required features failures consist of .. . inoperable features associated with an emergency bus ' * .* *.* . redundant to the emergency bus that has an i DG , *:*:* .. *\
• The Completion Time. is *intended to allow the operator*tinie .. *to evaluate and repair any discovered *This Comp1 et ion* Time a lSo allows for an on to the normal . . "time zero" for beginning the .outage time "clock."
• Jn this;'Required-Action the Completion TiD.ie only begins on diScovery that -* * *> .. ** * * *. ** .. * *. * -, *. * ' *> * *a.
• An and. , _ .. .. . . ' . .. . . .: *.** *-b *. A* redundant' on. another' 4 . kV : . .* bus is inoperable .. :. .. * * ** olf, at any time t.he existence .of this ConditiOn (one>"* ..... *DG inoperab_le); a required feature subsequently becomes * . .. inoperable,. th.is. et ion Time begins to be tracked.-. . . ' : . -.. one'-DG* co.incident 'with one .or* : . .. required support or *supported fef!tures, *:or -that *are as:soc_iated t_he OPERABLE DGs results in*.. < " _ . -*:.'.:--.* * ... ,: ,.'*, (continued).' :*.*:. -, .:-.-.** -* . , ..... ..... :--.. * *.B "; : , . "* : . . ... -*:: .* * .. * . .-,.::. *' *:: ... **-;, . *j .* .. 1 BASES ACTIONS PBAPS UN IT 3 B.3 (continued) AC Sources-Operating B 3.8.1 starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown. The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class lE Distribution System. Thus, on a component basis, single failure protection for the required feature's function may . have been lost; however, function has not been lost. The 4 hour Completion Time takes into account the component OPERABILITY of the counterpart.to the inoperable required feature. Additionally, the 4 hour Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a OBA occurring during this period. B.4.1 and B.4.2 Required Action B.4.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be *determined that the cause of the inoperable DG does not exist on the OPERABLE DGs, SR 3.8.1.2 does not have to be performed. If the of inoperability on other DG(s), they are declared inoperable upon discovery, and Condition For H of LCD 3.8.1 is entered, as applicable. Once the failure is repaired, and the common cause failure no longer exists, Required Action B.4.1 is satisfied. If *the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DGs, performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DGs. In the event the inoperable DG is restored to OPERABLE status prior to completing either B.4.1 or B.4.2, the PBAPS Corrective Action Program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer required under the 24 hour constraint imposed-while in Condition B. According to Generic Letter 84-15 (Ref. 5), 24 hours is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG. continued B 3.8-11 Revision No. 61

.;,, BASES AC Sources -Operating B 3.8.1 ACTIONS 8.5 (continued) *--* -.--*'. -*. The availability of the Conowingo Tie-Line provides an additional source which permits operation to continue in Condition B for a period that should not exceed 14 days from discovery of the failure to meet LCO 3.8.1.a or b. In Condition B, the remaining OPERABLE DGs and the normal offsite circuits are adequate to supply electrical power to the onsite Class lE Distribution System. The Completion Time of Required Action B.5 takes into account the enhanced reliability and availability of offsite sources due to the Conowingo Tie-Line, the redundancy, capacity, and capability of the other remaining AC s_ources, reasonable time for repairs cif the affected DG, and low probability of a OBA occurring during this-period. The Completion Time for Required Action 8.5 also establishes a limit on the maximum time allowed for any combination of required AC pciwer to be inoperable during any single contiguous occurrence of failing to meet LCO 3.8.1.a orb. If Condition B is entered while, for i_nstance, an offsite circuit is inoperable and.that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 1*days. Th1s situation could lead to a total of 14 days, since initial failure of LCO 3.8.1.a or b, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional :7 (for a total_ of 21 days) al lowed prior to '. _complete-restoration of the LCO.

• The_ 14 day Completion Time -limit on the allowed in a specified
• condition after .discovery of failure to ineet LCO 3.8.La or _ This: l illiit is considered reasonable for-situations in whic_h A and B are .entered concurrently. The 14 day Completion Time would also lirnit--tlle maximum time _a DG is -inoperable if the status of the Conowingo Tie-Line _ _ changes from being being not ava'ilable (this :is -_disc_ussed.*in Require4*Action C.l Basesdiscussion). -As ActiOn:_B.3, the Completion allows 'for an -_ ' ' exception to the" normal "t-iriie _zero" for beginning the " -allowed '.outage time "clock." This exception results in _ -the-"time zero" at the time that the -LCO_ was initially not met, instead-of the time that Condition B was entered. -,*: -.*;*' . *.***: _ c continued) ---..... :. '--... -. '**-** .. ..;*. . PBAPS UN IT 3. "_ Revision No. 1 * , '

BASES ACTIONS . ,. -: ' . ... -** P.BAPS UN iT 3 ** * :! B.5 (continued) AC B 3.8.l The extended Completion Time for restoration of an inoperable DG afforded by the availability of the Conowi ngo Tie-Line is intended to allow completion of a generator overhaul; however, subject to the diesel generator reliability program, INPO performance criteria, and good operating practices, using the extended Completion Time is permitted for other reasons. Activities or conditions that increase the probability of a loss of offsite power (i.e., switchyard maintenance or severe weather} should be considered when scheduling a diesel generator outage. In addition, the effect of other inoperable plant equipment should .be considered when scheduling a diesel generator outage. C. l If the the Conowingo Tie-Line is not verified within the Completion Time of Required B.l, or 1f the status of the Conowingo Tie-Line. changes after Action B.l is initially met, the DG must be restored to.OPERABLE status within 7 days. The 7 day Completion Time begins upon *entry into Condition C {i.e.,

• upon d i-scovery of failure to meet Requ Action B .1 L the total time to restore an inoperable DG cannot exceed 14 days.(per the. Completion Time of Required Action B.5).**. . . The 4 kV emergency bus design and loading is sufficient to a 11 ow operation to continue in Colid it ion B for a period that
• s.houldnot exceed 7 days,.if the Conowingo.Tie-Line is not *.available (refer to Required Action B.l Bases In Cond.itiori C, :th.e ref!J:atning OPERABLE DGs and offsite.
• c_ircuits .are adequate tp supply electriC:al *power to the *onsite Class IE Distribution System. *The ].day.Completion ** .. Ji me takes into account the :redundancy",* capacity, and,.. . *capability of the remaining AC sources; reasonable time for rep a frs : and . low li ty of a OBA occurring during this' * .* . . . . ' . . ' . . . . ... *** .. "-. (continued) . . _ .. *.'-; ,** .. . *.,*** :,.,_ ..
• No. o .

BASES ACTIONS (continued) 3 -**-.-, D.l and D.2 AC B 3.8.l Required Action D.1 addresses actions to be taken in the .event of inoperability of redundant required features concurrent with inoperability of two or more offsite circuits. Required Action D.1 reduces the vulnerability to a of function. The Completion Time for taking these actions is reduced to 12 hours from that allowed with one 4 kV emergency bus without offsite power (Required Action A.2). The rationale for the reduction *to 12 hours is that Regulatory Guide 1.93 (Ref. 6) allows a Completion Time -of 24 hours for two off site circuits inoperable, based upon the assumption that two complete safety divisions are ... OPERABLE. (While this Action allows more than two circuits to be inoperable, Regulatory Guide 1.93 assumed two circuits

• were a 11 that were required by the LCO, and a 1 oss of those two circuits resulted in a loss of all offsite power to the Class IE AC Electrical Power Distribution Thus, with the Peach Bottom Atomic Power Station design, a loss of more than two offsite circuits results in the same
• conditions assumed in Regulatory Guide 1.93.) When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of
• 12 hours is appropriate. These features are designed with redundant safe.ty related 4 kV emergency buses. Redundant* required features failures consist of any of these features that are. inoperable because any inop.erabil ity is on an emergency bus redundant to an emergency bus with inoperable offsite circuits.
• The Completion Time Required Action D.1 is intended to allow the operator time to evaluate and repair any *discovered This CompletiQn Time also allows for an exception to the normal "time zero" for* beginning the allowed riutage time "clock." In this Required= the Completion Time only begins on discovery that both: * * . a. Two or more offsite circuits are inoperable; and b. A required feature is inoperable. (continued} . } ' 83 *. 8:-14 . *' -*. 'I'.. _J BASES ACTIONS I ... : .. : . *. :*** 1.' _'. ,-'._., .. ! ., * . *:-',* .,. :: *,: -, ..... * ,. ,* .: --* .. :*. -* ', ; _, .. .. *.--.__:.* " -... -.. . . ; :,* -. *. *_: ___ ** .* .. **'" .. --: *_;, *. ' *=-.. ** ..*. . ::.*: : .. **** -* .. i_:. *:,:.. ., -_: .. : ;., .* '; **: ..... *-1. ,I ,;: *. * ' . * .. ., AC . B 3.8.1 0.1 and 0.2 (continued) Ii, at any time.during the existence of this Condition (two. or more* offsite circuits inoperable any combination of
• Unit 2 and Unit 3 offsite circuits inoperable), a required feature subsequently becomes inoperable,. this Completion*
• Time begins to be tracked. According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition 0 for a period that not exceed 24 hours .. This level of degradation means that the offsite electrical power system may not have the capability. to* * .effect shutdown and to mitigate the effects of :an accident; however., the onsite AC sources have not been . degraded. This level of degradation generally corresponds
• t.o a total loss of the immediately acces.sible offsite power sources . . Because of the.normalfy high availability of the offsite* sources, this level of degradation may appear to be more' severe than other:combinations of two AC sources inoperable that involve one or more DGs inoperable. However; two . factors* tend to decrease.the.severity of this degradat'ion level: * * * . . . ' .
• a.
• The configuration of the redundant AC :.power, system remajns available is not. to.*a * *single bus or switching failure; and* . ***. . b ... *. The ti me requ i reci to detect and rest9re an i 1 ... off.site power* source is gen er.ally. much less that .. *.required to*detect and restore an unavailable ons*ite::
• AC source .. * * * *. * ,. .. . . . . . -,* ... With,.two more Qf the. off site .ci rtui ts .inoperable,* ..... . sufficient onsite AC sources are* av*ailable to *maintain the> **.*unit in a safe shutdown conditiori in" the event of al)BA o*r .
• trarisienL In *fact,. a simultaneous lo.ss of offsite AC
• sou*rces,. a lOCA, and a worst case single failure were* * .postulated as a part of.the design basis: in the safety.*.
• analysis. 'Thus, the 24. hour Completion Time provides: a ** *' period of time.to restoraticm of. all* but one of the, ** off site :.circuits conimensurate with< the importance of . ** , *. * * .... maintaining an* Ac electrical power system capable of .. ** its destgn
• crjterfa * .... * * * * * * * ** .. * . * * -' . -. . . ' .. _:"* . koni.inuedl .. * . >* . *.*.-.* .*j* .: *. B 3 .*8-15' . * .* ; ** ..= . *-.

BASES ACTIONS. . . . : . :. ' . .-. . PBAPS UNIT 3 *.. * ' ' ***_ .. ,,,.*-.-: :;_,i -. ' .. . ... *,. *.. ........ __ D.l and D.2 (continued} AC Sources -Operating B 3.8.1 According to.:Regulatory Guide 1.93 (Ref. 6), with the . avail able offsite AC sources two less than required by the. LCO, operation may continue for 24 hours. If all offsite sources are restored within24 hours, unrestricted operation may continue. If a 11 but one offs i te source is restored within 24 hours, power operation continues in accordance with Condition .A. *

• E.1 and E.2
• Pursuant to LCO 3.0.6, the Distribution Systems-Operating ACTIONS would not be entered even if all AC sources to it* .. were inoperable, resulting in de-energization .. Therefore,
• the Required Actions *of Condi ti on E. are modified by a Note *to indicate that when Condition E is entered with no AC .
• source to any 4 kV emergency bus, ACTIONS for LCO 3.8.7, "Distribution Systems-Operatin*g, 11 rriust be immediately . entered *. This. allows Condition E to provide. requirements for tlie loss of the offsite circuit and one DG without
• regard to whether a 4 kV emergency bus is de-energized. LCO 3.8.7 provides the-appropriate restrictions for a de-:energiz,ed.4 kV emergency bus . .
• Actordi.ng to Regulatory Guide 1.93 (Ref. 6L. operation may continue i.n Condititjn, E for a period that should riot exceed *
• 12 hours.*. In Condition individual redundancy is lost in both .the *offsite electric.al power system and the onsite AC electrical power system. Since power system redundancy is "prov.ided. by two diverse sources of power, however, the. reliability of the power systems in this Condition may appear higher than that -in Condition D (loss of two or more offsite.Circuits} .. This.difference in reliability is offset by the susceptibility of this power system configuration to . a single bus or .switching failure. *The 12 hour Completion ***Time takes into account the capacity and capability of the remaining AC reasonable time for repairs, and the. low probability of a OBA occurring during this period. {continued) . B 3 .B-16.
• Revision No. 0
• I

-.. ; BASES ACTIONS (continued) *,*:*' _.-*.,*:.:._ :.-.-** .. *. *.* PBAPS UN IT 3 AC Sources -Operating B 3.8.1 With two or more DGs inoperable, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown. (The immediate shutdown cause grid instability, which could result in a total loss of AC power.) . Since any inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation* is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation. According to Regulatory Guide 1.93 (Ref. 6), with two or more DGs inoperable, operation may continue for a period that should not exceed 2 hours. (Regulatory Guide 1.93 assumed the unit has. two DGs. Thus, a loss of both DGs res u l _t s i n a t o t a l l o s s of .o n s i t e p owe r . T h e re fo re , a l o s s of two DGs; in the Peach Bottom Atomic Power design, results in degradation no worse than that* . assumed* in atory Gui de l*, 93.) .. ,* .. *_ *G.l If 'the ihoberable AC e1ettrical cannot restored to within the CompletiDn .Ji'me* CR_equire*d Actjon and assocfated_Completion Time of_ . COn'ditibrfA, *c, D, E, or F.*not met; or Required' Action B.2, B.3, B.:4.f, B.4 .. 2 *. or B.5::and associatedCompletion Time no.t met), the unit must be brought to a .MODE i ri which. the * .

• ove'-r"aJl:pJant *risk fs rilin..imized. To achieve this status, , the unit must*. be brought to.*: at least MODE 3 wi.thi n 12 hours. * .. ****Remainihg<Tn :the' App'fitabilHy of:th*e LCD is acceptable because plant risk i'n MODE 3 is _similar to *or lower than thE: in.MODE 4 (Ref. 1.1) and because the time .spent in-. MODE 3'to* perform the>_neCe$sary repairs to restore the *system to OPERABLE status wilYbe short. However, voluntary entry in;to:MODE 'may*be ma-de *as it is, :also an acceptabte .. -* .. YOw-r.1 s k. state. The a 11 ow.ed. Comp 1 et.ton Ti me i,s rea sonab 1 e ,'. based oh operati'ng* experience, to the requ'i red _pl ant conditfons' from full power.__condi tlons in' an orderly manner ' and w-itfloli_t.chai'lenging plant_s/stem$.. * . '(continued) . B 3.8-lT Revision No. 67 BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS ,* "* PBAPS -UNlT 3 --AC Sources-:-Operating B 3.8.1 H.1 Conditidn H corresponds to a level of degradation in which redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system may cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commenc,e a controlled shutdown. The AC sources are designed to permit inspection and testing o'f all important areas and features, especially those that have a standby function, in accordance with UFSAR, Section ,L* 5. 1 (Ref. 7) . Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3), Regulatory Guide 1.108 (Ref. Sf, and Regulatory Guide 1.137 (Ref. 9). As Noted at _the beginning of the SRs, SR:3.8.1.1 SR 3. 8. L 20 are applicabie onl-y to the Unit 3 AC sources and SR 3.8.1.21 is applicable only to the Unit 2 AC sources. the SRs discussed h'erein specify and frequency tolerances, the following summary is, applicable. The minimum steady sta:te output voltage of 4160 V corresponds to the minimum steady st,ate voltage analyzed :in the PBAPS emergency DG voltage regulation study. This value all6ws , _ _ for vol-tage drops to motors and-other equipment down through the', i2D *v"level; , _The' maximum steady state output voltage of 4400 v is egua_l to-the steady state: operating voitage -specified* for, 4000, V motors. It ensU:res that f6r a 'lightl-y loaded distribution -the voltage at the terminals-of 4000 v *motors is 'no more-than the ; --nia:xirriurn *:rated steady s-tate operating .* The arid. max.imum of .the -DG are:_-, 58.8 These--v_alues are_etjual +/- % :of the 60-Hz *nomi'ii.al fr:e-quericy arid are der'iv.ecL fro)it.
• the' found in Regulatory Guide L 9' (Ref. 3)-. _-The iurveilla:nce r_equirement *allowance o'f *+/- *2% for. the EDG is intended tb for EDG :tran$ient during _testing. :The nornlnai--frequency value* of ElO Hz _is, credited' __ in plant :a,f1alys;es for'ECCS :performance. . -.'* . (continued) .. ::, .*:*,. Revisi.9n No. 72 ....... *

.BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS .UNIT T * .... *... _.-_: SR 3.8.1.1 AC Sources -Operating B 3.8.1 This SR ensures proper circuit for the offsite At electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source and that appropriate *independence of offsite circuits is maintained. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby power supply to mitigate DBAs and transients and maintain the unit in a safe shutdown condition. To minimize the wear on moving parts that do not get lubricated when the engine ts not running, these SRs have been modified by a Note (Note 2 SR 3.8.1.2 and Note 1 for SR 3.8.1.7) to indicate that all DG starts fbr these be preceded by engine prelube period a*nd followed by a warrnup prior to loading. For the purposes of this testing, the DGs are started from standby conditions. Standby conditions for a DG mean* that the diesel engine coolant and oil are being continuously circµlated and is being maintained consisteht with manufacturer recommendations. In order to reduce stress wear diesel engines, the minufacturer recommends a modified start in which the starting speed of.DGs is limited, warmup is limited to this lower speed, and the DGs are gradually accelerated to synchronous speed prior to These start procedures are the intent of Note 3 to SR 3.8.1.2, which is only a pp l i ca b l e when s u c h mod i f i e.d st a rt p r o c e d u r e s a r e recommended by the manufacturer. SR 3.8.1:7 that the DG from standby conditions and achieves required voltage and frequency

• seconds. The minimum voltage and frequency stated in the SR are those necessary to ensure the
• continued B. 3; 19 *. Revisicin. No. 87 BASES SURVEILLANCE REQU rREMENTS . -, * AC Sources -Operating . B 3. 8. 1 SR 3.8.1.2 and SR 3.8.1.7 (continued) OG can accept OBA loading while maintaining acceptable *voltage and frequency levels. Stable operation at the nominal voltage and frequency values is also essential to establishing OG OPERABILITY, but a time constraint is not imposed. This is because a typical OG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by load application. The surveillance requirement of+/- 2% for the EOG frequency is* intended to allow for EOG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. This period*may extend beyond the 10 second acceptance criteria and could be a cause for failing the SR. In lieu of a time constraint in the SR, PBAPS will monitor and trend the actual time to reach steady state operation as a means of ensuring there is no voltage regulator or governor degradation which could cause a OG to irioperable. The 10 second start retjuirement supports the assumptions in the design basis LOCA analysis of UFSAR, Section 8.5 (Ref. 10). The
• 10 second start requirement is not applicable to SR 3.8.1.2 (see Note 3 of SR 3.8.1.2), when a modified start procedure as described above is used. If a modified .start is not
• used,_the 10 s{art requirement of SR 3.8.1.7 cipplies. Since SR*3.8.l.7' requires a 10 second start, it is more restrictive than SR 3.8.i.2, and it may be* performed in lieu 3.8.1.2. This is the inteht of Note 1. bf SR To mi n i mi z e test i n g of the 0 Gs , Note ,4 to
• SR 3 . 8 . 1. 2 and * *Note 2 to SR _3.8:1 .. 7 a*llow.a single test (instead of two. tests' one for each unit) to satisfy the requirements. *for *both units. is allowed since the mairi purpose of the Surveillance tan be the-test.on either, .. unit. If fails one of these Surveillances, shciul d be' considered inoperable' on both uni ts' unless* the of the failure be directly related to only orie unit. The Frequency is contrblled under the Control Program . * .
• B 3.8-.20
• Revis i.ori 87: I I I
• ,:_. ,*. BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UN IT 3 SR 3.8.1.3 AC Sources-Operating B 3.8.1 This Surveillance verifies that the DGs are capable of synchronizing and accepting a load approximately equivalent to.that corresponding to the continuous rating. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source. This Surveillance verifies, indirectly, the DGs are capable of synchronizing and accepting loads equivalent to post loads. The DGs are tested at a load approximately equivalent to their continuous duty rating, even though the post accident loads exceed the continuous This is acceptable because regular surveillance testing at post accident loads is injurious to the DG, and imprudent because the same.level of assurance in the ability of the DG to provide post accident loads can be developed by monitoring engine parameters during surveillance testing. The values of the testing parameters can then be qualitatively compared to expected values at post accident engine loads. In making this comparison it is necessary to consider the engine parameters as interrelated indicators of remaining DG capacity, rather than independent indicators. The important engine parameters to be considered in making this crimparison include, fuel rack position, scavenging air exhaust temperature and pressure, output, jacket water and lube oil temperature. With the DG operating at or near continuous rating and the observed values of _the above parameters less than expected post accident values, a qualitative extrapolation which shows the OG is capable of accepting post accident loads can *be made without requiring detrimental testing. Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY . . The Surveillance is controlled under the Surveillance Frequency Control Program. continued B 3.8-21 Revision No. 87 BASES SURVEILLANCE REQUIREMENTS .'*. --_.*-PBAPS UN IT 3 SR 3.8.1;3 (continued) AC Sources-Operating B 3.8.l Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. momentary power factor transients above the.limit do not invalidate the test. Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid . perturbat,i ons. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test.to credit satisfactory performance. . -.* To mini mi z.e testing of the .DGs, Note 5 a 11 ows a single* test (instead two tests, Dne.for each unit) to satisfy the. requirements for both units, with the DG synchronized to the 4 kV emergency bus of Unit 3 for one periodic test and synchronized to the 4 kV :e*mergency. bus of Unit 2 during the next petiodic This allowed since the main purpose . of the Survei 11 ance, to *.ensure DG *oPERABI LITY, is still being verified on the frequency, .. and each unit's* . breaker<'tohtrol circuitry' which is only being tested everY, second test* (due to the staggering. of :the tests), .. .. hthoricany haVe a'.yery. lo*w fai)ure .. rate.* Note 5 modifies the specified .frequenc,{ for eac.h unit's break'er control. circuitry :to*the total :of.the combined Unit 2. and Unit 3
• I frequencies. If. the .DG fail*s *one of Surveillances; * * **the DG *shciul d be consi c;ie:r'.ed. inoperable* on both units; unl e,ss the of* the f afl.ure c§r be ,di recti y '.related to only .orie u.r.1it. * 'rn*additJon, tf: the is sthed*ul ed to be performed oh Un.it ,2,*:an*d the Unit 2 Ts* allowance.that provides ah***** t9 performing the test is Used (i.e., when Unit 2 .is tn MODE 4 or 5, or* moving irradiated fuel-assemblies in *the the Ntite to*]nit 2:SR.3.8.Z.l provides an ext:epn6n to performing thi.s test) or .if it is* riot ... p'referabl'e to per{orm t'ne test on a .unit d.ue to -* operati6nai concerns (h_owever time is n.ot *to .exceed the -total":combfned frequency pllJS grate), then the test shaj'l be performea.-_s.ynchroni zed to the Unit 3 4 kV emergency. bu*s .** . .. _-. 'ctontiriued) B.3.8-22. Revision No. 87 ** .. * ' :.

BASES SURVEILLANCE REQUIREMENTS (Continued) "PBAPS UN IT 3 . AC Sources-Operating B 3.8.1 SR 3.8.1.4 This allowance is acceptable provided that the associated unit's breaker control circuitry portion of the Surveillance is performed within the total combined frequency plus SR 3.0.2 allowed grace period or the next scheduled Surveillance after the Technical Specification allowance is no longer applicable. This SR provides verification that the level of fuel oil in the day tank is adequate for a minimum ot 1 hour of DG operation at full load. The level, which includes margin to account .for the unusable volume of oil, expressed as an equivalent volume in gallons. The Survei.llance is controlled under the Surveillance Frequency Control Program. SR 3.8.1.5 Mi c r.o bi o log i cal foul i n g i .s a major cause of fuel o i l degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water. environment in order tb survive. Periodic removal of water from the fuel oil day tanks eliminates necessary environment for bacterial' survival ... This is the most effective means -Of microbiologjcal fouling. In additiori, it eliminates the potential for water entrainment in. the fuel oil during DG *operation. Water may come from any of including condensation, ground water, rain water, contaminated fuel oil, *and breakdown of thE! fueJ oi.l by .bacteria.. Frequent* checking. for and removal *of accuniul ated water. minimizes fouling and provides data regarding the'wc:itertight \nteg_rity of the.fuel oil system. The Survei l la_rice** Frequenfy .is*. controlled under the

• Survei lJ a nee frequency Control Prograni; This SR is for maintenance .. The df water dbes not. necessarily_. represent a fai'lur*e of this SR that accumula:ted water is remo.v.ed during performance of this *
• s u r v e ii la n i::e ; * *. * * .* *
• SR 3.8'.l."6* . *.. ThisS_u*rveillanc.e that e*ach fuel oil'_ trans'fer .. purrip operate_s arid .automatically transfers fuel-oil from Hs<associ ated _stor,age _tank to .its* as.soci ated day .Jank. *.** .. *It is r._equi r_ed to *support cbntjm.ious opera ti on of stqndby power. squrces: This .Survei:l lance provides assurance that (continued)' ...... -,
• No. 87 *.:_ . ,_._. I BASES SURVEILLANCE *REQUIREMENTS PB]\PS.UNIT-3 SR 3.8.1.6 (continued) AC Sources -Operating B 3.8.1 the fuel oil transfer pump is OPERABLE, the fuel oil piping system is the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE. This SR is. modified by a Note. The note recognizes that manual actions for manualiy operating local hand valves and control switches associated with the DG fuel oil transfer system is to support transferring fuel between DGsi testing, and sampling_activities. These manual actions would promptly restore the EOG fuel oil system to an automatic status since the actions are simple and straightforward. Credit fbr manual operator actions for maintaining operability must be controlled procedurally. These actions include a dedicated qualified individual and
• constant communi*cation with main control room licensed personnel.' The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.1.8 Transfer of each A kV emergency bus power.supply from the normal offsite circuit to the alternate Offsite. circuit demonstrates the OPE.RABILITY
• of the. alternate. circuit distribution network *.to power the shutdown loads. The Surveillance is* controlled under the Surveillance Frequency* Control Program.
• This SR is a Note. The reason for the Note is that, during operation with the reactor performance of this SR could cause perturbations to the electrical distribution systems that could challe,nge continued steady state operation and, as a result, plant safety systems. This Surveillance tests the applicable. logic associated with Unit 3. The comparable test specified in Unit 2 Technical Specifications tests the *applicable logic associated with Unit 2. Consequently, a test must be performed *within the specified Frequency. for each unit. As the Surveillance separate tests, the Note (continued) :i<.evisiop No.* 137 v"* ;:i '* ** * * ,. BASES SURVEILLANCE REQUIREMENTS -*, . ; .. -: . PBAPS UN Il 3 / AC Sources -Operating B 3.8.1 SR 3 .8.1.8 (continued} * -. specifying the restriction for not performing the test while the unit is in MODE 1 or 2 does not have applicability to Unit 2. The Note only applies to Unit 3, thus the Unit 3 Surveillance shall not be performed with Unit 3 in MODE 1 or* 2. Credit may be taken for unplanned events that satisfy this SR. SR 3 .8.1. 9 . Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load respotise characteristics and capabtlity to reject the . largest single load without exceeding predetermined voltage and frequency and while. maintaining a specified margin to_ the overspeed trip. The largest single load for each DG iS a residual heat removal pump (2000 bhp}. This Surveillance may be accomplished by: 1) tripping the DG output breakers with the DG carrying greater than or equal to its-associated. largest post-accident load while paralleled to offsite power, or solely supplying the bus, or 2f tripping its associated single largest post-accident load. with the DG solely supplying the bus. Currently, the second .
• op ti on is the method utilizes because the first method * -will result in steady state operation outside the allowable voltage and frequency limits. Consistent with Regulatory
• Guide 1.9 (Ref. 3), the, load rejection test is acceptable if _. the diesel speed does not exceed the nominal (syncnronous} -.
• _*speed-plus 75% o.f. the di-fference between -nominal speed and. the overspeed trip setpoint, or U5%of nominal speed, whichever is lower .. * *
• The time, voltage, and _tole.ranees specified {n this. SR are derived from Regulatory Gui.de 1. 9 (Ref. 3) --recollimendations for response during load sequence intervals .. The 1.8 seconds specified for voltage and the 2.4 seconds *specified for frequency are equal to 60% and 80%, *
• of the 3 second load * .* associated with sequencing the next load following the res.i dual heat removal: (RHR} pumps during *an undervo l tage on the *.bus concurrent
• with a LOCA. -The VO l tage and . frequency .. specified a:re consistent with the pesign range of the*. * . (continued) . ._ B 3.8-25 Revision No: 1 .** * * * .. -*-: .. . ,.

BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT 3 SR 3.8.1.9 (continued) AC Sources-Operating B 3.8.1 equipment powered by the DG.

• SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c provide steady state voltage and frequency values to which the system must recover following load rejection. The surveillance requirement allowance of+/- 2% for the EOG frequency is intended to allow for EOG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by two Notes. Note 1 ensures that the DG is tested µnder load conditions that are as close to design basis conditions as When synchronized with offsite power, testing should be performed at a power factor of 0.89. This power factor is representative of the actual inductive loading a DG would see under design basis accident conditions. Under tonditions, however, 1 allows the Surveillance to be conducted at a power factor other than 0.89. These conditions occur when grid voltage is high, and the ad.ditional field excitation needed to get the power factor to 0.89 results in voltages on the emergency busses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.89 while still maintaining voltage limits on the emergency busses. In other circumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of 0.89 may not cause unacceptable voltages on the emergency . busses, but the excitation levels are in excess of those for the DG. In such cases, the power factor shall maintained as close as practicable tb 0.89 without exceeding the DG excitation limits. To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the *test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. (continued) B 3.8-26 Revision No. 87 BASES SU RV EI LLANC E REQUIREMENTS :. ... .. *.\ PBAPS UN IT 3 *.* .. *_ SR 3.8.1.10 AC Sources-Operating B 3.8.l Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.8, this Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These criteria provide DG damage protection. While the DG is not expected to experience this transient during an event, and continue to be available, this respcinse ensures 1hat the DG is not degraded for future applicati,on, including reconnection to the bus if the trip initiator can be corrected or isolated. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This _SR is modified by two .Notes. Note 1 ensures that the DG is tested under lbad conditions that are as close to
• design basis conditions as po_ssible. , When synchronized with
• offsite be performed at a power factor of :s; 0.89 .. This power factor is representative of the actual ;jriducti ve load 1 ng a OG would see under-design basis atcident certafn tond1ti*ons, Note 1 al lows the Survei l larice to -be -_conducted at a power factor *0th.er than :=:;;-o.89. These condftions_ occur when grid voltage is high, and .the additiorral field ex'ci.tation needed _to get.the power factor.to :s; 0.89:_results in voltages on the emergenc.Y_ busses that are too high; Under these conditions, the power: factor should be maintained as cl os*e as -practic*able to 0.89'.while st*n1*mairitaining acceptable"* volfage_ i imit{*6n-tl:ie emifrgency busses: -in other' ci rcumstarices'.; the *grid voltage may be_ such thpt the m; e.xc1tafioh_-le\tels-ne-eded to\obtain 1i-' power fac:tor of 0.89 may not ,cause ur:iacceptabl e' voltages on the emergency 'busses, continued ;-*. -.;. --'*.-,., * . ..... B J.8-27-Revision _No. 87 -_,

. ,' .* BASES SURVEILLANCE REQUIREMENTS ..... PBAPS -VNIT 3 '* -.. SR 3.8.1.10 (continued) AC Sources-Operating B 3.8.1 but.the. excitation levels are in excess of those recommended for the DG. In such cases, the power factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation limits. To minimize testing of the DGs, Note 2 a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both uni ts, . unless the cause of the failure can be djrectly related to only one unit. SR 3.8.1.11 Consistent with Regulatory Guide 1.9 (Ref. 3), c:2.2.4, this demonstrates the as designed' operation of the standby power sources during loss of offsite source. This test verifies all encountered from.the loss-of offsite power, including* shedding of ail and energization of the emergency and respective loads from the DG. It further* the capability of the DG to achieve the required voltage and frequency within the specifie:d time. The DG*. auto-start and. energi zati.on of the.associated 4 kV emergency time of seconds is from requirements of the accident analysis for responding to a design:-basis large break The Surveillance should be *continued for a m1nimum of 5 minutes in order to demonstrC1te that h*ave stability has . beenc ach,ieved. . '.'. . ; * ( cont i i1 u e d ) . '* ,*, ... -.... :, . .': ,*. -. . **.-.**,;* ' . B 3;8:-27a 58

• . *,' .BASES SURVEILLANCE REQUIREMENTS RBAPS UNIT 3 SR 3.8.1.11 (continued) AC Sources-Operating B 3.8.1 The requirement to verify the connection and power supply of a u t o -con n e t t e d l o a d s i s i n t e n d e d to s a t i s fa ct o r il y s h ow t h e relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or systems are not capable of being operated at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS 0mode of operation. In lieu of actual demonstration*of the connection and loading of these loads, testing that adequately shows the of the DG system to perform these functions is acceptable. This testing may include any seHes of sequential, overlapping, or total .steps so that *the entire connection and loading sequence is verified. The Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by two N6tes. *.The reason for Note 1 is to minimize wear and tear on the DGs during For the purpose of this testing, the be started from standby c6nditions, that is, with the coolant and oil being continuously circulated and temperature maintained conststent with manufacturer retommendationi. The for Note 2 is that performing the Surveillance would remove
• a required offs ite ci rcu it from service, perturb *the electrical *distribution system, and safety *systems. *This Survei ll a nee tests *the applicable logic. associated with Unit 3. The test specified in the Unit 2 Technical Specifications tests applicable logic associated with Unit 2. Consequently, a test must be within the Frequency for each unit. The surveillance allowance rif +/- 2% for the EOG frequency is intended to allow for EOG. transient operatinns during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. As the Surveillance represents tests, the Note specifying the restriction for n6t performing the test while the unit is in 1, 2, or 3 does not have applicability to Unit 2. The Nota only applies to Unit 3, thus the Unit 3 Surveillances shall not be performed with Unit 3 in MODE 1, Credit may be taken for that satisfy this SR. . . continued B3.8-28 Revision* No. 87 *. I

..... ,.. ., BASES SURVEILLANCE REQUIREMENTS (continued) PBAPS UNIT 3' * .. ., SR 3.8.1.12 AC Sources -Operating B 3.8.1 Consistent with Regulatory Guide 1.9 (Ref, 3), paragraph C.2.2.5, this Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (10 seconds) from the design basis actuation signal (LOCA signal) and operates for 5 minutes. The minimum voltage and frequency stated in the SR are those necessary to ensure the DG can accept DBA loading while maintaining acceptable voltage and frequency levels. The surveillance requirement allowance of +/- 2% for the EDG frequency is intended to allow for EDG transient operations during testing. The.nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. Stable operation at the nominal voltage and frequency values is also essential to DG OPERABILITY, but a time constraint is not imposed. This is because a typical DG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by load application. This period may extend beyond the 10 second criteria and could be a cause for failing the SR. In lieu of a time constraint in the SR, PBAPS will monitor *and trend the actual time to reach steady state operation as a means of ensuring there is no voltage regulator or governor degradation which could cause a DG to become inoperable. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d and SR 3.8.1.12.e .. *.ensure that permanently connected loc:i.ds and emergency*loads are energized from the offsite electrical pqwer system on a LOCAsignal without loss bf offsite power. The requirement to verify the connection and power supply of and_ autoco:imected .loads is intended to 'satisfactorily show the relationship of l.oads to .the loading logic for load{ng onto offsite power. In certain ma:riy of these. loads cannot actually be_ connected or loaded. without undue hardship or potential for :undes*ired operation. "For**instance, ECCS *injection valves are not desired to l:Je sttoked open, ECCS are not*.. * ... ; ** capable of being operated at full flow, or RHR systems performing a decay _heat .:r-emoval function .are not desired to* be realigned to the Eccs*mode of operci.tion. In lieu of .actual. demonstration of the connection ahd -loading of these loads, testing that adequately shows the capability of the *oG system to perform these functions is acceptable.* Tqis. testing may ariy series Of sequential, overlapping,, .or total steps so tha*the entire *

• is yerified. * ..... . ( B 3.8-29 Revision No. ; 72
• BASES SURVEILLANCE REQUIREMENTS PBAPS. UN IT 3 AC Sources-Operating B 3.8.1 SR 3.8.1.12 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations. SR 3.8.1.13 Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.lZ, this Surveillance demonstrates. that DG noncritical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiation test signal. Noncritical automatic trips are all automatic trips except: engine overspeed, generator differential overcurrent, generator ground neutral overcurrent, and manual cardox initiation. The trips are during DBAs and to provide an alarm on an abnormal engine *condition. This alarm provides the operator with sufficient time to appropriately. The DG availability to .mitigate the OBA is more critical than protecting the engine against mi nor problems .that are not immediately detrimental emergency operation of the DG. DG emergency automatic trips will be iested periodically per the station periodic maintenance program. The Surveillance Frequency is controlled under the Frequency Control Program. To minimize testing of the DGs, the Note to this SR allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. continued ...
• B 3.8-30 Revision No. 87

.. ,. --*'-;.;" BASES SURVEILLANCE REQUIREMENTS (continued) *, ,*: *. ':.:*. -_:. PBAPS UN IT .3 SR 3.8.1.14 AC Sources-Operating B 3.8.1 Consistent with Regulatory Guide 1.9 (Ref. 3), paragraph C.2.2.9, this Surveillance requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours. However, load values may deviate from the Regulatory Guide such that the DG operates for 22 hours at a load approximately equivalent to 92% to 108% of the continuous duty rating of the* DG, and 2 hours of which is at a load approximately equivalent to 108% to 115% of the continuous duty rating of the DG. The DG.starts for this Surveillance can be performed either from standby or hot conditions. The provisfons for prelube and warmup, discussed ih SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

• This Sorveillance verifies, indirectly, that the DGs are capable of synchronizing and accepting loads equivalent to post accident loads. The DGs are tested at a load approximately equivalent to continuous duty rating, even th6ugh p6st accident loads exceed the
• rating; This is acteptable because regular surveillance at post accident loads is injurious to the DG, and imprudent because the. same l eveT of assurance.in the ability of the*. DG to provide post acc.i dent loads can be developed by parameters during The values .of the testing* parameters can then, be qualitativel.Y.coinpared to expected at post acciderit engine Joads. In making this compari'son it is necessary to cons=ider_ the engine pa*rameters as i nterr.e lated i ndi ca tors cif remaining DG capacity; than independent indicators. The* importan't e(lgine .parameters to be ccirisider.ed in making this' comparis6n iriclude; .. fuel' ratk pdsition', scavenging.air pressure; *_exhau5t.temperattire and pressure, engine* output,* jacket *w9ter tempe_raJ.Ur'e;:**and lube.oil temperature.*. With. the DG opera ti rig at .qr near tonfi nuous' rat1 ng and. the -.. *. 'o.bs'er've'd va lues"'6f the' above parameters .1 ess .than expec::;ted* post aC:tide_nf va lu'e's,,, a' qua l i tat1 ve extrapolation which ** shows.the*'oG :;s*:capable* of .. post accident loac!s can be made with out '.reqtii ring detri men ta 1 . testing. * --.-' --**-'* : . ... .:"'!-.,-. , ... . -.... . '*.
• C cbnf:inued) J:* ** . :,,*: B 3.8-31 .* ..... ,,_ *. Re.vision Nb .. 58 BASES SURVEILLANCE REQUIREMENTS . . **. -PBAPS U.N IT 3 SR 3.8.1.14 (continued) AC Sources -Operating B 3.8.1 A load band is provided to avoid routine overloading of the DG. Routine overloading.may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This Surveillance has been modified by three Notes. Note 1 states that momentary transients due to changing bus loads do.not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test.-Note 2 ensures that the DG is tested under load conditions that are as to design basis conditions as possible. When synchronized with offsite power, testing should be performed at a power factor of s 0.89. This power factor is representative of the actual inductive loading a DG would see under design basis accident conditions. Under certai*n conditions, howev.er, Note 2 allows the Surveillance to be conducted .at a power factor other than s 0.89. These conditions occur when grid voltage is high, and the additional field excitation needed to get the power factor to s 0;89 results in voltages on the emergency busses that are too* high. Under conditions, the power factor should be maintained a.s close as. practicable to 0,89 while. still maintaining acceptable voltage limits on the emergency busses, In other circumstances, the grid voltage may be such t h a t -the
• D G e :X c i t a t i on l v e l s n e e d e d t o ob t a i n a p owe r fa ct o.r o f 0 . 8 9 ma Y n o t c a u s e u n a c c e pt a b l e v o l t a g e s o n t he emergency busses, but the *excitation levels are in excess of those recommended for the in such casei, the power fa*ctor shall be maintained as close as pra.cticable to 0.89 without exceeding the DG excitation limits. To minimize testing.of the DGs, Note 3 allows a single (instead of two tests, _one for each unit) to satisfy the,requirements for both. This is._allowed since the main purpose of the Survei.l lahce *:can be, [!let by performing the test on either un.it.* If.the DG"fails,one*_ofthese SurveUlances, the DG shdUld be considered inoperable on both uriHs, unless* the .cause of.the failure*cari be directly *related* to only one unit:**.* *
• SR. 3.8;1:15 .' ,* .. Thi"s Survei l J that the ch es el engine can restart_ from*a hot condi_t_ion, such* as subsequent to shutdown from riormal. Sur\iei 11.ances, .and a chi eve.the req.ui red. voltage **-and *trequeni:y within 10. seconds ..
• The mini mum voltage_ and f_r_equenc.Y stated in the -SR *are_those necess.ary to ensure the ** DG can accept DBA:loa.dirig w.hile maintaining voltage and freque:ncf levels.' Stable* opera ti on at the_ . nominal-voltage and frequency valuesis*al-so essential to *establishing but.a. time constraint is imposed*;" This. is* because a typical DG wi_ll experience a* continued ... B 3:8-32 Revision*No. 87 ....

BASES SU RV EI LLANC E REQUIREMENTS PBAPS UN IT 3 ***., SR 3.8.1.15 (continued) AC Sources-Operating B 3.8.1 period of voltage and frequency oscillations prior to reaching steadj state operation if these oscillations are not damped out by load The surveillance requirement allowance of+/- 2% for the EDG frequency is intended to allow for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. This period may extend the 10 second acceptance criteria and could be a cause for failing the SR. In lieu of a time constraint in the SR, PBAPS will and trend the actual time to. reach steady state operation as a means of ensuring there is no voltage regulator or governor degradatibn which could cause a DG to become inoperable. The 10 second time is derived from the requirements of the accident analysis to respond to a design large break LOCA. The Su0veillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by three Notes. Note 1 ensures that the .test is performeci with the diesel sufficiently hot. The that the diesel has operated for at least 2 hours at full load conditions prior to performance of this is based on recommendations for achieving hot conditions. *The load bahd is to routine of the DG. overloads may res.ult inmore frequent teardown inspections in accordance with vendor reccimmendat ions in order to maintain *oG OPERABI LlTY. Momentary transients' due to.changing bus loads do irivalidate this test. Note 2 allows all DG starts to be preceded by an engine pr el ube period *to minimize wear and tear oh the diesel during.testing. To minimize testing bf the DGs, Note 3 allows a test of two tests, each unit) to satisfy the for units. This is a.llowed since the main purpose of the Surveillance can be met by the test on unit .. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit. SR 3.8.1.16 with Regulatory Guide 1.9 (Ref. 3), paragraph C .2. 2 .11, this Survei 11 ance ensures that the manual.synchronization and .load transfer -from the* DG to the tiffsite source can be made and that the DG can be returned continued B 3:8-33 Revision No. 87.-

., BASES SURVEILLANCE REQUIREMENTS ' ' PBAPS UN IT 3 AC Sources-Operating B 3.8.1 SR 3.8.1.16 (continued) to ready-to-load status when offsite is restored. It also ensures that the auto-start logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and can receive an auto-close signal on bus undervoltage, and individual load timers are reset. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This . Surveillance tests the applicable logic associated with 3. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. C6nsequently, a test must be performed within the specified Frequency for each unit .. As the Surveillance represents separate tests, the Note . specifying the restriction for not performing the test while the unit is in MQDE 1, or 3 does not have applicab1lity ' to Unit 2. The Note only applies to Unit 3; thus the Unit 3 Surveillances shall not be performed wi.th Unit 3 in MODE* 1, 2, or 3. Credit may be taken for unplanned events that * * *satisfy this.SR. -* SR 3:8.1.17 . with Regulatorj Guide. 1.9 0Ref 3), paragraph C.2.2.13, demonstration of the test mode override *Ensures that the availability accident condit{ons. {s the result of testing. *Interlocks to -,the, LOCA sen Sing circuits cause the DG to automatically , * .. **. reset tb ready-to-load operation if a Unit**3 ECCS initfatipri s"ignal is *received during operation in the test mode while synchronized to either Unit 2 or a Unit j 4 kV emergency b-us. Ready-to7load *operation is defined as the DG runnihg, . at rated speed and vol tag.e with the DG output breaker open. continued* . B 3.8-34 Revision. No.'8f-I. ... .. BASES SURVEILLANCE REQUIREMENTS .PBAPS UNIT 3. SR 3.8.1.17 (continued) AC Sources-Operating B 3.8.1 The requirement to automatically energize the emergency loads with offsite power ensures that the emergency loads will connect to an offsite source. This is performed by *ensuring that the affected 4 kV bus remains energized following a simulated LOCA trip of the DG output breaker, and ensuring 4kV and ECCS logic performs as designed to connect all emergency loads to an offsite source. The requirement for 4kV bus loading is covered by overlapping SRs specified in Specification 3.8.1, "AC Sources-Operating" and 3.3.5.l "ECCS Instrumentation". In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading is verified. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. To mini.mize testing of the DGs, the Note allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the S0rveillance can be met by performing the test on unit. If the DG fails one of these *Surveillances, the DG should be considered inoperable on both units, unless the cause of the failure be directly related to only one unit: SR 3.8.1.18 *Under accident and loss of offsite power conditions, loads are sequentially connected to the bus by individual load timers (i.e., relays). The sequencing logic controls the permissive and starting signals to motor breakers in timed load blocks as depicted, by example, on Table 8.5.l of Reference 10 to prevent overloading of the DGs due to high motor starting currents. The design interval for each individual load timer is the time between each load block that is applied onto the associated DG and is listed on the example Table 8.5.1 of Reference 10. The load sequence time interval (including the 10% tolerance) ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next timed load block. This that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 10 provides a summary of the automatic loading of emergency buses. continued B 3.8-35 Revision No. 115 BASES SU RV EI LLANCE REQUIREMENTS .***. *' . :. ' .* *.:, . ** ... .-;**. *._-. PBAPS UN IT 3. AC Sources-Operating B 3.8.1 SR 3.8.1.18 (continued) The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 3. The comparable test in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Corisequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note the restriction for not performing the test while the unit, is in MODE 1, 2, or 3 does not have applicability to Unit 3. The Note only applies to Unit 3,_ thus the Unit 3 shall not be performed with Unit 3 in MODE 1, 2, or 3. Credit may be taken for unplanned events that s a t i s f y t h_ i s S R

• SR --3.8.1.19 In th:e event of a OBA cofnC:i derit with* a loss of offs i te pow_er; the DGs are r_equired to supply the necessary power to ESF systems so *that the fuel, *RCS, and contafoment design limits "are not exteed.ed ... This s*urveillan*ce demonstrates DG opera.ti on, as discussed in th.e Bases for SR 3.8:.-Lll; *duri"ng a loss*. of offsite power . a*C:tuaticiri tes:t signal" in conjunct-ion with an ECCS initiation s1gna-l-'." ""In lieu* of actual demonstration of connection and lo.ading of that adequately shows the capabil;.ty of. the otJ*system*to perform these*fundions .is e .. -Thi:s testing* maY. include any series of . "seque[ltiaf, *overlapping, or total steps :so the elitire and "load1rig verified; .: . . -. . . . . . The Su rveill a*nce*: Fre*quen cy is cont ra*l i eci under the . Sur"vei l latice Control Program. ,,*_: ** :ccontinu_ed) . . -.... . .<' . . *': Revision. No. 87. ' .... ' I BASES .SURVEILLANCE REQUIREMENTS .... *' PBAPS .UNIT. 3. SR 3.8.1.19 (continued) AC Sources -Operating B 3.8.1 This SR is modified by two Notes. The reason for 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil being continuously circulated and temperature maintained consistent with manufacturer recommendations. The surveillance requirement allowance of +/- 2% for the EDG frequency is intended to allow for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. The reason for Note 2* i.s that performing the Surveillance would remove a requiied offsite circuit from service, petturb the electrical distribution system, and challenge safety systems. This Surveiilance tests the applicable logic associated with Unit 3. The comparable test specified in the Unit 2 Technical Specifications tests the applicable logic associated with Unit 2. Consequently, a test must be performed within.the specified Frequency for each unit. As the Surveillance represents separate testsi the fiote specifying the restr{ction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicab{lity to Unit 2. The Note only applies to Unit 3, thus the Unit 3 Surveillances shall not be performed with 3 in MODE 1, 2, o.r 3. Credit may* be taken for unplanned events that satisfy*this SR. SR 3.8.1.20 This *Surveillance demonstrates that the DG starting independence has not been*compromised. Also, this Surveillance demonstrates that each engine. can achieve proper speed. within the sp_ecified ti.me when the DGs are* started simultaneously. . . . The minimum voltage and frequency stated in the SR are those necessary to ensure the DG can accept DBA loading while *maintaining acceptable.voltage and frequency.levels. The surveillance requirement -*allowance of +/- for the EDG frequency is infended to.ai:low fcii EDG transient operations. dud.:rig te-sting. -rhe nominal frequency value of 60 *Hz. is * . credited.; *in plant analyses* for; ECCS perfo_rmance. Stable operation at the* norriinal voltage and frequency values i*s also to establishing DG OPERABILITY; but a time constrairit:: is not* imposed .. *_ This is becaus.e .a typical DG will, experience a*.*period' of voltage and *frequency. .* *. osc,ill;i:ti<;ms pri.oi to reaching: steady st.ate operation :if these .Os cflla ti'Oiis are,. not damped out*. by load application. *.
• This period may extend beyond the 10. *second. *acceptance criteria and coulc;l. be a cause for failing the SR.-In J,ieu *. :.o'f a::time:'constraint in tpe* SR, PBAPS will mo:nitor and trend the ac.tual 'time to r:each steady state operation as a inearis ' of ens'ur:irig there '-is no 'voltage regulator. br governor .* . * ** .. *degradation which could cause a DG to** becoi:ne inoperable. * .. __ : __ . (continued) '_,:* . . --.*. B *.3 .' 8.:-3.7 .. Revisi¢m No. 72 I I BAS.ES SURVEILLANCE REQUIREMENTS .. ' . . .,.; .. PBAPS UNIT 3 ,'*.*. SR 3.8.1.20 (continued) AC.Sources-Operating B 3.8.1 The Surveillance Frequency is controlled the Surveillance Frequency Control Program. This SR is modified by two Notes. The reason for Note 1 is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coo]ant and oi1 continuously circulated and temperature maintained consistent with manufacturer recommendations. To minimize testing of the DGs, Note 2 a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This allowed since the main purpose of the Surveillance can be met by performing the test on unit.* If a DG fails one of these Surveillances, a DG should be considered *inoperable on both units, unless the cause of the failure can be directly related to only one unit. SR 3.8.1.21 With exception of this all other Surveillances of this Specification CSR 3.8.1.l through SR applied only to the Unit 3 AC sources. This Surveillance is provided to direct that the appropriate for the required Unit 2 AC sources governed by the applicable Unit 2 Technicai Performance of the applicable Unit 2 Surveillances will satisfy Unit i requirements. as well as satisfying this Unit 3 si*x exceptions are ncited to the Unit 2 SRs of LC0.3.8.1. SR is excepted when onlY one* Unit 2 *offsite circuit by the Unit 3 Specification, sinte there i.s not a second to transfer to. SR 3.8.1.12, SR SR 3:8.1.17,
• SR 3 .. 8.1.18 CECcs* load block requirements only), and SR 3.8:1.19 are excepted since these SRs test the Unit 2 ECCS initiation signal, which is *not needed .for the AC sources to be OPERABLE on Unit 3. The required by the applicable Unit 2 SR also governs performance of SR for Unit 3. Notedi if Unit 2 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note t6 Unit 2 SR 3.8 .. 2.l is applicable. This ensures that a Unit 3 w{ll require a.Unit 2 SR to be 0hen the continued B .Revision Nb .. 87 . -

,'*:' ,_ .. *, *.:. ' .. ; ,* *' BASES SU RV EI LLANCE , REQUIREMENTS REFERENCES . PB AP s'

• UN IT 3 *Ac Sources-Operating B 3.8.1 SR 3.8.1.21 (continued) .Unit 2 Technical Specifications exempts performance of a Unit *2 SR (However, as stated in the Unit 2 SR 3.8.2.1 Note, while performance of an SR is exempted, the SR still must be met). 1. UFSAR, Sections 1.5 and 8.4.2. UFSAR, Sections 8.3 and 8.4. 3. Regulatory Guide 1.9, July 1993. 4. UFSAR, Chapter 14. 5. Generic Letter 84-15. 6. Regulatory Guide 1.93, December 1974. 7. UFSAR, Section 1.5.1. 8. Regulatory Guide 1.108, August 1977 . . 9. Regulatory Gui de. 1.137, October 1979 .* UFSAR, Section . . -' li. NEDC-32988-A, Revision 2, Technicai Justification to . . .. Support Risk-Informed Modi fi ca ti on -to Selected Required *End States for BWR.Plants,* De.cember 2002. . i2. Regulatory Guide*L9.'(Safety Guide 9), March 1971. :'-' B 3.8-39. Revisihn 95* I I AC Sources-Shutdown B 3.8.2 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.2 AC Sources-Shutdown BASES BACKGROUND A description of the AC sources is provided in the Bases for LCO 3.8.1, "AC Sources-Operating." APPLICABLE The OPERABILITY of the minimum AC sources during MODES 4 SAFETY ANALYSES and 5 and during movement of irradiated fuel assemblies in secondary containment ensures that: PBAPS UNIT 3 a. The facility can be maintained in the shutdown or refueling condition for extended periods; b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit status; and c. Adequate AC electrical power is provided to mitigate events postulated during shutdown, such as an inadvertent draindown of the vessel or a fuel handling accident. In general, when the unit is shut down the Technical Specifications requirements ensure that the unit has the capability to mitigate the consequences of postulated accidents. However, assuming a single failure and concurrent loss of all offsite or loss of all onsite power -is not required. The rationale for this is based on the fact that many Design Basis Accidents (DBAs) that are analyzed in MODES I, 2, and 3 have no specific analyses in MODES 4 and 5. Worst case bounding events are deemed not credible in MODES 4 and 5 because the energy contained within the reactor pressure boundary, reactor coolant temperature and pressure, and corresponding stresses result in the probabilities of occurrences significantly reduced or eliminated, and minimal consequences. These deviations from DBA analysis assumptions and design requirements during shutdown conditions are allowed by the LCD for required systems. During MODES I, 2, and 3, various deviations from the analysis assumptions and design requirements are allowed within the ACTIONS. This allowance is in recognition that (continued) B 3.8-40 Revision No. 0 .

BASES APPLICABLE SAFETY ANALYSES (continued) LCO .. *. ._.--. --.. ' --.-. . . :PBAPS UNIT. 3 .. AC Sources-Shutdown B 3.8.2 certain testing and maintenance activities must be conducted, provided an acceptable level of risk.is not exceeded. During MODES 4 and 5, performance of a significant number of required testing and maintenance activities is also required. In MODES 4 and 5, the activities are generally planned and administratively controlled. Relaxations from typical MODES* 1, 2, and 3 LCO requirements are acceptable during shutdown MODES, based on: a. The fact that time in an outage is limited. This is a risk prudent goal as well as a utility economic consideration. b. Requiring appropriate compensatory measures for *.*certain conditions. These may include administrative reliance on systems that do not necessarily meet typical design requirements applied to systems credited in operation MODE analyses, or both. c. * .. Prudent utility consideration of the risk associated with multiple activities that could affect multiple

• systems.* * . Maintaining, to*the extent practical, the ability to perform required functions (even if not meeting .MODES 1, 2, and 3 OPERABILITY requirements) with .assumed to function during an event. * . ' . -In the.eventof ah ac.cident duririg shutdown, this LCO ensures*the capability of supporting' systems necessary for avoiding .jnimedi.ate dffficiJlty, assuming either a loss of all offsite power or a loss of all (diesel ge.nerator (pG)) ... * * * *-** * -.. . . . -, . _.* .' -. The Ac'.* sati.sfy. Cti teriori 3 of. the NRt Poli cf Statement.* * 'circuit" supply1ngthe U.nit 3 onsite ClasslE . power distribution.subsystem(s)* of *tco .. "Distribution . Systems-:-Shutdown,n ensures that all required Unit 3 powered' loads.are powered from offsite power. Two OPERABLE.DGs, the Unit 3 ons1te *1r power distributipn *subsystem(s) required OPERABLE by LCO 3.8:8,: *' ensuf,es:*that.:a power source is available for .. **. -* pow.er< support *assuming a loss *of*the -----* . . ' ' . . -. -.-.. ' -*' ... :*' (continued) -,* Revision O * *.*.

. -. 'f BASES LCO (continued) .. * ,* o-** .:.'. *' . . . . **.:.-,,; .. -* *. PBAPS -UNlT 3. ** AC Sources_: Shutdown B 3.8.2 offsite circuit. In addition some equipment that may be required by Unit 3 is powered from Unit 2 sources (e.g., {ontainment Atmospheric Dilution System, Standby Gas Treatment System, Emergency Service Water System, and.Main Control *Room Emergency Ventilation System). Therefore, qualified circuits between the offsite transmission network and the Unit 2 onsite Class lE AC electrical power distribution subsystem(s), and the DG(s) (not necessarily different DG(s) from those being used to meet LCO 3.8.2.b requirements) capable of supplying power to the required Unit 2 subsystems of each of the required components must also be OPERABLE .. Together, OPERABILITY of the required offsite circuit(s) and required DG(s) ensures the availability of sufficient AC sources to bperate the plant in a safe manner and to mitigate the consequences of events during shutdown (e.g., fuel handling accidents and reactor vessel draindown). Automatic i n.iti ati on* *of the required DG during shutdown conditions is specified in LCD 3.3.5.1, ECCS Instrumentation, and LCD 3.3,8.1, LOP Instrumentation. The qualified Unit 3 offsite circuit must be capable of maintaining rated freqµency and voltage connected to the respective Unit 3 *4 kV. emergency bus(es)*, and of required *loads _during an accident. Qualified offsite circuits are those that are described in the UFSAR, Technical Specification Bases Section 3.8.1 and are part of the basis for A Unii. 3 offsite circuit consi.sts. of the incoming breaker and. disconnect to' the startup and emergency auxiliary *transformer' 'the respective circuit path to the emergencY iuxiliary transformer and the circuit path to the Un.it 3* 4 kV emergency puses required by LCD 3.8.8, iricluding feeder breakers to the required Unit 3 4 kV emergency buses. A qualified Unit 2 offsite circµit's the same as the Unit 3 circuit's . requirements, .0exceptthat: .the circuit *path, including the feeder. breakers, .is to .. the: Unit .2 4 kV emergency bus.es required to be OPERABLE by LCD .... . * -*' -. -, -, ' . The required DGs must be. capabie_ of startin9 *. accelerating *to rated*s.pe.ed*and voltage, and connec;:tirig to th.eir respecti-11,e Unit* 3 .e;mergen.cy bus on detection of bus . . undervoltage. This sequence must *_be accomplished within . io sec;:_ori'ds .. Each DG must al so be capable of-_acc:epti ng requfred l oa'ds within the ass*umed loading sequence * .* i ii t et v *l s , .** a n d mu st . c on ti n u e . o p e r a t e . u ri t i 1 .* offs i te pow e r can he**. reslOred to** the* 4* kV emergency. buses. **These .. ca pa bi lili e a re. r:equ ired to :be met frorri a'.*;V a ri of .-in it1 a L conditions such as DG in standby w*ith engine hot and DG .in* standby wi"th engirie at* ambient *condi.tjons. Additional C contfnued)

• Revision No. 58 .*,..'*

BASES LCO (continued) APPLICABILITY. PBAPS UNIT 3 -** . . '.. ' .... ' -' . -' ... ' ' . .. . AC Sources-Shutdown B 3.8.2 DG capabilities must be demonstrated to meet required Surveillances, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode. Proper sequencing of loads is a required function for DG OPERABILITY. The necessary portions of the Emergency Service Water System are also required to provide appropriate cooling to each required DG. The OPERABILITY requirements for the DG capable of supplying power to the Unit 2 powered equipment are the same as described above, except that the required DG must be capable connecting to its resp_ective Unit 2 4 kV emergency bus. (In addition, the Unit 2 ECCS initiation SRs are not applicable, as described in SR 3.8.2.2 Bases.) It is acceptable for 4 kV emergency buses to be cross tied during shutdown conditions, permitting a single offsite power circuit to supply all required buses_ No automatic transfer capability is required for offsite circuits to be considered OPERABLE.* The AC sources are required to be OPERABLE in MODES 4 and 5 arid during of irradiated fuel assemblies*in the secondary containment to provide assurance that: a. Systems adequate coolant inventory makeup are available for the irradiated fuel assemblies in

• the core in case of an inadvertent dra i ndown of the reactor vessel; b. Systems needed to mitigate a fuel handling accident are
• c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are a*vailable; and d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition. AC power requirements for MODES I, 2, and 3 are covered in LCQ 3.8.L (continued) I Revision O. -* I AC B 3.8.2 BASES (continued) ACTIONS LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement-can occur in MODE 1, 2, or 3, the ACTIONS have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend "' . --PBAPS UN IT ..
• 3 movement of irradiated fuel assemblies would not be
• sufficient reason to require a reactor shutdown. A.l and B.l With one or more required offsite circuits inoperable, or with one DG inoperable, the remaining required sources may be capable of supporting sufficient required features (e.g., system, subsystem, division, component, or device) to allow .. continuation of CORE ALTERATIONS, fuel movement, and operations with a potential for draining the reactor vessel. For example, if two or more 4 kV emergency buses are required per LCO 3.8.8, one 4 kV emergency bus with offsite power available may be capable.of supplying sufficient required features. By the allowance of the option to
• decla:rerequired features inoperable that are not powered from offsite. power (Required Action A.l) or capable of being. powered by the required DG (Required Action B. 1} ,
• appropriate restrictions can be implemented in accordance with the.affected feature(s) LCOs.I* ACTIONS. Required features remaining powered from a qualified offsite power circuit, even if that circuit is considered inoperable. . because it is not powering other required features, are not declared inoperable by this Required Actjon .. If a single DG .is credited with meeting both LCO and one of the DG
• retjufrements of tCO 3.8.2.b, *then the required features remaining capable of being powered by the DG are not declared inoperable by this Required Action, even if the DG -is tonsidered beciuse it is not capable of
• powering other . 'A. 2 . l, A. 2. 2 , A. 2 . 3 , A*. 2 A, B. 2 . 1, B. 2 : 2, B. 2 . 3 , B. 2 . 4, C . 'i, C,2, C.3*,*and. C.4 -With an* offsite circuit not available to *all required 4 kV emergency -bus_ es -on_e ired DG inoperable, the opt ion.* .*. still exists to* declare all. required features inoperable * {continued) -,. -. -.. B 3.8-44 Revision No. O l\_ BASES ACTIONS SURVEILLANCE REQUIREMENTS . PBAPS UNIT 3 AC B 3.8.2 A.2.1, A.2.2, A.2.3, A.2.4, 8.2.1, 8.2.2; 8.2.3, 8.2.4, C.l, C,2, C.3, and C.4 (continued) {per Required Actions A.l and B.l). Since this option may involve undesired administrative efforts; the allowance for sufficiently conservative actions is made. With two or more required DGs inoperable, the minimum required diversity of AC power sources may not be available. It is, therefore, required to suspend CORE ALTERATIONS, movement of irradiated fuel assemblies in the secondary containment, and activities that could result in inadvertent draining of the reactor vessel. Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition. These actions min,imize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC sources and to continue this action until restoration is accomplished in order to provide the necessary AC power to the plant safety systems. The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required AC electrical power sources should be completed as quickly as possible in order to minimize the time during which the plant safety systems may be without sufficient power. Pursuant to LCD 3.0.6, the Oistribution System ACTIONS would not be entered even if all AC sources to it are inoperable, resulting in Therefore, the Required Actions of Condition A have been modified by a Note to indicate that when Condition A is entered with no AC power to any required 4 kV emergency bus, ACTIONS for LCO 3.8.8 must be immediately entered. This Note allows Condition A to provide requirements for the loss of the offsite circuit whether or not a required bus is de-energized. LCO 3.8.8 provides the appropriate restrictions for the situation involving a de-energized bus. SR 3.8.2.l SR 3.8.2.1 requires the SRs from LCO 3.8.l that are necessary for ensuring the OPERABILITY of the Unit 3 AC sources in 0th.er than MODES 1, 2, and 3. SR 3. 8 .1. 8 is not {continued} . B 3.8-45 Revision No. 0

'* '-_' I ! ! . 1: I . -*: ,*_. * * ! ,*. BASES SURVEI'LLANCE REQUIREMENTS -*-_* . *.-. -_.,* : .. *-* ' ',.,. _.::* *.** -. . . PBAPS UNIT 3 SR 3.8.2.1 (continued) AC Sources -Shutdown B 3.8.2 required to be met since only one offsite circuit is required to be OPERABLE. SR 3.8.1.17 is not required to be met because the required OPERABLE DG(s) is not required to undergo periods of being synchronized to the offsite circuit. SR 3.8.1.20 is excepted because starting . independence is not required with the DG(s) that is not required to be OPERABLE. Refer to the corresponding Bases for LCO 3.8.l for a discussion of each SR.

• This SR is modified by a Note. The reason for the Note is to preclude requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during the performance of SRs, and to preclude de-energizing a required 4 kV emergency bus or . disconn*ecting a required offsite circuit during perfomance of SRs. With limited AC sources available; a single event could compromise both the required circuit and the DG *. It is the intent that .thes.e SRs must still. be capable of being met, but actual performance is not required during periods when the DG and offsite circuit are required to be OPERABLE. . . -' ' . This SR is m'od i fi eci by a second Note. The reason for the Note is to preclude requiring the automatic functions of the DG(s) on an .ECCS initiation to be functional during periods .. wlien .ECCS are. not required. Periods in which ECCS are not * *required are .sp*ecified in LCO 3.5.2, *Eccs. -Shutdown*. th.is Surveillance is provided to direct that the appropriate Surveillances for*the* required *Unit 2 AC sources are .. governed by the Unit*2 Jec:hnkal. Spee;ifications.
• Performance .of the. *applicable .. Unit *2 Surveil 1 an.ces: will ** .. satisfy Unit<2 requirements, as well as satisfying this ...
• Un;t 3 SurveiJlance Requirement. Seven exceptions are noted ,:to th'e Unit 2: SRs *of LCO 3.e.J .. SR 3.-8.L8 'is* excepted when
• only one Uriit 2 :offsite circuit is required by the Unit 3
• SpecifJca:tion;. *since _there is not a second .circl!it-to transfer to. SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, . . , SR ( ECCS; load block *requirements. on 1 y), and * . : SR excepted *:since these .SRs test the Unit 2* *< ** ' ECCS. t fat ion sfgna 1, wbi ch is not needed for the AC . <, . . sources to be OPERABLE on* Unit 3. * .. 3-;8.L20 is excepted **.since starting** independence ii.not required with the DG(s) . that *fs _not re*quired. to be 9PERABLE. . . . . .. .. -, '*.* Ccont i nued l * '*', . ' ' . B :. . . * *Revisi.on No.1.a , Amendment No *. 226 J .

. BASES SURVEILLANCE . REQUIREMENTS SR 3.8.2.2 (continued) AC Sources -Shutdown B 3.8.2 The Frequency required by the applicable Unit 2 SR also governs performance of that SR for Unit 3. As Noted, if Unit 2 is not in MODE 1, 2, or 3, the Note to Unit 2 SR 3.8.2.1 is applicable. This ensures that a Unit 3 SR will not require a Unit 2 SR to be performed, when the Unit 2 Technical Specifications exempts perfonnance of a Unit 2 SR or when Unit 2 is defueled. (However, as stated in the Unit 2 SR 3.8.2.l Note, while performance of an SR is exempted, the SR st il 1 must be met) * *

• REFERENCES None. -,,._ ":. . ' ,. ' .. , ... . . . . ... * . .*. PBAPS UN Ii. 3
• 8*3.B-47 . ** Revhion No. 18 -_ Amendment 226. -------------------------* ___ ,,, I I -*. *****-. Di es el Fuel Oil, Lube Oil, and Starting Air B 3.8.3 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air BASES BACKGROUND PBAPS UNIT 3 . .-.. -. Each of the four diesel generators (DGs) is provided with an associated storage tank which collectively have a fuel oil capacity sufficient to operate all four DGs for a period of 7 days while the DG is supplying maximum loss of coolant accident CLOCA) load demand discussed in UFSAR, Section 8.5.2 (Ref. 1). The maximum lo(ld cjemand is calculated using the time dependent loading of each DG and the assumption that all four DGs are available. This onsite fuel oil capacity is suffi ti ent to operate the DGs for longer than the time to replenish the onsite supply from outside sources. Post accident electrical loading and fuel ccinsumpti6n is not equally shared among the DGs. Therefore, it may be necessary to transfer post accident loads between DGs or to transfer oil between storage tanks to achieve 7 days of post accident operation for all four DGs. Each storage tank contains sufficient fuel to support the operation of the DG with the heavfesi load (with four DGs for than 6 days with 31,000 initially in each tahk. Each DG is equipped with a day tank and an fuel transfer pump that will automatically oil from a fuel tank to the day tahk of the DG when actuated by float switch in the day tank. Additionally, the'. capability exists to transfer fuel oil between storage tanks: . Redundancy of pumps and piping precludes the failure of one pump, or the rupture of any pipe; valve, or tank to result in loss of more than one DG. Al_l outside tanks and piping are underground. For proper on of j:_be_ sta_ndby it_ is neces __ proper of the fuel oil. -Regulatory Guide 1.137 (Ref. 2) the recommended fuel oil practices as supplemented by ANSI N195 (Ref. 3). The fuel oil governed by these SRs are the water and sediment content, the-kinematic viscosi*ty, specific gravity (or API gravity), and impurity level. continued .B 3.S-48 . Revision No. 105-:
• '.*, BASES ** BACKGROUND (continued) APPLICABLE SAFETY ANALYSES LCD PBAPS UN 1T J' *, Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 The DG *1ubrication system is designed to provide sufficient to permit proper operation of its associated DG under all loading conditions. The system is required to circulate the lube oil to the diesel engine working surfaces and to excess heat generated by friction during operation. Each engine oil sump and associated lube oil storage tank, along with additional inventory which is stored in a seismic Class I structure that is protected against other natural phenomena, are capable of supporting a minimum of 7 days of operation. Each lube oil sump utilizes a mechanical float-type level controller to automatically maintain the sump at the "full level running" level via gravity feed from the associated lube oil storage tank. :I Each DG has an air start system that includes two air start receivers; each with adequate capacity for five successive normal starts on the DG without recharging the air start receiver. The initial conditions of Design Basis Accident CDBA) and transient analyses in UFSAR, Chapter 8 (Ref. 4), and . 14 (Ref. 5), assume Engineered Safety Feature (ESF) systems are OPERABLE. The DGs are designed to provide sufficient capacity, capability, redundancy, and reliability to. ensure the availability of necessary power to ESF systems so that fuel, Reactor Coolant* system; and containment design limits are not These limits discussed in in the Basei for 3.2, Distribution . Limits; Secti6n 3.5, Emergency Core Crioling Systems {ECCS) and Reactor Core Isolati9n Cooling (RCIC) System; and Sectior:i 3.6, Containment Systems.* Since_ diesel fuel .oil, lube oil, and starting air subsystem** . support the operation of. the. standby AC power *sources, the;y . Criterion 3 .of the NRt Policy Statement. Stored diesel fuel oil is required to have sut"ficient supply fo_r 7 days *of opera ti on ilt ttie worst case post accident -"
• time-dependent l O?Jd profile. It is al so required to meet specific standards for quality. Additionally, sufficient lube oil .supply must be to ensure the capability to operate at full load for 7 days. This. requirement, in continued B 3, 8-.49 . Revision No. 124 BASES LCD (continued) APPLICABILITY ACTIONS . .* PBAPS *UNIT 3 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 conjunction with an ability to obtain replacement supplies within 7 days, supports the availability of DGs required to shut down both the Unit 2 and Unit 3 reactors and to maintain them in a safe condition for an abnormal operational transient or a postulated DBA in one unit with loss of offsite power. DG day tank fuel oil requirements, .as well as transfer capability from the storage tank to the day tank, are addressed in LCO 3. 8 .1, "AC Sources-Operat i ng' II and LCO 3. 8. 2' n AC Sources-Shutdown. II The starting air system is required to have a minimum capacity for five successive DG normal starts without recharging the air start receivers. Only one air start receiver per DG is required, since each air start receiver has the required capacity. The AC sources (LCO 3.8.l and LCO 3.8.2) are required.to ensure the availability of the required power to shut down both the Unit 2 and Unit 3 reactors and maintain them in a safe shutdown condition after an abnormal operational transient or a postulated OBA in either Unit 2 or Unit 3. Because stored diesel fuel oil; lube oil, and starting air subsystem support LCO 3.8.1 and LCO 3.8.2, stored diesel fuel oil, lube oil, and starting air are required to be within limits when the associated DG is required to be . OPERABLE. The Actions Table is modified by a Note indicating that separate Condition entry is a 11 owed for each DG. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem. Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem(s) are governed by separate Condition entry and application of associated Required Actions. (continued) B 3.8-50 Revision No. 0 BASES ACTIONS (continued) :. ' ,* PBAPS UNIT j A.1 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 With fuel oil level< 33,000 gal in a storage tank (which includes margin for the unusable volume of oil), the 7 day fuel oil supply for a DG is not available. However, the Condition is restricted to fuel oil level reductions that maintain at least a 6 day supply {with fuel oil transfer between storage tanks). These circumstances may be caused by events such as: a. Full load operation required for an inadvertent start while atminimum required level; or b.-Feed and-bleed operations that may be necessitated by increasing particulate levels or any number of other oil quality degradations. This restriction allows sufficient time for obtaining the requisite replacement volume and performing the analyses required prior to addition of the fuel oil to the tank. A period of"_ 48 hours is considered sufficient to complete restoration of the required level prior to declaring the DG_ inoperable: This pericid is based on the iemaining capacity (> 6_days)j the fact that procedures will qe' initiated to obtain replenishment, and the low probability of an event during this brief period. B.1-In this -Ccm,dition*,' the 7 day lube oil in.;,entory, i.e.; .I suf.ficient lube oil to support 7 days of-continuous DG ftili lpad not available. the Condi ti.on is -restricted to lub_e _oil vo,lume :that mairitaih *at ieast a 6 *supply. The ltJbe -_, __ oil inventory eqi.ii tb a--6 day supply is 300 gallons . . This time -for' the-*--_ -vpiume .*: A period bf 4 B is ---C_C?nsidei;'ed *t_:a ccimp+ete _rest6ratfon of the -required volume p_i:ior* to declaring the DG' inC:lpera"ble-. period is acceptable based on the -remaining' ca pad ty -(> 6. BayS-1, the _low rate of -usage, the *fact that procedures -.will be to obtain. i-eplenishment, and tbe low pl:'bbab:Clity :of an event ,duiing t.his period. . ' _, __ , --.-*_, B 3.8-51 -(continued)-. " . . Rev1sion No. 136 BASES Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 ACTIONS C.l (continued) ,.*.-' UNIT 3, .*_ ---This Condition is entered as a result of a failure to meet the acceptance criterion for particulates. Normally, trending of particulate levels allows sufficient time to
• correct high particulate levels prior to reaching the limit of acceptability.. Poor sample procedures (bottom sampling), contaminated sampling equipment, and errors in analysis can produce failures that do not follow a trend. Since the presence of particulates does not mean failure of the fuel oil to burn properly in the diesel engine, since particulate concentration is unlikely to change between Surveillance Frequency intervals, and since proper engine performance has been recently demonstrated (within 31 days), it is prudent to allow a brief period prior to declaring the associated DG inoperable. The 7 day: Completion Time allows for further evaluation, resampling, and re-analysis of the DG fuel oil. With the new fuel oil properties defined in the Bases for SR 3.8.3.l riot within the-required limits, a period_of 30 days is allowed for restoring the stored fuel oil* properties. This period provides suffic_ient time to test the -stored fuel oil to determine that the new fuel oil, when mixed with previously stored fuel oil, remains accep.table, or *to_ *restore the stored fuel . o i 1 properties. This
• restoration may involve feed and* bleed procedures, filtering, or combination of these procedures. Even if a DG start and load was required during this time interval-and
• the fuel oil properties. were outside limits, there is high -likelihood the DG would still be capable of performing its intended. fl,inct ion. _-:* > . . .. LL -*w1th starting air -receiver pressure <* 225 psig, sufficient capacity for five successive OG-normal starts does riot exi sL However;. as long as the receiver pressure is . >--150-psig; there is-adequate capacity for at -1 east one start_-attempt,. and the DG can be considered OPERABLE while. . .' ,-*_ <continued} . " ** c '* .* . ' _,.--,
• B_ 3.8.-5.2
• Reyi sion: NO. 0 .** *.. . .

BASES ACTIONS SURVEILLANCE REQUIREMENTS . PBAPS UNIT 3 ' ., *.' ' .. E.l {continued) Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 the air receiver pressure is restored to the required limit. A period of 48 hours is considered sufficient to complete to the required pressure prior to declaring the DG inoperable._ This period is acceptable based on the remaining air start capacity, the fact that most DG starts are accompli!>hed on the first attempt, and the low probability of an event during this brief period. F.L With a Required Action and associated Completion Time of Condition A, B, C, D, or E not met, or the stored diesel fuel oil, lube oil, or starting air subsystem not within limits for reasons other than addressed by Coriditions A through E, the associated DG maybe incapable of performing its intended function and must be immediately declared inoperable. SR 3.8.3.1 This SR provides verification that there is an adequate useable inventory of fuel oil in the storage .tanks to support each of -all four DGs 7 days at the worst case post accident time.:.dependent load profile. 7 day peri6d is sufficient time to place both Unit 2 and *Unit -3 in a safe shutdown condition and to bring in*

• replenishment fuel from an offsite location. The Surveillance Frequency is controll-ed under the Surveillance Frequency Control Program. SR 3.8.3.2 Thi.s Surveillance ensures that sufficient lubricating oil inventory {combined inventory in the DG lube oil sump, lube oii storage tank, and in a seismically qualified structure) is available to support at least 7 days of full load operation for each DG. The lube oil inventory equivalent to a 7 day supply is 3-50 gallons and is based on the DG_ manufacturer's consumption-values for the run time of the DG. The entire inventory.of lube oil required by Technical Specifications shall be stored in a location which Class I and is protected against ot!1er -natural pheonomena Implicit. fn this-_ SR is the* requirement to_ verify the -(continued) B 3.8-53 "Revision-No. 13"6

.* .. BASES SU RV EI LLANC E REQUIREMENTS -. . _** PBAPS *V,N IT 3*, Diesel Fuel Oil, Lube Oil, and Starting Air B 3 .. 8. 3 SR 3.8.3.2 (continued) capability to transfer the lube oil from its storage location to the DG to maintain adequate inventory for 7 days of full load operation without the level reaching the manufacturer's recommended minimum level. The Surveillance Frequency is controlled under the Frequency Control Program. SR* 3.8.3.3 The tests of new fuel oil prior to addition to the storage* tanks are a means of determining whether new fuel oil is of the appropriate grade and has not been contaminaied with substances that would have an immediate detrimental impact on diesel engine combustion. If results from these tests within acceptable limits, the fuel oil may be added to the storage tanks without concern for contaminating the en ti re v o l um e of f u e l o i l i n t he s to r a g e t a n k s .

• The s e t e s t s are to be conducted prior to adding the new fuel to .the storage tank(s), but in no case is the time between the sample (and corresponding results) of new fuel and addition of new fuel oil to the storage tanks to exceed 31 days, The tests, limits, and applicable ASTM Standards are as follow:;: ' a. Sample the new fuel**oil in accordance with ASTM 04057-81 (Ref. 6): .* b.
• Verify.in actordance With the tests specified in 0975*81 6) as discussed in 7 that .the has a viscosity at 40°C df
• c. *.*. centi stokes and ::;; 4 .1 cent.i stokes (if: specific gravity
• was not determined by comparison wi.th the supplier's certification), a flash point 125°F; Verify tests specified in. ASTM: (Ref. 6) as discussed Reference 7 that sample has an absolute specific gravity at 60)60°l o'f . 0.83 0.89 ,:*or an absolute specificgravityof* within 0.0016 at 60/60°F when compared to the or an API at 60°F cif 27'° and::; 39°, or an API gravity of.within .0.3° at 60°F when compared to the supplier's certification;*. and continued B 3.8-54 Revision No:" 87 * : ..

BASES SURVEILLANCE REQUIREMENTS PBAPS UN IT. 3 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SR 3.8.3.3 (continued) d. Verify that the new fuel oil has a clear and bright appearance with proper color when tested in accordance with ASTM 04176-82 (Ref. 6) as discussed in Reference 7; or verify, in accordance with ASTM 0975-81 (Ref. 6), that the sample has a water and sediment content 0.05 volume percent when dyes have been intentionally added to fuel oil (for example due to sulfur content). Failure to meet any of the above limits is cause for rejecting the new fuel oil, but does not represent a to meet the LCO concern since the fuel oil is not added to the storage tanks. Following the initial new fuel oil sample, the fuel oil is anal*yzed to establish that the other properties are within the required acceptance criteria for new fuel oil specified in Table 1 of ASTM The testing methodology must be in accordance with ASTM 0975-81 as discussed in Reference 7, except that the testing methodology for sulfur may be in accordance with ASTM 01552-79 (Ref. 6) or ASTM 02622-82 (Ref. 6) or ASTM 05453 (for ultra low sulfur diesel). Even with the use of ultra-1 ow *sulfur di es el fuel oil, the Technical Specifications acceptance limit for sulfur weight percent is maintained by Table 1 of ASTM 0975-81. In addition to the properties specified in Table 1 of ASTM 0975-81, measurement of lubricity is required, in accordance with the testing methodology in ASTM 06079, with acceptance criteria specified in Table 1 of ASTM 0975-06. These additional analyses are required by Specification 5.5.9, 11 Di es el Fuel Oil Testing Program, 11 to be performed within 31 days following sampling and addition. This 31 day requirement is intended to assure that: 1) the new fuel oil sample taken is no more than 31 days old at the time of adding the new fuel 9il to the DG storage tank, and 2) the results of the new fuel oil sample are obtained within .31 days after addition of the new fuel oil to the DG storage tank. The 31 day period is acceptable because the fuel oil properties of interest, even if they were not within stated *limits, would not have an immediate effect on DG operation. This Surveillance ensures the availability of high quality fuel oil frir the DGs. Fuel oil degradation during long term storage up as an increase in particulate, mostly due to oxidation. The presence of particulate does not mean that the fuel oil will not burn properly in a diesel engine. The particulate can cause fouling of filters and fuel oil injection equipment, however, which can cause engine failure. The fuel oil properties which can affect diesel generator (flash point, cetane number, viscosity, cloud point) do not change during storage. If these properties are within specification when the fuel is placed in storage, they will remain within specification unless other non-specification petroleum products are added to the storage tanks. The addition of non-specification petroleum products is precluded by above described surveillance test progr_am. (continued) B 3.8-55 Re vision No. 124 BASES SURVEILLANCE REQUIREMENTS :. ' '. ,:* ***:,-.' --' -. -. . --, -, PBAPS UN n-3 -<; ,. Di es el Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SR 3.8.3:3 (continued) Particulate concentrations should be determined in with ASTM 02276-78 (Ref. 6), Method A, as discussed in Reference 7 except that the filters specified in ASTM 02276-78, (Sections 3.1.6 and 3.1.7) may have a nominal pore size up to three microns. This method involves a gravimetric determination of total particulate concentration i.n the fuel oil and has a limit of 10 mg/l. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing. *For the Peach Bottom Atomic Power Station design in which the total volume of stored fuel oil is contained in four interconnected tanks, each tank must be and. tested separately. The Frequency of this test takes into consideration fuel oil degradation trends that indicate that particulate concentraiion is unlikely to change significantly between Frequency SR 3 . 8. 3 . 4 Surveillance that, .without the aid 6f the *refill -compressor, sufficient air start capacity for each DG available. The system design requiremehts pr-Ovide for a* minimum of five normal engine starts without recharging. The in this SR is intended t6 reflect the .lowest value at w*hi co _the five starts can be accomplished. The Survein ance Frequency is controlled under the Survei 11 ance frequency Control Program .. -,.'-. Mi c to bi o i og i cal *

• f o u i i rrn i s a m*a j or* ca use .*of fuel o i l *degradation. ** *are numerous bacteria that grow i ti fuel, on.: and cause foulfng; but an mu!;jt ha:ve .a water *-en vi rorirrienf _*1 n .order _ s u ryi ve. / -Period i C:. r_emoval of water from the .fuel storage tanks el ilili ti ates the .necessary environment for*oatterial survival. This is the most effective means controlli:ng microbio'logical* fouling. In ad_dition,-.it' eliminates the_ potenti.ai for water entrainment' in: thf fuel bil during* DG
• opgrat*i on. Wa:ter may come from any. , , of sev'era 1 .. sou r'ces-, i n'cl udi n,g, conderfs at ion; .ground water. , , rain water, contaminated .fue.l oil, and from ,', , * *** *J '* '.' --( continuec{) * !
• __ -_, B 3*:8-56 .. No. 124 . ,,

.... ___ ..... * '* .<* . BASES SURVEILLANCE REQUIREMENTS REFERENCES *.** ... . PBAPS ur.fu.3 Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 SR 3.8.3.5 (continued) breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding* the watertight integrity of the fuel oil system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR*is for preventive maintenance. The presence of does not necessarily represent failure of this SR, provided the accumulated water is *removed during performance of the Surveil 1 ance. 1. UFSAR, Section 8.5.2. 2. Regulatory Guide 1.1.37, Revision 1. 3 .

• AN S I N 19 5 , 19 7 6 . . 4. UFSAR, Chapter 6. 5. , UFSAR, Chapter 14. 6. ASTM Standards: 04057-81; 0975-81; 01298-80; b4176-82; 02622-82; 02276-78; and 0975-06. 7. Letter from G.A. Hunger (PECO Energy) to USNRC Control Desk; Peach Bott6m Atomic Power Station Units 2 and 7 to tscR 93-16, Conversion to Improved Technical Specifications; dated May 24, 1995. *-*.--, . -----. : . B Reyisjon No .. 124 I
• I I

'. DC B 3.8.4 . B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.4 DC Sources-:-Operating BASES BACKGROUND . -.: ' ' ' .PBAPS UNiT 3 ***:; __ . .' The DC electrical power system provides the AC emergency power system with control power. It also provides a source of reliable, uninterruptible 125/250 VDC power and I25 VOC control power and instrument power to Class IE and non-Class IE loads during normal operation and for safe shutdown of the plant following any plant design basis event or accident

• as documented in the UFSAR (Ref. I), independent of AC power availability. The DC Electrical Power System meets the *
• intent of the Proposed IEEE Criteria for Class IE Electrical Systems for Nuclear. Power Generating Stations (Ref. 2). The *DC electrical power system is designed to have sufficient independence, redundancy; and testability to perform its safety functions, assuming a single failure * . The DC power sources provide both motive and control power, and instrument power, to selected safety related equipment, as we 11 as to the nonsafety related . equipment. There are two independent divisions per unit, designated Division I and Division II. Each .division consists of two I25 VOC batteries. The*two I25 VDC batteries in each division are connected in series. Each I25 VDC battery has two chargers (one normally inservice charger and one spare charger) that are exclusively assoC:iated with that battery and cannot be interconnected with any other 125 VDC battery, *The chargers are supplied from separate 480 V motor control centers Each of these MCCs is connected to an independent emergency AC bus. Some of the chargers are capable of being supplied by Unit 2: MCCs,. which receive power: from a 4 kV emergency bus, via manual* transfer switches. However, for a* requfred battery charger to be considered OPERABLE when the ' unit is in MODE 1, 2, or 3, it must.receive power from its associated Unit 3 MCC. The safety related loads betweenthe I25/250 voe subsystem are not transferable except for the Automatic Depressurization System (ADS) valves and logic circuits and the main steam safety/relief valves. The ADS logic circuits and valves and the main steam safety/relief . valves are normally fed from the Division .I DC system. (continued) .. _ .. :* . B 3.8-58 " .. . . . Revi sfon No. 0 ,-_*.*

BASES BACKGROUND (continued) -:-. PBAPS UNIT 3

• DC Sources-Operating B 3.8.4 During normal operation, the DC loads are powered from the battery chargers with the batteries fl oat i ng on the In case of loss of normal power to the battery charger, the DC loads are powered from the batteries. The DC power distribution system is described in more detail in Bases for LCO 3. 8. 7, "Di stri but ion System-Operating," and LCO 3.8.8, "Distribution System-Shutdown." Each battery has adequate storage capacity to carry the required load continuously for approximately 2 hours. Each of the unit's two DC electrical power divisions, consisting of two I25 V batteries in series, four battery chargers (two normally inservice chargers and two spare chargers), and the corresponding control equipment and interconnecting cabling, is separately housed in a ventilated room apart from its chargers and distribution . centers. Each division is separated electrically from the other division to ensure that a single failure in one division does not cause a failure in a redundant division. There is no sharing between redundant Class IE divisions such as batteries, battery chargers, or distribution panels. The batteries for DC electrical power subsystems are siied
• to produce required capacity at 803 of nameplate rating, .* corresponding to warranted capacity at end.of life cycles and the I003 design demand. The minimum design voltage for sizing the battery using the methodology in IEEE 485 (Ref. 3) is based on a *traditional 'LSI volts per cell at the 'end of a 2 hour 1 oad prof i 1 e. The battery terminal voltage using I.BI volts cell is I05 V. Using the*
• LOOP/LOCA load profile; the predicted value of the battery * *terminals is greater than*I05 voe at the end of the profile. Many IE loads operate exclusively at the beginning of the* profile and requtre greater than the* mini.mum terminal' voltage .. The analyzed voltage of the distribution panels* and the MCCs is that required during the
• LOOP/LOCA to support the operation of the IE loads during .the time period they are required to operate. . ' ' '*.* .* . Iach required battery charger of DCelectrical power subsystem. has. amp 1 e power output capacity for the steady state operation of connected loads during normal operatiOn, while at the same time maintaining its battery ( conti nuedl .. * .B 3.a*-59* Revision No .. o ";. '.* : I . I BASES BACKGROUND* (continued) DC Sources-Operating B 3.8.4 bank.fully charged. Each battery charger has sufficient capacity to restore the battery from the design minimum charge to its fully charged state within 20 hours while normal steady state loads following a LOCA coincident with a*loss of offsite power. A description of the Unit 2 DC power sources is provided in the Bases for Unit 2 LCO 3.8.4, "DC Sources-Operating." APPLICABLE The initial conditions of Design Basis Accident (OBA) and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 14 (Ref. 1), assume that Engineered Safety Feature (ESF) systems are OPERABLE. The DC electrical power system provides normal and emergency DC*electrical power for the DGs, emergency auxiliaries, and control and switching during all MODES bf operation. The OPERABILITY of the DC subsystems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining DC sources OPERABLE during accident conditions in the event of: LCO PBAPS"UN'IT 3 a. An assumed loss of all offsite AC power or all onsite
• AC power; and b. A worst case single failure. The DC sources satisfy Criterion 3 of the NRC Policy Statement. The Unit 3 Division I and Division II DC electrical power subsystems, with each DC subsystem consisting of two 125 V station batteries in series, two battery chargers (one per battery), and the corresponding control equipment and interconnecting cabling supplying power to the associated bus, are required to be OPERABLE to ensure the availability of the required power to shut down the reactor and maintain it in a safe condition after an abnormal operational transient or a postulated OBA. In addition, DC control power (which provides control power for the 4 kV load circuit breakers and the feeder breakers to the 4 kV emergency bus) for two of the four 4 kV emergency buses, as well as control power for two of the diesel generators, is provided by the Unit 2 DC electrical power subsystems. Therefore, Unit 2 Division I and Division II DC electrical power subsystems are also required to be OPERABLE. A Unit 2 {continued) B 3.8-60 Revision No. 0

_ ! .... .: BASES LCO (continued) . APPLICABILITY ACTlONS -_ ***:*' . . -.: -,,. --, -*-** .. . : PBAPS UNIT 3-DC Sources-Operating B 3.8.4 DC electrical power subsystem OPERABILITY requirements are the same as those required for a Unit 3 DC electrical power subsystem, except that the Unit 2: 1} Division I DC electrical power subsystem is allowed to consist of only the 125 V battery A, an associated battery charger, and the corresponding control equipment and interconnecting cabling supplying 125 V power to the associated bus; and 2) Division II DC electrical power subsystem is allowed to consist of only the 125 V battery B, an associated battery charger, and the corresponding control equipment and interconnecting cabling supplying 125 V power to the associated bus. This exception is allowed only if all 250 .VDC loads are removed from the associated bus. In addition, a Unit 2 battery charger can be powered from a Unit 3 AC source, (as described in the Background section of the Bases for Unit 2 LCO 3.8.4, "DC Sources-Operating"}, and be considered OPERABLE for the purposes of meeting this LCO. Thus, loss of any DC electrical power subsystem does not prevent the minimum safety function from being performed. The DC electrical power sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure safe unit operation arid to *ensure that: a ... Acceptable fue.l des1gn .liini ts arid reactor cool arit . pressure boundary limits are not exceeded as a result . . of abnormal operational and . --. . . --b. * .core co.cling is provided, *and containm.ent . integrity and other vi ta 1

• fLmct ions are maintained in th¢ .of a: postulated* DBA. *
• The DC electrical powerr*qµirerilents for MODES 4 and s*are addressed iii LCO :3 .J. 5, *"D.C Shutdown. II --. -. --*-A.1 *. .-. ..:---; -.. *: ' .. -. . .. -. ---; -. --.Pursuant to Leo 3.0.6, *the Distribution ACTIONS*would not.be entered even if the DC electrical power subsystem inoperability resulted. in' de-energization* of an AC . *or oc* Therefore, the Required Actions *of .Conditian A :are:modffied: by a.Note **fo/indicate -that when Condition. A -. .-. . --. * . (continued) . '-,*_ Revision No .. 0; ... J".

BASES ACTIONS --.,.* -PBAPS UNIT 3 * -. A. l (continued} DC Sources-Operating B 3.8.4

• results in de-energization of a Unit 3 4 kV emergency bus or a Unit 2 DC bus, Actions for LCO 3.8.7 must be immediately entered. This allows Condition A to provide requirements for the loss of a Unit 2 DC electrical power subsystem (due to performance of SR 3.8.4.7 or SR 3.8.4.8} without regard to whether a bus is de-energized. LCO 3.8.7 provides the appropriate restriction for a de-energized bus. If one Unit 2 DC electrical power subsystem is inoperable due to performance of SR 3.8.4.7 or SR 3.8.4.8, the remaining DC electrical power subsystems have the capacity to support a safe shutdown and to mitigate an accident In the case of an inoperable Unit 2 DC electrical power subsystem, since a subsequent postulated worst single failure could result in the loss of safety contiriued power operation should not exceed 7 days. The 7 day Completion Time is based upon the Unit 2 Dt power being inoperable due to performance of SR 3.8.4.7 or SR 3.8.4.8. Performance of these two SRs will result in i noperabi l ity. of the Unit 2 DC divisional batteries since these batteries are needed for Unit 3 operation, more time is provided to restore the batteries, if the batteries are inoperable forperformance of required Surveillances, to the.need for*a dual unit shutdown to perform these Surveillances. The Unit 2 DC el ectri cal power subsystems al so do .not pro vi de power to the same type of equipment a.s the Unit .3 DC sources. The Completion Time also takes into account the capacity and of the DC sources. * . B. l . Pursuant 'to LCD 3. b 6":, 'the Di stri b*ut ion .Systems-Operating ACTIONS would *not *be .ente.red even if the -DC electrical power * *** subsystem i noperabil .i ty 'resulted in de.:..energi zat ion of an AC *<Therefore, the Required Actions of-Condition A a.re *. *modifi.ed -by a to indicate that when Condition A results dn .. de-"eriergiZat.ion: oLa Unit 3 4 kV emergency bus, Actions for* lCO. 3.8.7*must be immediately entered.* This allows.* Cond-itioil A *to provide*requirements for the loss of a Unit 2
• DC electrical power subsystem without* regard to whether a . bus is de-energized. LCO 3.8.7 provides the ap.propriate
• restrJction-for a de-eherghed bi.ts.* * * ** * ** (continued) -_B *. Rev.is'ion, No. O **

I I BASES ACTIONS . . . . . PBAPS UNIT 3 :-*-. B.l (continued) DC B 3.8.4 If one of the Unit 2 DC electrical power subsystems is inoperable for reasons other than Condition A, the remaining DC electrical_ power* subsystems have the capacity to support a safe shutdown and to mitigate the accident condition. Since a subsequent worst case single failure could, however, result in a loss of minimum necessary DC electrical subsystems to mitigate a worst case accident, continued power operation should not exceed 12 The 12 hour Completion Time reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power subsystem and takes into consideration the importance of the Unit 2 DC electrical-power subsystem. C.l Condition C represents one Unit 3 division with a loss of ability to completely respond to an event, and a potential loss of ability to remain energized during normal operation. It is therefore imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for complete _loss of DC power. * -If one -of the Unit 3 DC electrical power subsystems is inoperable (e *. inoperable battery/batteries, inoperable required battery charger/chargers, or inoperable required battery charger/chargers and associated battery/batteries), the remaining DC electrical power subsystems have the capacity to support.a safe shutdown and to mitigate an

• Since a subsequent worst case single -failure c-ould result in the loss of minimum necessary-DC* electrical subsystems to mitigate a worst case accident, power Qperation should not exceed 2 hours. The 2 hour-Completion Time is consistent with Regulatory Guide 1.93 4) and reflects_ a reasonable time to assess unit status as a function of the inoperable DC electrical power division and, if the Unit 3 DC electrical power dfvision is not restored to OPERABLE status; to prepare to initiate an orderly and safe unit shutdown. The 2 hour limit is also consistent the allowed time for an inoperable Unit 3 DC tiistribution System division. (continued)* Revision -o -'., .. _
  • .. _ . ,-*' BASES. ACTIONS (continued) SURVEILLANCE REQUIREMENTS. * .. . . PBAPS UN IT 3 DC Sources-Operating B 3.8.4 If the DC electrical power subsystem cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 6) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE ?tatus will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable l*ow-risk state. allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. Condition E corresponds to a level of degradation in the DC *.electrical power subsystems that causes a required safety function to be lost. When more than one DC source is lost, this results .in a loss of a required function, thus the. pl ant i s i n a con d it i on, outs i de the a cc i dent anal y s i s .. Therefore, no additional time is justified for continued* . operation. LCO be entered immediately to . commence a controlled sh.utdown. : . . . As N o t e d a t. t he beg i nn 1 n g o f t h e S Rs , . S R . 3 . 8 . 4 . 1 t h r o u g h 'SR 3.8.4.8 are only to the Unit 3 DC . power subsystems and .SR 3:8.4.9 is applicab.le only to the Unit 2 p6wer . SR 3.8.4.l v*erifying battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of the . *charging *system and the.ability of the b.atteries to perform their iritended furiction. Float charge is the condition i.n which -:the charger .is supplying the continu.ous charge *required to overcome the i nterna*1 losses of a battery (or .. batter'y cell) and maintain the battery (or a ,battery cell)*. 'in a: fully'charged state. :.The voltage requirements are **.*.-" B 3.8-64 Revision, No .. 67 .

BASES SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 SR 3.8.4.1 (continued) DC Sources-Operating B 3.8.4 based on the minimum cell voltage that will maintain a charged cell. This is consistent with the assumptions in the battery sizing calculations. The SR must be performed unless the battery is on equalize charge or has been on equalize charge any time during the previous 1 day. This allows the routine Frequency to be extended until such a time that the SR can be properly performed and meaningful results obtained. The surveillance frequency is applicable and continues the time that the battery is on equalize with the exception that the surveillance does not need to be performed if the battery has been on equalize during the previous 1 day. The additional 1 day allows time for battery. voltage to return to normal after the equalize charge and time to perform the test. The intent of the Note is to allow orderly, yet prompt performance of the surveillance that will produce meaningful results once the equalize charge is complete. The Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.4.2 Visual inspection to detect corrosion of the battery cells and connections or measurement of the resistance of each *inter-cell, inter-rack, inter-tier, and terminal connection, provides an indication of physical damage or abnormal that could potentially degrade battery performance. The battery connection resistance limits are established to maintain connection as low as reasonably possible to minimize the overall voltage drop across the battery, and the possibility of battery damage due to heating of connections. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.4.3 *Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The presence of physical damage or deterioration does not necessarily represent a failure of continued B 3.8-65 Revision No. 87

-! -BASES SURVEILLANCE REQUIREMENTS .. *.-.-.. '* . .--. .. PBAPS UN IT 3.

• 1-.* SR 3.8.4.3 (continued) DC Sources -Operating B 3.8.4 this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.8.4.4 and SR 3.8.4.5 Visual inspection and resistance measurements of inter-cell, inter-rack, inter-tier, and terminal tonnections provides an indication of physical damage or abnormal deterioration that could indicate degraded battery condition. The corrosi.on material is used to help ensure good electrical connections and to terminal deterioration. The visual inspecti6n 'for corrosion is not intended to require removal of and j*nspection under each terminal The rem6val of visible corrosion is a preventive SR .. The presence of visible corrosion does not necessarily represent a failure *of this SR, provided visible corrosio_n .* j s removed during performance o.f this .. survei 11 ance. The batte:ry connection limits a re established to m'aintai*rr'con'nectfo"n resist9nce as low as reasonably possible to minimize the over*an voltage drop across the battery, and battery damage to heating of corinectfons. under the. Su rv'eil ce . Ff".equ*en cy . Control Program . *SR **3.8.4.*6_ .. Battet}. capa*b:il i t.Y_ re qui *a re on the design capacity'.of _the The miniriruril charging capaci}y requi.tement _is based on the c*apacity to maintain* the associa.ted. batter.y *in its .. ful_ly charged* condition*, and (continued) .*,: *, . * .. -** -',,._*.: ... B*J.8-66*-Revision .N(J. 87 . .1

---. BASES SURVEILLANCE REQUIREMENTS -,, ' : ... , _ PBAPS UN IT 3 **--.. -DC -Sources-Operating B 3.8.4 SR 3.8.4.6 (continued) to restore the battery to its fully charged condition following the worst case design discharge while supplying normal steady state loads. The minimum required amperes and duration ensures that these -requirements can be satisfied. The Surveillance Frequency is controlled under the Surveillance Frequency {ontrol Program. SR 3.8.4.7 A battery test is* a special test of the battery's capability,_ as found, to satisfy the design requirements (battery duty cycle) of the DC Electrical Power System. The rate and test length corresponds to the design duty cycle requiremerits. The Surveillance Frequency is controlled under the Frequericy Control Program. This SR is by two Notes. Note 1 allows performance of a modified performance discharge test -performance discharge test (described_ in the-Bases for SR 3;B.4;8) in lieu of a service test provided the-test performed envelops the duty tycle of the battery. This is acceptable becaDse as as the test current is greater than or_equal to the actual duty cycle of the battery, SR 3. 8. 4.8 represerits a more -severe test of capacity than test. I --cont.i nued :'* .*. ."-i ... *. .: .. -*. *_ . ' . *-**. *-,.* -BJ.*8-67 Revi s:Jon No. 87 ,, . BASES SURVEILLANCE REQUIREMENTS . PBAPS UNIT. 3 ' . -.. *. SR 3.8.4.7 {continued) DC B 3.8.4 The reason for Note 2 is that performing the Surveillance would remove a required DC electrical power subsystem from service, perturb the Electrical Distribution*System, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance. SR 3.8.4.8 -A battery performance discharge test is a test of the . constant current capacity of a battery, performed between 3 and30 days after an equalize charge of the battery, to detect any change in the capacity determined by the acceptance test. The test is intended to determine overall battery degradation due to age and usage. A battery modified performance discharge test is a simulated duty cycle consisting of just two rates; the one minute rate published for the battery or the largest current load of the duty cycle, followed by the test rate employed for the performance test, both of which envelope the duty cycle of the service test. *Since the ampere-hours removed by a rated one minute discharge represents a very small portion of the *battery capacity, the test rate can be changed to that for the performance test without compromising the results of the perf ormanc*e discharge test. The battery termi na 1 voltage for-the modified performance discharge test should remain greater.than or equal to the minimum battery terminal voltage specified .in the battery performance discharge test.-A modified performance discharge :test isa test of the battery capacity and its ability to provide a high rate, short duration load {usually the highest rate of the duty cycle}. This wfll often confirm the battery's ability to meet the critical period of the load duty cycle, in addition to determining its percentage of rated capacity. Initial conditions for the performance discharge test should be identical to those specified for a performance discharge test. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.8; however, the discharge test may be . . **(continued) B 3.B-6a. Revision No.' o ,* .* '1.: ,. ,, BASES SU RV EI LLANCE REQUIREMENTS PBAPS UN IT 3*, SR 3.8.4.8 (continued) DC Sources-Operating B 3.8.4 used to satisfy SR 3.8.4.8 while satisfying the requirements of SR 3.8.4.7 at the same time only if the test envelops the duty cycle of the battery. The acceptance criteria for this Surveillance is consistent with IEEE-450 (Ref. 5) and IEEE-485 (Ref. 3). These references recommend that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A capacity of 80% shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. If the battery shows degradation, or if the battery has reached 85% of it.s . expected life and capacity is< lOOl of the manufacturers the Frequency is reduced to 12 months. However, if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity 100% of the manufacturer's rating. Degradation is indicated, according to IEEE-450 (Ref. 5), when the capacity drops by .more than 10% relative to its capacity on the previous performance test or when it is 10% below the manufacturer's rating.* If the rate of discharge varies* significantly from the previous discharge test, the* absolute

• capacity may change significantly, resulting in a
• capacity drop exceed*ing the criteria specified above. This abs6lute battery Change could be. a result of acid concentration iri the plate material, which is not an. =indication of Therefo0e, of tests with .. si grri fi cant rate differences Shaul d be discussed with the vehdor and to if has
• occurred. All Frequencies, with the exception of the 24. morith Frequency, are consistent with th{ recommendations. *in (Ref. 5).* The 24 month Frequency is acceptable,* . given the battery hils shown no signs 6f degradation, the* ** unit c6nditions to perform the test and requirements exi:sti ng to* ensure battery performance during .. *
• these 24 month In addition, the 24 month * * . Frequency is intended to be consistent expected fuel.* cycle *1 engths
• continued
• ':. BASES SURVEILLANCE REQUIREMENTS REFERENCES .PBAPS *UN_IT 3 SR 3.8.4.8 (continued) DC B 3.8.4 This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required DC electrical power subsystem from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy the Surveillance. The DC batteries of the other unit are exempted from this restriction since they are required to be OPERABLE by both units and the Surveillance cannot be performed in the manner required by the Note without resulting in a dual unit shutdown. SR 3.8.4.9 With the *exception of this Surveillance, all other Surveillances of this Specification (SR 3.8.4.l through SR 3.8.4.8) are applied only to the Unit 3 DC electrical power subsystems. This Surveillance is provided to direct that the appropriate Surveillances for the required Unit 2 DC electrical power subsystems are governed by the Unit 2 Technical Specifications. Performance of the applicable Unit 2 Surveillances will satisfy Unit 2 requirements, as well as satisfying this Unit 3 Surveillance Requirement. *The Frequency required by the applicable Unit 2 SR also governs performance of that SR for Unit 3. As Noted, if Unit 2 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note to Unit 2* SR 3.8.5.1 is applicable. This ensures that a Unit 3 SR will not a Unit 2 SR to be performed, when the Unit 2 Technical Specifications exempts performance of a Unit 2 SR. (However, as stated in the Unit 2 SR 3.8.5.1 Note, while performance of the SR is exempted, the SR still must be met.) 1. UFSAR, Chapter 14. 2. "Proposed IEEE Criteria for Class IE Electrical Systems for Nuclear Ppwer Generating Stations," June 1969. 3. IEEE Standard 485, 1983. (continued) B 3.8-70 Revision No. 0 BASES REFERENCES (continued) DC Sources -Operating . B 3.8.4 4. Regulatory Guide 1.93, December 1974. 5. IEEE Standard 450, 1987. 6. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002 . . :-* -. "' .. *! , .* . -,-B .3. 8-71 : No. 67

'* j. : . -'I' 1*._.* ... * ... *, ,. I

• _-: -i-;** -*.: ' . . . . : / .. -.. '* : :; *' ... *, . \'1 *. . . DC Sources-Shutdown B 3.8.5 B 3.B. ELECTRICAL POWER SYSTEMS B 3 .8. 5 DC
• BASES. BACKGROUND* A description of the DC sources is provided in the Bases for LCO 3 .BA, "DC Sources-Operating." APPLICABLE . The initial of Design Basis Accident and SAFETY ANALYSES transient in.the UFSAR, Chapter 14 (Ref. 1), assume .that Engineered Safety Feature systems are OPERABLE. The DC electrjcal power system provides normal and emergency DC power for diesel generators (DGs), emergency auxiliaries, and control and switching during all MODES of ._ '/*, *. * .... ' *' ,.L_Cb/: " ' . . ..... ' -. : ,1
• operatiqn_. *
• The.,OPERABILITY of DC subsystems is consistent with the 'initial assumptions of _the accident analyses and the ... requfr:ements for the* supported systems' OPERABILITY. The OPERABILITY .of the minimum DC *electrical power sources during MODES 4. and 5 iind during inovement of irradiated fuel ass.emb lies .. in secondary containment ensures that: . * *. a. * .. The facility can be. ma i nta*i ned* in* the _shutdown or *
• re:fue l i ng *. condtti on *for* extended pert ads; .
• b. . Suffi.c i enf i i *an* an_d
• cor)iro f capability is . available for monitoring and maintaining the unit, . ; status. and. . . . . . . . * ' .o ** : f\de.quate DC e l power-is provided to mi ti gate . pQstulate(.'.durfng* shutdown,: su:ch as ari ' . . . * * * .. pf or a. fuel. * * *_ ._-_* * .. *-**" * * * ... PoliCy.'." ' . * *. * < '* ,_. * *. *. **. . .*. . . . .*.: . . '-*' .. *--' . ... -. *' . --. . ' . , . The, Uh'it* 3 pc .power*-s*uBsys:feink; eaC:tibC . *' . . sy_bsystem. cori'sfsting,* rif *two: 125 V in * ,_ <*series, two *battery chargers (one per *battery)' ,'.and the " . '*co.rres*pondihg f:::ontrol eqt.itpment. an*d Jnterconneeting *tabliri_g . ';,. supplying .. power. to, the_ass_oc:Jated bus*,, required tp: _be_ \*: *.', * ... -*,. , * .: " ,,-_*.:-, -: ** * -.. * ** ,. *. :-* -.** .*.*-,*_ .. . . ... PBAPS. UNlf. J* .. * * < . ,* _., **'*.*:.:_:*( .. ;._"*.; ;_.**, .. -' . *.** .. _*_.*. . .. ' *,, .... ..-.:.-.* .. _, *.* : -_ *.. ,, . .-.. 5,.3.8"-72. *** .. *, . '* . . : . .. ,[ .. .. *: *:*.*.-

BASES LCO (continued} .APPLICABILITY PBAPS'UNIT 3 .. **.-.. -.. DC Sources-Shutdown B 3.8.5 OPERABLE to support Unit 3 DC distribution subsystems required OPERABLE by LCO 3.8.8, 11Distribution Systems-Shutdown.11* When the equipment required OPERABLE: l} does not require 250 VDC from the DC electrical power subsystem; and 2) does not require 125 VDC from one of the two 125 V batteries of the DC electrical power subsystem, . the Unit 3 DC electrical power subsystem requirements can be modified to only include one 125 V battery (the battery needed to provide power to required equipment), an associated battery charger, and the corresponding control equipment and interconnecting cabling supplying 125 V power *to associated This exception is allowed only if all 250 VDC loads are removed from the associated bus. In addition, DC contr61 power (which provides control power for the 4 kV load circuit breakers and the feeder breakers to the 4 kV emergency bus) for two of the four 4 kV emergency buses, as well as control power for two of the diesel generators, is provided by the Unit 2 DC electrical power subsystems. Therefore, the Unit 2 DC electrical power subsystems needed to support required comptinents are also required to be OPERABLE. The Unit 2 DC electrical power subsystem OPERABILITY requirements are the same as those required for a Unit 3 DC electrical power In addition, battery chargers (Unit 2*and Unit 3) Can be powered from the opposite unit's AC source (as described in the Background section of the Bases-for LCO 3.8.4, 11DC *Sources --:-Operat i ng11), and be considered OPERABLE for the purpose of this LCO. * *This requirement ensures the availabi11ty of s*ufficient DC electrical power sQurces to operate the untt in*a safe mariner to the consequences of postulated events during shutdown (e.g., foel handling qccidents and inadvertent reactor vessel draindown}. * *The DC electrical power sources required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment provide *assu_rance that: a. Required features to provide adequate coolant inventory makeup are available for the irradiated fuel assemblies in the core in case of an inadvertent draindown of the reactor vessel; * (continued) B . Revision No. 0-. .. : ' ' ... -.' ,' * .. -:. *t .**' BASES APPLICABILITY (continued) ACTIONS PBAPS UNIT *3 DC B 3.8.5 b. Required features needed to mitigate a fuel handling accident are available; c. Required features necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and d. Instrumentation and control capability is available for monitori-ng and maintaining the unit in a cold shutdown condition or refueling condition. The DC electrical power requirements for MODES 1, 2, and 3 are covered in LCO 3.8.4.

• LCO 3.0.3 is not applicable while in MODE 4 or 5. However, since irradiated fuel assembly movement can occur in MODE 1, 2, or 3, the AcnoNS have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or-3, the fuel *movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be sufficient reason to require a reactor shutdown. A.I, A.2.1, A.2.2, A.2.3, and A.2.4 If more than one DC distribution subsystem is required according to LCO 3.8.8, the DC electrical power subsystems .* remaining OPERABLE with one or more DC electrical power
• subsystems. may be capable of supporting sufficient required features to a1low continuation of*coRE' ALTERATIONS, fuel movement, and operations with a potential for draining the reactor*vessel.. . . . ' BY allowance of .the optlon to declare required features . inoperable with assodated DC electrical power subsystems . inoperable, appropriate restrictions are implemented in* *accordance with the affected system LCOs' ACTIONS. However, in many instances, this option may involve undesired admi ni strati ve efforts. Therefore,* the a 11 owance for .
• sufficiently conservative actions is made (i.e., to *CORE.ALTERATIONS, movement of irradiated fuel assemblies in **secondary containment, and any.activities that could result in iriadvertent draining of the reactor
• B 3.s.:.74
• Revision No*. o . -

BASES ACTIONS SURVEILLANCE REQUIREMENTS . *PBAPS *UNIT 3 DC B 3.8.5 A.l, A.2.1, A.2.2, A.2.3, and A.2.4 (continued) Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required DC e1ectrical power subsystems and to continue this action until restoration is accomplished in order to provide the necessary DC electrical power to the plant safety systems. The Completion Time of inunediately is consistent with the required times for actions requiring prompt attention. The restoration of the required DC electrical power subsystems should be completed as quickly as possible in order to minimize the time during which the plant safety systems may be without sufficient power. SR 3.8.5.1 SR 3.8.5.1 requires performance of all Surveillances required by SR 3.8.4.1 through SR 3.8.4.8. Therefore, see the corresponding Bases for LCO 3.8.4 for a discussion of each SR., *

• This SR is modified by a Note. The reason for the Note is to preclude requiring the OPERABLE DC electrical power subsystems from being. discharged below their capability to provide the required power.supply or otherwise rendered inoperable during the performance of SRs. It is the intent that these SRs must still be capable of being met, but actual *performance is not required. SR 3.8.5.2 This Surveillance is provided to direct that the appropriate Surveillances for the required Unit 2 DC electrical power subsystems are governed by the Unit 2 Technical Specifications. Performance of the applicable Unit 2 Surveillances will satisfy Unit 2 requirements, as well as satisfying this Unit 3 Surveillance Requirement. The Frequency required by the applicable Unit 2 SR also governs performance of that SR for Unit 3. (continued) B 3.8-75 Revision No. O

. ' .. , , BASES SURVEILLANCE REQUIREMENTS REFERENCES *"* .' .' . --*. -* _.: :' *.::., . **, .. PBAPS UNIT 3" SR 3.8.5.2 (continued) DC B 3.8.5 As Noted, if Unit 2 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note to Unit 2 SR 3.8.5.1 is applicable. This ensures that a Unit 3 SR will not require a Unit 2 SR to be performed, when the Unit 2 Technical Specifications exempts performance of a Unit 2 SR. (However, as stated in the Unit 2 SR 3.8.5.1 Note, while performance of an SR is exempted, the SR still must be met.) l; UFSAR, Chapter 14. *'*. -'.: .. -' -,* * .. .. *. __ .... -*'*:-** * **: * ._, * ., '*.* :B,3.8-76 .**.-. _*:...*_ RevisiOn Q. Battery Cell Parameters B 3.8.6 B 3.8 ELECTRICAL POWER SYSTEMS B 3. 8. 6 Battery Ce 11 Parameters BASES BACKGROUND APPLICABLE SAFETY ANALYSES LCO. . -. APPLICABILITY .*-,. *:,*' This LCO delineates the limits on electrolyte temperature, l_evel, float voltage, and specific gravity for the DC electrical power subsystems batteries. A discussion of these batteries and their OPERABILITY requirements is provided in the Bases for LCO 3.8.4, "DC Operating," and LCO 3.8.5, "DC Sources-Shutdown." conditions of Design Basis Accident (OBA) and transient analyses in UFSAR, Chapter 14 (Ref. 1), assume Engineered Safety Feature systems are OPERABLE. The DC electrical power subsystems provide normal and emergency DC electrical power for the diesel generators (DGs), emergency auxiliaries, and control and switching during all MODES of operation. The OPERABILITY of the DC subsystems is consistent with the

• initial assumptions of the accident analyses and is based upon meeting the design basis of the unit as discussed in the Bases of LCO 3.8.4, ... DC Sources-Operating," and LCO "DC Sources'--Shutdown. -. .--.* . . Since battery cell parameters support the operation of the DC e lectri cal power subsystems, they sfy Criterion 3 of the NRC Policy Statement. -Battery cell parameters must remain withi11_acceptable limits to ensure availabHity-of the required DC power to shut down_ the reactor and: maintain it-i-n a safe condition after an abnorrria:T:o:peratiQnal :transient or a .postulated OBA._ . Electrolyte limits are conservatively esta:_blished, alJowing ** cont i nlied DC e_l ectri cal sYstem function: even with Category A *-and W limits not meL * * * * *
• The' battery <:ell requfred solely for the* support of *the associated DC electrical. power subsystem. *Therefore, these eel l parameters are only. requtred when . the
• DC.powersource*.i's* required to_ b_e OPERABLE. Refer to the Appli:cability discussions in Bases for L_CO 3.8.4 and *
• lC_0_3.8;.5-. * -'.** .. (continued) *. '.-' --. PBAPS 'lJNI*T 3 .. _*. . . ,. 0. .. .BJ.8-77 i . Revi siOn *No. O * .. __ ,_.-,* .:.-..

. ' :-. ***. _.;. I< ... 1. I*. ' .. *.* ,. ! . .. ' . ' Battery Cell Parameters B 3.8.6 * .BASES (continued) ACTIONS ,* ... * .. -. --* : --c . * * * * * ' ... 1, ' * ._. . . .. --., -;.: .. . ' *.,.-. *. PBA'pf mi IT 3 ** * ....

• A.2, and A.3 With parameters of one or more
• ce 11 s in or. more . batteries not within (i.e., Category .A limits* not' met . or Category B limits not met, or Category A and B limits not met) but within the Category C
• l i mi ts. specified . in *. *Tab le. 3. 8. 6-1, the* battery is degraded but there is still sufficient capacity to' perform the intended function. ' ' Therefore, the affected battery is .not to be. considered inoperable solely .as a result of Category A or B limits. not met, *and continued operation is permitted for. a *limited
• The ,:pilot cell electrolyte level and*. float .voltage are* .. requir.ed to be verified to meet the Category C limits:withiJl* . 1 hour'(Required Action *This check provides a quick indication of the status of the remainder of the battery cells. One hour provides* time to inspect.the electrolyte level and to confirm the fl oat voltage of the pilot eel ls. One hour is considered a.reasonable amount of time to
• perform the required verification. ' VerifiCation that the CategorY. C limits are met (Required *Action. pr_ovides assurance that during* the time needed to restqre the parameters to the Category.A and B limits, .. the battery is still: cap ab le of performing .. its intended . A period *of 24 hours ts a 11 owed* to complete the . initial verifltation because. specific gravity measurements**
• must be obtained for each connected t.ell .. *Taking into . ' consideration' both the time required to perform the. required. *. ver.:ification and the* assurance that the *battery*cell
• parameters are*no:t.severely degraded, this time is cons*idered reasonable. The verific_ation :is repeated at .. *.** 7 day'intervals until tbe*parameters are restored to Category-._A or B This periodic verification -is .. consistent with the normal. Frequency of pilot* cell
• Continued. operation is onl.y permitted for 31 days before* battery ce 11 parameters must. be restor*ed *to within . Category A and B limits.. Taking into consideration that, while battery capacity is degraded, sufficient capacity exists to perform the intended function and to allow time to *fully restore the battery cell parameters to normal limits, * . this time is le Jor operation prior to dee la ring. the , .. ; DC batteries inoperable. * * * ** . . . . ' . . *.(continued)**.* *.**.' "'. *' :'. ';* . : . *, **.*. B*' .. "* .* .. ' .. . .. , sfon No .. :. o-. .. *. ' ' ... : -;,.",. *.<** *.* .. '. *'_,., **: *:*

1'"' BASES Battery Cell Parameters B 3.8. 6 ACTIONS JL.J. (continued)* SU RV EI LLANCE REQUIREMENTS PBAPS *UN U 3* . When any battery parameter is outside the Category C limit for any connected eel l, sufficient capacity to supply the maximum expected load requirement is not ensured and the correspondfng DC electrical power subsystem must be declared inoperable. Additionally, other potentially extreme conditions, such as not completing the Required Actions of Condition A within the required Completion Time or average electrolyte temperature of representative cells falling below also are cause for immediately declaring the associated DC electrical power subsystem inoperable. SR 3.8.6.1 This SR verifies that Category A battery cell parameters are consistent with IEEE-450 (Ref. 2), which recommends regular battery inspections including voltagej specific gravity, and electrolyte temperature of pilot cells. The SR must be performed unless the battery is on equalize charge or has *been pn equalize charge any time during the previous 4 days. This allows the routine Frequency to be extended until such a time that the SR can be properly performed and meaningful results obtained. The surveillance frequency is applicable and continues during the time that the battery is on equalize with the exception that the surveillance does not need to be performed if the battery has been on equalize during the previous 4 days. The additional 4 days allows time for battery. parameters to return to normal after the equalize charge (nominally 3 days) and time to perform the test (nominally 1 day). The intent of the Note is to . orderly, yet prompt perfbrmance of the surveillance'that will produce.meaningful results once the etjualize is complete. The Surveillance Frequency is under the Surveillance Ftequency Control Program. "* ' .. SR '3.8.6.2 The ii under the *:1.

• Surveillance Frequency: Contr.ol Program. *In addition, within 2 4 h O U r S O ( a b a t t e r y d i S'C h a r g e < 10 0 V 0 r Wit h i n 2.4 h 0 U r S . *of a battery overtharge > 145 V; the battery must be . demons.trated to meet Category B limits .. Tr:ansients, such as. motor which cause*
• battery voltage to drop to s 100 V, do not constitute: discharge provided the battery terminal voltage and float current return to pre-transient values. This . _ .inspection is also consistent with IEEE-450 (Ref. 2), whi_ch special inspections following a severe discharge .or overcharge, to ensure 'that no* significant.degradation of. t he b a tt e r.y_ 6 cc u r s a s i'l co n s e q u e n c e of. s u c h d i s c h a r g e
• o r , overcharge.
• continued B 3 .. 8-79 Revision No: _87 ::'.

BASES SU RV EI LLANC E REQUIREMENTS (continued) , PBAPS UN IT. 3 SR 3.8.6.3. Battery Cell Parameters B 3.8.6 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Lower than normal temperatures act to inhibit or reduce battery capacity. This SR ensures that the operating temperatures remain within an acceptable operating range. Table 3.8.6-1 This table delineates the limits on electrolyte level, float voltage, and specific gravity for three different The meaning of each category is discussed below. Category A defines the normal parameter limit for each designated pilot cell in each battery. The cells selected as pilot cells are those whose temperature, voltage, and electrolyte specific gravity approximate the state of charge of the entire battery. The Category A limits specified for electrolyte level are based on manufacturer's recommendations and are consistent with the guidance in IEEE-450 (Ref. 2), with the extra % inch allowance above the high water level indication for operating margin to account for and charge effects. In addition to this allowance, footnote a to Table 3.8,6-1 the electrolyte level to be above the specified maximum level during equalizing charge, provided *it is not overflowing. These limits ensure that the plates suffer no damage, and that adequate electron transfer capability is maintained in the event of transient conditions. IEEE-450 (Ref. 2) recommends that electrolyte level readings should be made only after the battery has been at float charge for at least 72 hours. The Category A limit specified for float voltage 2.13 V per cell. This value is based on the recommendation of (Ref. 2), which states that prolonged operation of cells 2.13 V can the life expectancy of cells. The Category A limit specified for specific gravity for each pilot cell is 1.195 (0.020 below the manufacturer's fully continued B 3.8-80 Revision No. 87 f . J I i: . -.... >: '. .. -. . : : "'* .. * .. ,; * .. .I:;-. *:*-**

• i *. , ' ' .* *; --BASES* SURVEILLANCE REQUIREMENTS . ' . . . .:. ,* *.:**. .:: '** :,*.* -** **_.*,, *:-;* .. Table 3.8.6-1 (continued) Battery Cell Parameters B 3.8.6 charged nominal specific gravity or a .battery charging current that had stabilized at a This is characteristic of a charged.cell with capacity; According to IEEE-450 (Ref. 2), the specific gravity readings are based on a temperature* of 77°F (25°C). The specific readings are corrected for actual
• electrolyte and level. For each 3°F (l.67°C) above 77°F (25°C), 1 point (0.001) is added to the reading; 1 point is subtracted for each 3°F below 77°F. The specific gravity of the electrolyte in* a cell increases with a loss of water due to electrolysis or evaporation. Level . correction will be in *accordance with manufacturer's recommendations. *
• Category *a defines the normal parameter limits for each con_ne-cted ce 11.
• The *term "connected ce 11 ". excludes any battery ce 11
• that may* be j umpered out. * *
• Th{Ca:te:gor.Y.B limits specified for electrolyte level and . fl Oiit, *voltage are the* sanie as those specified for Category A and have been discuss.ed above. The Category B l iinit *:: for speiif1c gravity for each connected cell is ** * *. *:> (0.020 below the miinufactu'rer' s* fully charged, * *. nomi*riaJ sp_eci f.i c .gravttyJ :with_ 1:,he average of a Tl ¢onnected cells: _(0.010. below-.the manufacturer's fully .charged, *,nominal gravity). values were developed from ,.. * !llanufacturer's recorrimendatfons. The minimum specific. . -.value
• requfr.ed *fqr ea Ch cell .ensures that the' . .. . . effects of a highly charged or newly instalJ ed .eel l do not mask overa'll. degradation of the battery .. ' '-:-' *:. :* ... ** : * :-* : * ' . '-: ** '\ ...* -* :** '. 1. . ' '_::,:.,,. "'*-'* -.. * . _.-.* . .,. ; c . def i ihe i tmit for' each connected : cei l *. . These . * .. val al t'hough* reduced;,'. prpyi de. that s_u{fici;ent . . *' exi$'ts ,to*, per.form the intended* function and< * . > * .. , . * .. , ': riialntain .( _m'argjj:i:'.*of safe.ty.-_ '.When. .b(ltt-er.Y is * *. . , * *. *. * * *. . * * .. o.uts,t(je C.-li'!JJit., .the ... as'sifrari:ce .*of sufficient. . ..... ** . \::*capacit.)t°descri-becL above. -no**tonger exists;: and: the: battery ... . :*.:' *,must be. declared S * .. **: * * * * * .. : *. . .-. *.* . . . . * *.* rt1'e: .c:11fu1:t spe_<:*1ifed. tor' eve1 * . " the:,:-top ,qf-the p] a_t.es. >a11d not over.flowing )'Jfosi1re .*that the . .. )pla,tes**suffer 110 :a,Qd.'inaint:a1ri _** _, ,_. *. el ectron:transfer* capabiT:ity .<The Category :.c -Allowable*** * * *for.; voltage* is *based)on*JEEE-450 .. (Ref._ 2),: whi *' .* *._ *. ..:* . *-i' *. . ;,. ,. . -. . . ._... . . *-' . . . . -. '\ *_ -::-. *. . .. . . ' . .. . ', --*: *:r. ,**-"". -* .. * * 'CcJnt1nu'ed) * , . ' . . _;_ -* .*,. 3-.8-si:* ** *." ,; .... ><**,.*::*': PBAPS 3 . .. .. -*' .... ':_:_ . .. . :-* .; .. *****'.*-_-;,:*: *,* _: .. .. **.,-*, *-; *,* ... ;* .. ' .. .; .. ***.-. .. I '*:* ...

i . 1 ** **' i I I ". :-* *.*-I :1 :-,' '. *: '*.--* . ** . .;.*. . ' .. _: ,, if'..* ..

• _. ,l ,. *,, ... BASES 'suRVEILLANCE REQUIREMENTS * .* .. '. .* .**' .. ,. .REFERENCES' . -* *.***_._._.'.:" !i' ii II . *Battery Cell Parameters . B 3.8.6 . Tati'ie 3.8.6-1. (continued) ' . . that a cell voltage of 2.07 V or below, under float (lnd not caused by ele'vated temperature of the cen, indicates internal cell problems and may require cell acement. * . 'I Thei Category C limit of average specific 1.190, is bas*ed *on manufacturer's recommendations.
• In addition to limit, it is required that the spedfic gravity for each connected cell must be no less than 0. 020 below the ave'rage of all connected cells. This limit ensures that the a highly.charged or new cell does riot mask overall . deg:radat ion of the battery. . . * * * * . . ,I . ' * . . . ,_ . .to.Table 3*.8.6-l that ap.ply to specific gra:vity *are applicable to Category A, B, and C specific . grayity. Footnote bof Table 3.8.6-1 requires the above correction for electrolyte level and temperature, . *wit.h exception that level correction is not req'uired wheh battery charging .<:t.irrent, while on float charge, is This current-provides,. in an indication of ,c:>V.era 11 battery c<>nd it ion. * . * . * .* . Ii" *. . * .. ii . . ... *. . of speci.fic gravity gradients that are produced . the recharging proce_ss, 'delays .of several days may * * . occ:µr waiting for the specific gravity to.stabilize. *A s,tab*ilized charger .q1rrent .is an .acceptabl.e alternative to c gravity. measurement. 'for determining . the state of charge; of.'the designated pilot cell. Thls phenomenon" is *in lEEE-4SO"(Ref. 2). *Footnote .c .to Table all9ws the float charge* current to be usE;!d as an .alternate :tc;> gravity .for up to 180 days folJowing a battery a Within;JSO days*ea.ch.
• connected *ceJFs .must ;be* measured .to= ..... . . con'.firm* the state" ofchaf.ge. "Following a minor battery . rec}large (such as equali,i.i ng charge that. does . not foll ow a .: * ... deeJ>:d.i'scharge}.speci.ffc:*gravity' gradients are not .. ** ..... , :: :and be within * * * .. . < . , " * -* <: * * * ** * * * * . * * * . . * * : -L * *-.*. **:,_-:* . -.. . :! -*_--' ._ ... : . *n-_".-:-. _,_. *. -chapter.* r 4 .* . ... * .*. _ .. -.;;.
• J" .. Sta*n_9!ird 450, :* 1987 > ** . < . .. -.:. '.":'. .* , .. ,-. ,. ;.'.\ . ' * .. "' .. ** *r -* *;** ** . ,. -c.:.:: -*'* ***.: * ... -'>* . **-* ,:* ., .. * . . .. ** * * * *II *.-*.' * ... PBAPS 'l.JNfT 3 :*. -*.. . * ... *!! .-';. . *:... . . :. **: . -... '"' __
• __ .:. ". .. ' . ':: . oK 'J -... * ',: _* 3 . *. * -RevfsiO'n** No. -,.* --,* .. '... :.-* ,_._ -* *.,-.*. **.-.-,.:**** . --, .. .. ,_: * .

' . <. . ,.** Distribution Systems-Operating B 3.8.7 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.7 Distribution Systems-Operating BASES BACKGROUND .. . ' PBAPS UNIT 3 The onsite Class lEAC and DC electrical power distribution system is divided into redundant and independent AC and DC electrical *power distribution subsystems. . . The primary AC distribution system for Unit 3 consists of four 4 kV emergency buses each having two offsite sources of power as well as an onsite diesel generator (DG) source. Each 4 kV emergency bus is connected to its normal source of power via either emergency auxiliary transformer no. 2 or 3. During a loss of the normal supply of offsite power to*the 4 kV emergency buses, the alternate supply breaker from the alternate supply of offsite power for the 4 kV emergency buses attempts to close. If all offsite sources are unavailable, the onsite *emergency DGs supply power to the 4 kV emergency buses. (However, these supply breakers are not governed by thts _LCD; they are governed by LCD 3.8.1, "AC Sources-Operating".} The secondary plant distribution system for Unit 3 includes 480 VAC load centers El34, E234, E334, and E434. The.re are two* independent 125/250 VDC electrical power distribution subsystems for Unit 3 that support the necessary power for ESF functions. * * .* . . . . .In addition, since some components required by Unit 3

• power through Unit 2 electrical power subsystems, the Unit 2 AC and DC electrical power * -distribution subsystems needed to support the equipment are also addressed in LC0.3.8.7 .. A description of. the Unit 2 AC.and DC Electrical Power Distribution System is prov1 ded in the Bases for Un it 2 LCO 3. 8. 7, "Di stri but ion System-Operating. " . .. lhe.list of required Unit 3 distribution buses is presented in Table B (continued) * *s 3.8-83 Revision No. b *
• 1: . -' I . \

Distribution B 3.8.7 BASES (continued)

• APPLICABLE The ini.tial conditions of Design Basis Accident (OBA) and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 14 (Ref. 1), assume LCD PBAPS UNIT 3 . Engineered Safety Feature (ESF) systems are OPERABLE.. The AC and DC electrical power distribution systems are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to .:ESF systems so that the fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed .in more detai 1 in the Bases for Sect ion 3. 2, Power Distribution Limits; Section 3.5, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) System; and Section 3.6 Containment Systems. The OPEAABILITY of the AC and DC electrical power distribution subsystems is consistent with the initial *assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes . maintaining distribution systems.OPERABLE during accident c.onditions in the event of: a. An assumed loss of all offsite power or all onsite AC electrical power; and A postulated worst case single failure. The AC and DC electrical power distribution system . Criterion 3 of the NRC Policy Statement. The Un.it *3 AC and DC electrical power distribution . subsystems are required to be OPERABLE. The required Unit 3 subsystems listed in .
• Table B 3.8.7-1 ensure the availability. of AC and DC el ectri ca 1 po*wer for the systems required to *Shut down *reactor and maintain it iil a safe condition. after an
• abnormal operational transient or a postulated As* . . stated *in the: Table; each division of the AC and DC .. electrical power distribution systems is a subsystem. *.In*: . add.ition, since some *components required* by Unit 3 *receive* through Unit 2 power. distribution . .. ' *. subsystems (e*.g., _Containment Atmospheric Dilution (CAD) System, Stahdby Gas ireatment (SGT} System, Emergency .* Service Water* *system, -Main Contra 1 Room Emergency Ventilation (MCREV) System, and DC control power for two.of the four 4_,. kV buses, as well as _control power for B-3.8-84 Revision No. O' BASES LCD (continued) ** PBAPS UNIT 3 Distribution Systems-Operating B 3.8.7 two of tbe diesel generators), the Unit 2 AC and DC electrical power distribution subsystems needed to support the required equipment must also be OPERABLE. The Unit 2 electrical power distribution subsystems that may be required are listed in Unit 2 Table B 3.8.7-1. Maintaining the Unit 3 Division I and II and required Unit 2 AC and DC electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor. The Unit 2 and Unit 3 AC electrical power distribution subsystems require the associated buses and electrical circuits to be energized.to their proper voltages. The Unit 2 and Unit 3 DC electrical power distribution su.bsystems require the associated buses to be energized to their proper from either the associated batteries or chargers. However, when a Unit 2 DC electrical power subsystem is only required to have one 125 V battery and associated battery charger to be considered OPERABLE (as described in the LCO section of the Bases for LCO 3.8.4, "DC . the proper voltage to which the associated bus is -required to be energized is lowered from 250 V to 125 V (as read from the associated battery charger). Based on the number of safety significant electrical loads associated with .each electrical power distribution component (i.e., bus, load or distribution panel) listed in Table-B 3.8.7-1, if one or more of the electrical power distribution components within a division (listed in Table 3.8.7-1) becomes inoperable, entry into the appropriate ACTIONS .of LCD 3.8.7 is required. Other electrical power distribution components, such as motor control centers {MCC) distribution panels, which help comprise the AC and DC distribution systems. are not listed in Table B 3.8.7-1. The loss of electrical loads associated with these electrical power distribution components may not result in a complete loss of a redundant safety function necessary to shut down the and maintain it in a safe condition. Therefore, should one or more of these electrical power distribution components become inoperable due to a failure not affecting the.OPERABILITY of an electrical power distribution component listed in Table B 3.8.7-1 (erg., a breaker (continued) B 3.8-85 Revision No. 0

. '* I* I .. : ,,.,* *-. . ;, i .. I . . . . : .. :: ,*,. .) . BASES *Leo ii

• 1l I . I . Distribution Systems-Oper;ating B 3.8.7 II * * * * *. *.*. *
• a. single MCC* fails open),.' the tndividual loads .on .. (continued) . the 1electrical power distribution component would be* inoperable, and the appropriate Conditions and
• Actions of the LCOs governing the individual loads * .. _,. -, *;_*. '*. .. ,.*_.,. be entered. *'If however, one or more of these . el ec:1tl' r.i cal power. di stri but ion components is_ . i iloperab le due to a failure a1so affecting the OPERABILITY of an electrical powe1r distribution component listed. in Table B 3.8.7-1 loss of a 4 kV emergency bus, which results iri de:.. zati on. of all el ectri cal power di but ion . powered from the 4 kV emergency bus), wh1le these electrical distribution components* and individual loads are still . inoperable, the Conditions and Required Actions of t,he. LCO for the individual loads are not required to be ente!red, 'since 1.CO 3.0.6 allows this exception (i.e., .the l oad1s:: .are* i Jloperabl e due to the i noperabi li ty of a support
• governed _by Specification; the 4 kV *. busJ.. . *... . . II * ** . . * . In* transfer switches between redundant safety.* Unit :2.*and Unit 3 AC. and *oc .power distribution *.
• must be This prevents any electrical .**** ' .* .. **. in a*ny power distribution subs_ystem from
• pr()p!,agatrng to the redungant subsystem, wh1 could* cause . . . . . ..
• 4re of: a .. st1bsystem and* a loss of ess.enti a 1 . ** .* * .. *. safe[ty funct.ion(s)..; Jf transfer-. switches are closed,. . . * ... the "electr.ical .power. d1siribution subsystem which is 'not*. . * .bein1g from jts .. it is.being*.** .. 'fr_om ,its'*redundanf electrical. power distribution* .
• subs'jyste111J is . tons i:deted *. ;.noperable *. Th.is applies to: the ate9; electrical .power . .. . .... . d1s;br1but1on . It does not, precfode : .** . . , .1 E .4 kV buses\from ;, being powered , . .. ._ .from* the* same 'offsite-.circuit> * * * * * :*: .. **lh* /': > . ..:.. ,. ' * ** 'APPLftABILIT.Y*; Th.e .. t6 : *. *.* .. ;*.be irf MQDE:S, . .i:,.:.2, and*.3 to ens.ur.e: 't.hat: * , * . ... .. ,* :--< *-_l' : * . **** .. * *.* -. -' ." -., ", * :: * -* * . . ' . -* ........ '" *: '. * * ;.* -. _ y* .'0a. .Ir Acceptable -fue,-design limits *:ant:I' reactor cool ant * . . * ... ,:
• ll pressure imi ts *are exceeded* as a'_ :esul t *. ,-l tr.ans1ents; ... *. . I( .. . ;,* .: .:: .... :--... * . . .. "'.' *. .* ' . . . . . . . **. -* .. :**b\ core-c&oltn'g is' provided., and"'containment .**. .. .. ..... if O.PERABJtITY antl*:other*:Nital fu.nctions:ire maintained:: . . ... ** .. , **.* -.j .***.. **.. . /;, 1: t:;. *!h¢ eve **.a **P, ul *.. , , .* ****.........*.
• n l ..* ... * .. +*[I.:.. .'>*" '.,. *. . : ....... .. * ..*... -***' . .. -.... r*-;, f".' ii* ]f '.". .. * . .. ::*.*'-. ii . *.)

BASES APPLICABILITY (continued) ACTIONS ..--.: ...... .' ** .... < P8AP-S UN IT 3 .-* Distribution Systems-Operating B 3.8.7 Electrical power distribution subsystem requirements for MODES 4 and 5. and other conditions in which AC and DC electrical power distribution subsystems are required, are covered in LCO 3.8.8, "Distribution Systems-Shutdown." Pursuant to LC0'3.0.6, the DC Sources-Operating ACTIONS would not be entered even if the AC electrical power distribution subsystem inoperability resulted in energization of a required battery charger. Therefore, the Required Actions of Condition A are modified by a Note to indtcate that when Condition A results in de-energization of a required Unit 2 battery charger, Actions for LCO 3.8.4 must be immediately entered. This allows Condition A to provide requirements for the loss of a Unit 2 AC electrical power distribution subsystem without regard to whether a battery charger is de-energized. LCO 3.8.4 provides the *appropriate for a de-energized battery charger. If *i::me or more of the required Unit 2 AC electrical power *di stri but ion subsystems-' are inope_rabl e, and a loss of function has not occurred*as described in Condition. F, the remaining AC electrical power distribution subsystems have the capacity to .support a safe shutdown .and to mitigate an* accident condition. . Si nee a subsequent worst case single failure could, however, result in*the loss of certain safety functions,continued poweroperation should not exceed 7 days. The 7 day Compl et i Ti me takes into account the

• tapacity and capability of the remaihing AC elettrical power -di stri buti on subsystems, and is based on the shortest * * . restoration time allowed for the systems affected by the . inoperable electrical power distribution subsystem in the respect.i ve: Speci'ffcatfon . .. B-.l ,Tf one.of the_ Unit 2 DC. electrical. powerdistribution _*subsystems fs inope_rable,.the remaining DC electrical power .. di strlbution subsystems have *the capacity to support a safe* shutdown and to *mitigate an *accident condition. *Since a *subsequent worst case single failure could, however, result .in th'e* loss .of ,safety function, continued power operation*.* . . . ' . . ' '.*,:.*_:***** ' ' ; _., (continued) ..... ;: *.**--_. '**. -B _3.8-87 *Revision No. o * . I I

.BASES ACTIONS PBAPS UNIT 3 B.l (continued) Di stri but ion Systems-Operating B 3.8.7 should not exceed 12 hotirs. The 12 hour Time . reflects a reasonable time to assess unit status as a function of the inoperable DC electrical power distribution subsystem and takes into consideration the importance of the Unit 2 DC electrical power distribution subsystem. C. l::. *With one Unit 3 AC electrical power distribution subsystem inoperable, ttie remaining AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, no single failure; The overall reliability is reduced, however, because a single failure in the power distribution subsystems could result in the minimum* required ESF functions not being supported. Therefore, the Unit 3 AC electri.cal power distribution subsystem must be restored to OPERABLE status within 8 hours. The Condition_ C worst scenario is. one 4 kV emergency bus without AC power (i.e., no offsite power to the 4 kV emergency bus and the associated DG inoperable). In this Conditi.on, the unit is more vulnerable to a complete loss of Unit 3 AC It is, therefore, imperative that the unit operators' attention be focused on minimiiing the potential for 'loss of power to the remaining buses* by stabilizing unit, and on restoring power to the affected bus(es). The 8 hciur time limit before requiring a unit shutdown in this Conqition is acceptable because: a. .*There is a potential for decreased safety if the unit ..

• operators' *attention is diverted from the evaluations and actions necessary to *restore power to the affected bus(es) to the actions associated with taking the unit to shutdown within this time limit. b. The potential for an event in conjunction with a single failure of a redundant component in the
• division with AC power. (The redundant component is verified OPERABLE in accordance-with Specification 5.5 .. 11, "Safety Function Determinatit>n (SFDP).") (continued)* .. . ,, .. . _ .. .._ Revision No.* 0-. ,-:-.

BASES ACTIONS (continued) PBAPS. UN IT* 3 Distribution Systems-Operating B 3.8.7 With one.Unit 3 DC electrical power distribution subsystem the remaining DC electrical power distribution subsystem is capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The reliability is reduced, however, because a single failure in the remaining DC electrical power distribution subsystem could result in the minimum required ESF functions not being supported. Therefore, the Unit 3 DC electrical power distribution subsystem must be restored to OPERABLE status within 2 hours. Condition D represents one Unit 3 electrical power distrjbution subsystem without adequate DC power, potentially with both the battery(s) significantly degraded and the associated charger(s) nonfunctioning. In this situation the plant is significantly more vulnerable to a complete loss of all Unit 3 DC power. It is, therefore, imperative that the operatot's attention focus on continued . . 8 3.8-89 si on No. *86 :. *' BASES ACTIONS . 0NIT 3 lL.J. (continued) Distribution Systems-Operating B 3.8.7 stabilizing the plant, minimizing the potential for loss of power to the remaining electrical power distribution subsystem, and restoring power to the affected electrical power distribution subsystem. This 2 hour limit is more conservative than Completion Times allowed for the majority of that would be without power. Taking exception to LCO 3.0.2 for components without adequate DC power, which would have Required Action Completion Times shorter than 2 hours, is acceptable because of: a. The potential for decreased safety when requiring a chahge in plant* conditions (i.e.,* requiring a shutdown) while not allowing stable operations to continue; b. The potential for decreased safety when requiring entry into numerous applicable Conditions and Required Actions for components without DC power, while not providing sufficient time for the operators to perform the necessary eva1uations and actions for restoring power to the affected subsystem; ' '* c. The potential for an event in conjunction with a : single failure of a redundant component. The Completion Time for DC electrical power distribution subsystems is consistent with Regulatory Guide 1.93 (Ref. 2). continued B 3 .. B-90 Revision No. 86 ' ' BASES ACTIONS (continued) SURVEILLANCE . REQUIREMENTS . -:-'. -.-: -;' -_::.-. PBAPS. UN IT >3 _.-.. Di stri buti on Systems-Operating B 3.8.7 If the inoperable electrical power distribution subsystem cannot be restored to OPERABLE status within the associated Time, the unit must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the ri.sk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short .. However, voluntary entry intb MODE 4 may be made as it is also an acceptable low-risk state. allowed Completion Time is reasonable, based on experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging systems. Condition F corresponds to a level of degradation in the electrical power system that causes a required safety function to be When more than one Condition is entered, and in the loss of a function, the plant is in a condition the accident analysis; Therefore; no additional time is justified for continued operat i orJ.

• Leo 3 :O. 3 m"ust be entered i mmedi at el y to shutdowri .. i, :* --SR 3. ... . -::,; ; . , -. . -.. ' .,-' *. *!. ' :: ... * ' *:, .. '* . , .... ,*
• B .3. 8-91
• Revi s*i on No. 86.

i I I i I BASES SURVEILLANCE REQUIREMENTS REFERENCES PBAPS UNIT r SR 3.8.7.1 *(continued) Di st ri but ion Systems -Operating B 3.8.7 that the power is readily available for motive as well as control functions for critical system connected to these buses. This may be performed by verification of absence of low voltage alarms. The Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Chapter 14. ' . . 2.

• Guide 1.93, December 1974. 3 . N ED C -3 2 98 8 -A , Rev i s i o n 2 , Te c h n i c a l J u s t if i ca t i o n t o Risk-Ihformed Modification to Selected Required *End States for BWR Plants, December 2002. . *** .... * .... ,": *, *:**' : :: _ .. *: B 3.8-92 TYPE AC b.uses .DC buses Distribution B 3.8.7 Table B 3.8.7-1 (page 1 of 1) AC andDC Electrical Power Distribution Systems VOLTAGE 4160 v 480 v 250 v DIVISION I* Emergency Buses El3, E33 load-Centers El34, E334 DIVISION I I* Emergency Buses E23, E43 Load Centers E234, E434 Distribution Panel Distribution Panel 3AD18 3BD18 * -Each division of the AC .and DC electrical power distribution systems is a subsystem. P:BAPS UNIT 3 B 3.8-93 _ Revi sioli No. O* -' -*.:" .. .. .: _-*,,:

_ ... *.: _, Distribution B 3.8.8 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.8 Distribution BASES BACKGROUND A description of the AC and DC electrical power distribution is provided in the Bases for LCO 3.8.7, "Distribution Systems-:-Operat i ng. 11 APPLICABLE The 1nitial conditions of Design Accident and SAFETY ANALYSES transient analyses in the UFSAR, Chapter 14 (Ref. assume Engineered Safety Feature (ESF) systems are OPERABLE. The AC and DC electrical power distribution systems are designed to sufficient capacity, capability, redu.ndancy, and

• reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System, anq PBAPS. UN IT 3 containment limits are not The OPERABILITY of the AC and DC electrical power . distribution system is consistent with the initial assumptions of the accident analyses and the requirements . for the supported systems' OPERABILITY. * . . . . . The QPERABILITY of the minimum AC and DC electrical *power .* stiurces and associated power distr1bution subsystems during MODES 4. and 5 and during movement of irradiated fuel . *
• assemblies in the secondary containment ensures that: a. The facility cin be maintained in the shutdown or :.refueling condition for extended periods; * *. 'b ..
• Sufficient and control aVailable for and maintaihjng the unit c. status; and * * * * * . . .* *. . ' . Adequate power to mitigate events
• postulated during shutdown, such as an inadvertent drai ridown of the vessel or a fuel handling ...... The AC and DC electrical power distribution systems satisfY
• Criteripn 3 of the NRC Policy Statement. .(continued). .B 3. 8_;94
• Revision No ... o *. '*'

... ,.* I ' ** '

• Distribution B 3.8.8 BASES (continued) LCD Various combinations of subsystems, equipment, and components are required OPERABLE by other LCOs, depending on the specific plant condition. Implicit in those requirements is the required OPERABILITY of necessary support required features. This LCO explicitly requires energization of the portions of the Unit 3 electrical distribution system necessary to support OPERABILITY of Technical Specifications required systems, equipment, and specifically addressed by their own LCO, and, implicitly required by the definition of OPERABILITY. APPLICABILITY PBAPS UNIT 3 In addition some components that may be required by Unit 3
• receive power through Unit 2 electrical power distribution subsystems (e.g., *standby Gas Treatment System, Main Control Room Emergency Ventilation System, and DC control power for two of the four 4 kV emergency buses, as well as control power for two of the diesel generators). Therefore, Unit 2 AC and DC electrical power distribution subsystems needed to support the required equipment must also be OPERABLE. *In addition, it is acceptable for required buses to be cross-tied during shutdown conditions, permitting a single source to supply multiple redundant buses, provided the source is capable of maintaining proper frequency (if required) and voltage. Maintaining these portions of the distribution system energized ensures the availability of sufficient power to operate the plant in a safe manner to mitigate the of postulated events during shutdown (e.g., fuel handling accidents and inadvertent reactor vessel drafndown). The AC and DC electrical power distribution subsystems required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment provide assurance that: a.
• Systems to provide adequate coo 1 ant inventory makeup are available for the irradiated fuel in the core in case of an inadvertent draindown*of the reactor *. vessel; b. . Systems needed to mitigate a fuel handling accident are available; (continued) B 3.8-95 Revision No. 0 BASES APP LI CAB IL ITV (cont i n*ued) ACTIONS **-_':: :*--. * .. :. . ' PBAPS UNIT 3 .
• Distribution B 3.8.8 c. Systems necessary to mitigate the effects of events . that can lead to core damage during shutdown are *.available; and d. *Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition. The AC and DC electrical power distribution subsystem requirements for MODES 1, 2, and 3 are covered in LCO 3.8.7. LCO is not applicable while in MODE 4 or 5. However, since.irradiated fuel assembly movement can occur in MODE* 1, 2, or 3, the ACTIONS have been modified by a Note stating that' LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE.4 or 5, LCO 3.0.3 would not specify any action. If moving itradiated fuel assemblies while in MODr:1, 2, or the fuel movement is independent of reactor operations. *Therefore, in either case, inability to suspend movemeht of irradiated fuel assemblies would n6t be reason to a reactor shu{down . . A .. l, A.2.1, A.2.2.* *A.2.3, A.2.4, and. A.2.5 Although redundant r.equfred features may require redundant electrical power di stri but1on subsystems to. be OPERABLE,* one OPERABLE distribution_ s*ubsystem may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS, fuel movement, and operations-* with a potential for draining the reactor *v.esseL . By allowing the* option to -declare requfred :features inoperable wfth: associated. -* * . electriC:al power distribution subsystems inoperable, apprripri ate restrict,; ans::* are imp 1 emented in 'accordance with . the .affec:ted di.stripution subsystem LCO's Required Actii:>ns .. 0However, in i this option may i nvo 1 ve undesired adminlstrative'*.*efforts .. Therefore;. the allowance for* *, .:suff.fr-ieritly.cons_ervitive actions fs made, (i-.. to suspend .*.. CORE AL TE RATIONS, niovement of lrrad i ated fl.le l assemblies . in the.secbndary'containment, and any activities that could. ' result-ir:i inadvertent draining of the. reactor vessel). ' . -.. . -. _*.,,.: . ... -_ ,, *.* .. : (continued) *.* ' . --.,: ,,. . -.: ' . '. *.* .. Revisi6h ' I *I BASES ACTIONS SURVEILLANCE REQUIREMENTS R E FE R E.N C E S PBAPS UN IT 3* Distribution Systems-Shutdown B 3.8.8 A.l. *A.2.1. A.2.2. A.2.3. A.2.4. and A.2.5 (continued) Suspension of.these activities shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of events. It is further required to immediately initfate action to restore the required AC and DC electrical .power distribution subsystems and to continue this action until restoration is accomplished in order to provide the power to the plant systems. . . performance of the above conservative Required Actions, a required residual heat removal-shuidown (RHR-SDC) subsystem may be inciperable. In this case, Required Actions A.2.1 through A.2.4 do not adequately address the relating to coolant circulation and heat removal. Pursuant to LCO 3. O. 6 *. the RHR-SDC ACTIONS would not be entered. Therefore, Required Action A.2.5 is provided tG direct declaring RHR-SDC inoperable, which in taking the appropriate RHR-SDC 'ACTIONS. The Time of immediately *is with.the times requiring prompt. attention. The restoration of the electrtcal power distribution subsystems should be completed as quickly possible in order!to minimize the time the plant safety systems may be without power. **:. .. SR 3::8.s.i
• that the AC and DC electrical power.;di:strfoution j_s* functioning *prop,erly,.with the. buses *The 'verification of .1ndicated power *avail l ity on the* bus*es ensures. that the requi re*d power is readily:available for motive as well as confrol functio.ns for crUJca l system loads' connected to these .buses. This m*a.Y be* pe'r:formeq by "veri fi c:at ion .of absence of low_ voltage al arins. , The Surveill a nee *Frequency is con\ rolled under the. *-1 Sur:ve*iHance Frequency Control Program.'. * * * *.' : " . L
• U,FSAR,.Chapter 14.* "': i' *B 3;S-97 Rev i s-.1*on . No. 8 7 -_1 '

,* .. *. * .. *. : i, ... *: *.*

• I,'*. . -**. *". '* ._ ..... ..... *:**1 -:_ -. <-.. *.11 . *il. '.I "11 . 11 " ,, II II " Refueling Eq4ipment B 3.9.1
• B 3. 9 REFUELING OPERATIONS II . ... B 3.9.1 Refueling Eq'uipment Interlocks. . I BASES BACKGROUND * .. ,' .\I ,, *I'
• Refµel i ng e.qui pment inter.locks, restr.i ct the operation of the equipment or the withdrawal of control rods to* rei unit procedure.s th.at prevent the reactor from . achieving criticality dtfririg refueling: The refueling Circuitry senses the conditions of the refueling _.equ1pmerit and the control rods. Depending* on the sensed ; interlocks are actuated to prevent the of the refueling *equipment or the withdrawal of control .. -** *
• Ii ii
• criteria requ_i re that one of the two required* coritrol systems be capable of holding the Jreattor core subcri ti cal under cold cohd it ions (Ref. I). The::1control when fully inserted, serve as the system of maintairiing the reactor subcritical in cold . co.nd it ions during *a 11 fuel movement activities and . acd'.dents. . * * * * * * * * * : * * * .
• One of instrumentation is to sen.se the posi1[t.ion of the in.g .platform,. the loading of the. platform fuel.grapple and the full insertion of .. . all :control rods. Additionally, inputs provided for the load'.,ing of the.*refueling-plalform framemouhted*auxiliary . . hoisit and the loading* of the refueling platform monorail.* .. :" ( .. * .. **:-_ .. .** .. . . mounted hoist.
• With the reactor mode switch in .. the shutdown or:*refuel ing position,. the indicated conditions are combined in, logic circuits to determine if all restrictfons on ** .*. . . 1ng equipment and *cohtrol* ro*d insertion are ., . . : . :_ ' *1 : . ,* . . .. . **.' ..*. :*,::" .. *.,**._** . * *.**. * * . .* . * . . . * . . . ii **A co'htrol rod not at its fiJll-.in position interrupts power .to refueling and operating the.
• _:.* equipment* over core when.loaded with B fuel 'assembly. Conversely, the refueling equipment located over the iore arid loaded with ftiel inserts a control rod
• block in ihe Reactor Manual Control System to prev6nt withdrawing a control rod.* * . i ' ' ' .. , ii * (continued) . .. _. '* . ** *1 . *. . . . ,. *, . .. *-. /:Revision* No. ,29 .:.' : '*. : ' ** ..... -** . . . *--.-: ... ,_, ... : .. *,_. .. _ ,_ ,_., __ .* .. .;* .. :-..-.**._

BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES :-PBAPS UNIT .. *3 Refueling Equipment Interlocks B 3.9.1 The refueling platform has two mechanical switches that open before the platform or any of its hoists are physically located over the reactor vessel. All refueling hoists have switches that open when the hoists are loaded with fuel. interlocks use these indications to prevent operation of the refueling equipment with fuel loaded over the core whenever any control rod is withdrawn, or to

• prevent control rod withdrawal whenever fuel loaded refueling equipment is over the core (Ref. 2). The hoist switches open at a load 11ghter than the weight of a single fuel assembly in water. The'.refueling interlocks are explicitly assumed in the UFSAR analyses for the control rod removal error during refueling . (Ref. 3) and the fuel assembly insertion error during
• refueling (Ref. 4). These analyses evaluate the consequences of control rod withdrawal during refueling and also fuel assembly insertion with a control rod withdrawn. A prompt reactivity excursion during refueling could. potentially result in fuel failure with subsequent of radioactive material to the environment. Criticality and, subsequent prompt reactivity* are prevented during the insertion of fuel,* *. provided all control rods are fully inserted duririg the* fuel
• i nse.rt ion. The refuel iilg interlocks accomp l i sh. *this by *
• loading of fuel into the core with any control
• rod *Withdrawn or. by preventing withdrawal of a rod from the core.during fuel The refueling platform location switches. activate at a point. ' ,, outsidE? of the reactor core such that, with a fuel' as'sembly*
• loaded and tontrol rod the fuel is not core. ng equipment i riterl ocks satisfy Cri-teri on 3 of the NRC Policy Statement. (continued) .. ..... ,:'

. . ,. : '.-* ' .. . , ... * "';. ( ...

• lf II II -i'I_ Refueling Equipment Interlocks B 3.9.1 BASES * (continued) I; LCO ii ii . To prevent criticality refueling, the refualing . int¢rlocks ensure that fuel assemblies are.not loaded with any:! control rod withdrawn. !i II . ' . To these conditions from developing, the the refueling platform position, the refueling fuel grapple fuel loaded, t.he refueling platform frame mounted auxiljary hoist fuel loaded, and the refueling platform monorail mounted hoist fuel loaded inputs are reqyired to* be OPERABLE. These inputs are combined in logic* cirquits, which provide refueling equipment or control rod to prevent operations that could result in
• refueling . !! . , . ,I :r APPLICABilITY In MODE 5, a prompt reattivity excursion could fuel
• and subsequerit release of radioactive material to the The refueling equipment interlocks protect against.prompt reactivity during MODE 5. The interlocks are required to be.OPERABLE during in-vessel fuel . ACTIONS*.*** 1. *-.. -* . PBAPS -UNIT 3 .* -. . : . ' ."'* . with refueling associated with the .. .
• In MODES 1, 2, 3, and 4, the reactor pressure vessel head is *on, ;:and in...:vessel fuel movements are not possible. Theriefore, the refualing interlocks are n6t required to be in these MODES. '* ii A.111* ... WitW one or more 6f the required refueling equipment lnoperable; the unit must be in a condition in which the LCO does not apply. In-vessel fuel wfth the affected refueling equipment must be .. This action ensures that . are performed.with equipment that would potentially' not be blocked from unacceptable operations (e.g., loading fuel intd a cell with a control rod withdrawn). Suspension of *fuel movement shall not preclude completion of of a component to a safe position. -1: \!. (continued) 11 II .::1 lf * ;. -. .. II . B 3. 9-3 Revision No. 29 I* I I * .. *,_ .. _* . . . . . ! .... ,* .*:: BASES (continued) SU RV EI LLANCE REQUIREMENTS REFERENCES PBAPS UN IT 3 SR 3.9.1.1 Refueling Equipment Interlocks B 3.9.l Performance of a CHANNEL FUNCTIONAL TEST demonstrates each required refueling equipment interlock will function properly when a simulated or actual signal indicative of a required condition is injected into the logic. The CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping, or total channel. steps so that the entire channel is tested. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. L UFSAR, Sections 1.5.1.1, 1.5.1.8.1, 1.5.2.2.7, 1. 5 *, 2 . 7 . 1. 2. :U FSAR, Section 7. 6. 3. 3. . . UFSAR, Section 14.5;3.3 . 4. . UFSAR, Section 14.5.3.4 . . *.* . --. ----*:*-. -. *:* .* . . *. *. :* ... . _ ...... : " *. . -.. _ . . . ---::,;:. ,-__ ' .'* .. *r * .. , .. '*:* .** --,* . and ,--.. B '3: 9 4
• Revision.No .. s7* '. **:, '

Refuel Position One-Rod-Out Interlock B 3.9.2 B 3. 9 REFUELING OPERATIONS .* B 3.9.2 Refuel Position One-Rod-Out Interlock BASES APPLICABLE .... SAFETY.ANALYSES PBAPS UNIT 3 * *

• The'refuel position one-rod-out interlock restricts the movement of control rods to reinforce unit procedures that prevent the reactor from becoming critical during refueling operations .. During refueling operations, no more than one rod is permitted to be withdrawn. The .UFSAR design criteria require that one of the two required independent reactivity control systems be capable of holding the reactor core. subcritical under cold conditions (Ref. 1). The control rods serve as the system capable of maintaining the reactor subcritical in cold conditioris.
• position one-rod-out interlock prevents the rif a second ccintrol rod for movement when any other control rod is not fully inserted (Ref. 2). It is a logic circuit that has redundant channels. It uses the rods-in signal (from the control rod ful 1-in position indlcators discussed in LCO 3.9.4, "Control Rod Position Ihdfration11) and a rod selection signal (from the Reactor *Manual Control System).
• This: Specification ensu.res that the performance of the refuel position one-rod:..out interlock event of a Design Basis Accident meets the *assumptions used in the safety analysis of Reference 3. *
• The re.fueling position one-rod-out interl otk is explicitly assumed. in the UFSAR an_alysis for the control rod withdrawal er_ror* durin.g in*g* (Ref. 3*). This .analysis evaluates the i:onsequences of rod withdrawal during refueling. )\.prompt reactivity* excursion during refueling could.** ** potentially result-in fuel failure with, subsequent release ' Of material tn the environment. * * .. Tne'*crefuel position* and (LCO.<LLI, 11SHUTDOWN*MARGIN (SDM)11.) preyerit criticality by preventing withdrawal of more than one control rod. With one c:ontrol -rod."'ithdrawn, the core will remain' subcritical, thereby* preventing any: prompt critical. excursion. . . . . . -. --*--'.' ' *-*.* <Continued) B 3. 9:...5 . *:* . *:* .. ,

I . . . ' I ' ... )-.-. '._._ ... *: ...... . . ,.---; ,-'* . :-* .. .. BASES

• APPLICABLE SAFETY ANALYSES {tontinu.ed) .Leo* APPLICABILITY. ,., . -ACTIONS* . -* .. ,.", -... *,* . '.**.-:_." . : .. -,,:-:. _..: .. .. " Refuel PositiOn One-Rod-Out Interlock* B 3.9.2 Ii ,i *:1 . J. The ilrefuel position one-rod-out interlock *satisfies Cri,erion 3 of the NRC Pol icy Statement ... * " II TQ criticality during MODE 5., the refuel position interlock ensures no more than one control rod may iibe withdrawn. Both channe 1 s of the refue 1 pps i ti on * -one..'..rod-out interlock are required .to be* OPERABLE, and the reactor mode switch must be locked in the Refuel position to the OPERABILITY of these channels .. * * " II I. In-MODE 5, with the reactor mode switch in t.he refuel . _ posi!',tion, the OPERABLE refuel position one-rod-out interlod{_
• proYi'.ides protection against. prompt reactivity excursions. . 1, 2, 3, and 4, refuel position 'inte.rlock is not *required to be OPERABLE and *is bypassed. In* MPDES 1 and 2; the Reactor Protection System * -. . * *. 3.3.Ll) and the control rods (LCO 3.1.3) provide
• miti'gation of potential reactivity excursions. *In MODES 3 and *4, with the reactor mode switch in the shutdown posi:tion, a control rod block (Leo* 3.3.2.1) ens.ures .all -cont'ro 1 . rods are 'inserted, thereby preventing cri ti ca 1 i ty* auri hg shutdown conditions. . . . . . . . -'
• 1. ' * . *' * ...... 1 ..... " ** .... -:k __ nd=-*---A ...... =2 , ... ---Wi thj( one -or chann:-1 s of the refue 1 i ng .* on --* interlock the refuel1ng interlocks may *not be capable of preventing more than one rod* fro*m!! being withdrawn. This condition may lead to cri t;i tali ty. *
• IL _. . ], . . . ,, -* ._ *. . . . *Control rod withdrawal must be immediately suspended, and*. acti9n must be immediately initiated to fully insert all contrtil.rods iri core cells more. Action .. contintie'until.all such** -control rods are fully inserted. Control rods in core cells tio fuel assemblies do not affect the reactivity of core and, therefore*, do not have to be inserted. .; ':: I , .. * *:1 . !I -:: . :: . .... (continued)*
• B 3.9-6 , ... Revi No*.* o ** *,, ..... . . ;:* .. , .. -.,-** .... _ .* :*.*,: . *1: .. : .. *
• 1 -* : . ' * . . ... , **;* ... *** **, JI -. ,

. :-* Refuel Position One-Rod-Out Interlock B 3.9.2 BASES (continued) SURVEILLANCE REQUIREMENTS . REFERENCES . -' -.... -PBAPS *uN H 3*, SR '3.9.2.1 Proper functioning of the refueling position one-rod-out requires the reactor mode switch to be in Refuel; During control rod withdrawal in MODE 5, improper positioning of the reactor mode switch could, in some instances, allow improper bypassing of required interlocks. Therefore, this Surveillance imposes an additional level* of assurance that the refueling position one-rod-out interlock will be OPERABLE when required. By "locking" th.e reactor mode switch in the proper position Ci .e., removing the reactor mode switch key from the console while the reactor mode switch is positioned in refuel), an additional administrative control is in place to preclude operator errors from resulting in unanalyzed operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3.9.2.2 Performance of a CHANNEL FUNCTIONAL TEST on each channel demonstrates the associated refuel position will function properly when a simulated or signal indicative of a required condition is injected into the l6gjc. The CHANNEL FUNCTIONAL TEST may be performed by any*series of sequential, overlapping, or total channel so that is tested. The. is controlled under the Control T6 perform the the must be entered {i.e., a control rod must be withdrawn from .i.ts full-in position). * * . . *Therefore, SR 3.9::2.2 has been .modified by .a Note that . TEST required to be performed until 1 hour after any control rod is withdrawn-:'. UFSAR, .. . .. *-*-:**: 1. *section 1. 5. 2. UFSAR, Section 7.6, 3. . UFSAR, Section 14.5.3.3 . . . . B 3.9-7 Revision No .. 87.* -1 i. Control Rod Position B 3.9.3 B 3.9 REFUELING OPERATIONS B 3.9.3 Control Rod Position BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT 3 Control rods provide the capability to maintain the reactor subcritical under all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the Reactor Manual Control System. During refueling, movement of control rods is limited by the refueling interlocks (LCO 3.9.1 and LCO 3.9.2) or the control rod block with the reactor mode switch in the shutdown position (LCO 3.3.2.1). UFSAR design criteria require that one of the two required independent reactivity control systems be capable of holding the reactor core subcritical under cold conditions (Ref. 1). The control rods serve as the system capable of maintaining the reactor subcritical in cold conditions. The refueling interlocks allow a single control rod to be withdrawn at any time unless fuel is being loaded into the core. To preclude loading fuel assemblies into the core control rod withdrawn, all control rods must be fully inserted. This prevents the reactor from achieving criticality during refueling operations. Prevention and mitigation of prompt reactivity excursions during refueling are provided by the refueling interlocks (LCO 3.9.1 and LC0*3.9.2), the SOM (LCO 3.1.1), the wide range neutron monitor period-short scram (LCO 3.3.1.1), and the control rod block instrumentation (LCO 3.3.2.1). The safety analysis for the control rod withdrawal error during refueling in the UFSAR (Ref. 2) assumes the . functioning of the refueling interlocks and adequate SDM. The analysis for the fuel assembly insertion error (Ref. 3) assumes all control rods are fully inserted.* Thus, prior to fuel all control rods must be fully inserted to

• minim.ize the probability of an inadvertent criticality. Control rod position satisfies Criterion 3 of the NRC Pol icy Statement. (continued) B 3.9-8 Revision No .. 17 Control Rod Position B 3.9.3 BASES (continued) LCO All control rods must be fully inserted during applicable refueling -conditions to minimiie the probability of an inadvertent criticality during refueling. APPLICABILITY ACTIONS s*uRVEI LLANCE .. REQUIREMENTS ., :** *-._,-. ' .. -.-.-. -. *-,:._-*. --. PBAPS UNIT 3 '} Dur i n 'g M 0 DE 5 , l o_ ad i n g f u e 1 i n to core c e 1 l s w i th cont r o l rods withdrawn may result in-inadvertent criticality. Therefore, the control rods must be inserted before loading fuel into a core cell. All control rods must be inserted before loading fuel to ensure that a fuel loading error does not result in loading fuel into a core cell with the control rod withdrawn. In MOPES 2, 3, and 4, the reactor pressure vessel head is on, ind no fuel loading activities are possible. Therefore, this Specification is not applicable in these MODES. Wi_th all .control rods not-fully inserted during the applicable conditions_, an inadvertent criticality could occur that. is not analyzed .in the UFSAR. All fuel loadi_ng operations must be immediately sus*pended. -Suspension of th*ese1'activities shall -not preclude completion of movement cif-a a safe ' *, . D u rtn g ref u e 1 i n g ,: t o e ri s u r e t h at t he r e a -cto r rem a i n s subcritical, all control 'rods must be fully irrserted prior to*>and durihg :fuel. ioa'ding. *Periodi_c checks of the control rod pos'if1on:erisure 'this"conditio-ri" is maintained . . , . ' --. . ----* The lJ ance: Fre'quency is controlled. under the -* Surve-i l1 a*nte Treque_n_cy Gortrol Program: . :-* ' .. \ i. UFSAR*,-Section *i, 5. ' -. -. UFS,AR, Section '14_. 5. 3.3. --.-2. . -;.*, , .. **. _ .. ,_* ,*,: ' . *-,,;,_, '-.* *, __ B :3.9-9 : Revision No. 87 -1 I-. Control Rod Position Indication B 3.9.4 B 3.9 REFUELING OPERA1IONS B Control Rod Position Indication BASES BACKGROUN.D APPLICABLE
• SAFETY ANALYSES ', *. ' . . .. -*. -; ---. ' . ' The full-in position indication for each control rod provides necessary information to the refueling interlocks to prevent inadvertent criticalities during refueling .. During refueling, the refueling interlocks (LCO .3.9.1 and LCO 3.9.2) use the full-in position indication to limit the operation of refueling equipment and 1::he movement of the control rods. The absence of the full....:in position indication signal for any control rod remoVes the all-rods-in permissive for the refueling equipment interlotks and prevents fuel loading. Also, this cond{tion causes the refuel position one-rod-out interlock to no.t allow the withdrawal of any other control rod. UFSAR design require that one of the two required reactivity control systems be capable of holding* the reactor core subcritical under cold conditions {Ref. l). The c'ontrol rods serve as: the system capable of maintaining the *r*eactor subcri ti cal in cold cond jt ions.
• Prevention and mitigation* of *prompt reactivity excurs'i ons d'uring refueling are provided by the refueling interlocks *. {LCO and LCO the SOM (LCO 3.1.1), the wide neutron monitor periOd-short scram {LCO 3.3.1.1), .and. the c;onfrol rod block instrumentation {LCO 3.3.2.1) . . The s,,afetY.analysis the control. rod wit,hdrawal error durin'g. refueling {Ref.* :2) assumes the functioning of the refueltng interlocks and adequate SOM. *The analysis for the fuel 1;assemb ly ir:i_sertioo: ;error {Ref. 3) assumes all control rods' !are:fullyJnserted.':The full-in* position indication ts*
• requi'.:red.to *be' OPERABLE* so. that the refueli.ng interlocks can *ensur:e' that fuel cannot be: loaded with ariy control rod * .. w_ithdr.awn* and that f1'o more them one control rod can be *.*
• withq,rawr1 *at. a ti eontrol *rqd posltion: indi.tatfon satisfies Criterion 3 *of thlr *. NRC Polity *statement*. ' * ** . . . . . ' . -(continued) .. ':.-**,. _ ... *.,.: ' .,'. ..... .. -* No. n .* ,, *<

" Ii Contrtil Rod Position ** B 3.9.4 BASES (continued} . II II

• i-) ' . I; 1 i .* :--. '*,. '.* .. I i 1, .... ,. *' LCD APPLICABILITY ACTIONS *:-**.** '**.* .* PBARS. :uN IT 3 *' **'(/ ,._ .. ,, **:._, ____ . !! . I!, *. . Each1i control rod full ..,in position indication must be OPER!\BLE to provide the required input to the refueling i.nte'rlocks. A full-in position indication.is OPERABLE it correct position indication to' the refueling . irite.rlock logic. * '* :, . Duri'.tlg MODE 5, the control rods must have OPERABLE full-in ion . cation to ensure the app li c;*ab 1 e refuel i ng interlocks wi 11 be . OPERABLE. . . . . . .. . . . . . . '!. *ln. M'i:>DES 1 and 2, requirements* for control rod position *q,re in LCO "Control Rod OPERABILITY."
• ln
• MODES 3-and 4, with'the reactor mode switch in the shutdown posftion, a control rod block (LCO 3.3.2.1} ensures all
• control rods are inserted, *thereby preventing criticality ". dtiripg shutd()wn conditions*. * * * * , I 1:* A has* been provided to modify the ACTIONS related to. control rod .position indication channels.. Section 1.3; * .* Compijetion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or .... vari'abl es expressed in the Condition, discovered to be . or limits, will not result in separate . . entry into the Condi.:tion. Section i.3: also. specifies that . of to apply. failure, with Completion Times b.ased on initial ** . eiltry'jnto the*condition. However, the Required Actions for . inoperable control. rod' position indications provide . . . app,rppriate compens.atory measures for separate inoperable. . As such,* this'. Note has been provided, which*... .
• each jnoperable required q:mtrol rod position indication. . 11 * . ,. . *".A.1.*1.-*A.1.2, A.1.3, A.2.1. and A.2.2 or more requ-ired full-in position indiCations *. inoperable, actions *must be taken to protect .. again.st potential reactivity excursions frtim fuel assembly insertions or control rod withdrawals. *This may be* accomplished by immediately suspending invessel fuel.* *movement*_and control rod withdrawal, and 1mmediately in1tlatiTig action to fulJy insert*a11 trisertable control. *_rodsHn core cells containing one or more fuel assemblies.** .**** \!! ... . . ' . .. . -.-. *. (continued):** *.. :*. *.** ... : ,I. B* 3 .* 9-11 .. Revi s*i No*; 0 . .; .: \: ..... --. *. '.!! .. *** . :-* ; *:* .. ***".:: .* . . .<.*. '.,. __ -:* ..

_ ... *;: I. ' :***,. BASES ACTIONS SURVEILLANCE REQUIREMENTS PBAPS UNIT 3 Control Rod Position Indication B 3.9.4 A.LI. A.1.2, A.1.3,

• A.2.1 and A.2.2 (co*ntinued)
• Actions must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted. Suspension of invessel fuel movements and control rod withdrawal shall not preclude moving a component to a safe position. Alternatively, actions must be immediately initiated to fully insert the control rod(s) associated with the inoperable full-in position indicator(s) and disarm (electrically or hydraulically) the drive(s) to ensure that the control rod is not withdrawn. A control rod can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. A control rod can be electrically disarmed by disconnecting power from all four direction control valve. solenoids. Actions must continue until all associated control rods are fully inserted and *. are disarmed. Under these (control rod fully inserted and disarmed), an inoperable full-in position indfcation may be bypassed to allow refueling operations to proceed. An method must be used to ensure the control rod is folly inserted (e.g., use the "00" notch position indication). SR 3.9.4.1 The full-in position indications provide input to the one-rod-out interlock a'nd other refueling interlocks that require an permissive. The interlocks are_ actuated when. the full.,;in position indiCation for any contfdl is not present, since this indicates that all rods are not fully .inserted .. Therefore,_ testing of the full-in position indicati.ons is performed .to ensure that . .. when a control rod is withdrawn, the'full-in position *indication.is not presenL. The 'full-in position indication* is considered inoperable even with the control rod fully * .. ** if it would continue to indicate fulhin with the
• control rod withdrawn. *Performing the SR each time a* *** *control rod is.withdrawn is considered adequate because of the procedural controls on control rod withdrawals and the visual and audible indications available in the control to alert the operator to control rods not fully inserted. (continued) ' . ** ii.:** B 3.9-i2 *. *Revision No. o *.:. *' 'i ' I ---_______.j

• • • . . . BASES REFERENCES 1. . _PBAPS UNiT .. 3 *. 2. ' 3. ii Ii -II .h l1 II \1 ii -ii . ,, i1 II* .-ii :1 ' ii 'I ii !: .. . l! ii *. JI. Ii' :l II I! II Ii :J\ I' 1: II i! I' *' -II* ' -., "' Ii _-:* \i ' !! ', *:j ii ' 'ii I ,[ l ,. a 3.9-13 Control Rod Position Indication B 3.9.4 Revision No. 0 I ' '. Control Rod OPERABILITY-Refueling B 3.9.5 B 3.9 REFUELING OPERATIONS B 3.9.5 Control Rod OPERABILITY-Refueling BASES* BACKGROUND APPLICABLE SAFETY A.NALYSES LCO ... *, .. .-. . PBAPS. *UNIT 3 *. -: Control rods are components of the Control Rod Drive (CRD) System, the primary reactivity control system for the reactor: In conjunction with the Reactor Protection System, the .CRD System. provides the means for the reliable control of reactivity changes during refueling operation. In addition, the control rods provide the capability to maintain the reactor subcritical under all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the CRD System. UFSAR design criteria require that one of the two required independent control systems be capable of holding the reactor core subcritical under cold conditions (Ref. 1}. The CRD System is the system capable of maintaining the reactor subcritical in cold conditions. ;, . Preventfon and mitigation of prompt reactivity during refueling are.provided by refueling interlocks (LCO 3.9.1 and LCO 3.9.2}, the SDM (LCO 3.1.1), the wide *range neutron.monitor period-short scram (LCO 3.3.1.1), and. the cont*ro l

• rod b.l ock instrumentation ( LCO 3. 3. 2 .1). The sa*fety analyses for the control rod withdrawal error . during .refueling (Ref.. 2) and the fuel. assembly insertion .. *error (Ref. 3) evaluate the consequences of control rod
• withdrawal during refueling and also fuel assembly insertion with;, a rod. withdrawn. A .*prqmpt re,activity excursion *during refueling*could* *potentially result* in fuel failure with:'subsequent release 9f radioactive.mater:ial to the * . environment. Control rod s:cram provides protection should a . prompt reactivity occur. * * * * * .. rod OPERABILITY during refueling satisfies . *. Criterion* 3 *of the NRC Pol tc.Y Statement. *
• wi thdrawh control. rod must. be OPERABLE.*. The *contror rod is OPERABLE if the scram* accumulator **: i_s 940 psig and'. the control rod is :capab.le, of . ,.**:* :: .. .. . . :; . . :**** .. .----.-.. .*.: * .. * (continued). No., i7 BASES LCO (continued) APPLICABILITY ACTIONS SURVEILLANCE REQUIREMENTS. **-:.*., -------Control Rod OPERABILITY-Refueling B 3.9.5 being automatically inserted upon receipt of a scram signal. Inser:ted control rods have al ready completed their coritrol function, and therefore, are not required to be OPERABLE. !' * -During MODE 5, withdrawn control rods must be OPERABLE to ensure that in a scram the control rods will insert and the required negative reactivity to maintain the reactor subcritical. For MODES 1 and 2, control rod requirements are found in LCO 3.1.2, "Reactivity Anomalies," LCO 3.1.3, "Control Rod OPERABILITY," LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators." During MODES 3 and 4*, control rods are not able to be withdrawn since the mode switch is in shutdown and a control rod block is-applied. This provides adequate requirements for control rod OPERABILITY dtiring cnnditions. With.bne*or more withdrawn control rods inoperable, action be initiated to fully insett the inoperable contr61 rod(s). the contrril r6d{s) ensures shutd9wn. and scram cap*abi.l i t:i es a re not adversely affected. Actions-must continue until the*inoperable.control rod(s) is fully: inserted. * * .. SR .3.9.*5.l and SR 3.9.5.21* __ During MODE 5; th_e OPERAS*UITY of control rods is primarily req u i red>ta eri s'ure .a wit hcfr*awn* control _rod wi 11 . ' aufomC!tically_insert if_a s*ignal requi'rfng_a* reactor *.shutdown:occurs.-_ Because n*o explicit ana_lys-:is exists for a.utoniqtit shutd'owri. during retu'el i ng, the. s_hutdown' fun"ctfon is sati°sTied if the w.ithdrawn control rod is capable of automatic insertio.h and the associated CRD scram accumulator is 94ci* ps*;-g .' * * * * * * . *.The *sur'veillance frequency is controiled_under the* S'urve{llance ,Control_ Program .. * *., "-** -CcOntiriUed) .. :.--*.**--.-.B 3 .. 9-15 *Revision* No. 87

1. I

• i -. !..-_ . .1 -... . *. '. j .. ,. *' ._,. " I .. \--,. _ . ' *. *. -,-:*_* . *. BASES SURVEILLANCE REQUIREMENTS REFERENCES ... **,* . **-,-. *:-.... ; : : ..... * < * . .... .. _-:: ,** -. *-.. --*:. . P.BAPS: UNiT 3 -..... .-..... -;--_._:.* I'* '* -'I* II I' " .1* Control Rod OPERABILITV,...-Refueling . *B 3.9.5 ii II *' II. Ji . 1, . 1: SR' 3.9.5.1 and SR (continoed}" II . * . ** SRl:3.9.5.l is modified by* a Note that allows 7 days
• wi l of the *contra l rod to perform the Survei 11 ance . . Thiiis acknowledges* that the control rod must. first be withdrawn before performance of . the Survei 11 and
• avoids potential -.conflicts with SR 3.0.3 and _ -SR
• 0. 4
• L l UFSAR, Section 1.5. . . ii. *jf UFSAR, Section -14.5.3.3 . . *,; 3.
• Section 14.5.3.4. " '1i ii (t. ' .ii *11 ii . *-.11 ,, :111*._.*. -. _: l '> -*. t . ii *:1 *' " *,; II II '" I' . II Ii ... . *,.;_-"'.i ,: .. -. 11 *. * .. :* ... 11 ** *. , -1!.* * .:':-. ,,-__ .:a . o ... .*:* .. . * ... :-: .. '. . . . . . -:... . . '.!.:-.. * ,:* . -.* .

" I! ii ' ,j 11 RPV Water Level . B B.3.9 REFUELING OPERATioNS . I II . B 3.9.6 R_eactor Pressur&e Vessel (RPV) Watef7 Level 1: i: BASES (BACKGROUND jl ;:. '* The mJvement of fuel assemblies or.handling of control rods the RPV requires a minimum water level of 458 inches above ilRPV instrument zero. During refueling, this mai ntai.ns. a sufiiicient water level in the reactor vessel cavity and spent!fuel pool .. Sufficient water is necessary to retain iodine fission product ac'ti vity in the water in the event. of . I! . . * *. . -a fuel handling accident (Refs. 1 2). Sufficient iodine activi;ty would be retained to limit doses from the. accident to wel 1. below .the guidelines set forth in *

• 10 50.67 (Ref. 3) as modified in Regulatory Guide 1.1.83, Tablej6. * * .. . I APPLICABLE. * . S,A.FETY ANALYSES . ,* .. I . .. *.* ... , . ,*' .... ,: -: . : *, .. , :* ,. -:.:**_:* *-*.**-*.* .... --*.,,-,' .. --.:*.:' -* ' .. : .... :*_, .. _'. ., .*;, -. .. _ .. . --PBAPS U,N'rT 3 '1 .* ,*"' *-* * ...... :: !! Durind movement rif assemblies or*handling of control' rods, ::the .water level in the RPV and the spent fuel pooi is_ an initial condition design parameter in the of a fuel handling accident in containment .. postui:ated fo Reference 1 . A mini mum water 1 evel of 20 ft ...
• 11 ;:itiove tl]e top of the RPV flange_allows a partition factori of 200 to be used .. in the accident analysis .. for * * -halpgens(Ref.-,1)-:_ ** * * . It --. *** of the fuel accident "inside contai.nmenV is _ in ,Reference 1_; , With a mini mum water 1 _of 458 i r:;iches-above* RPV *instrument zero* (20 _ft 11 inches above the tqp of the RPV flange) and a mini muin decay ti nie of . .-* * . hocirs to fuel. handling, the and test . ' " 11* --._'."* . * * . -.. . * * '. . . .>: . . . --__ * ;p*rograms that. the i odi.ne rel ease due to a _ . . postulated fuel handling* acc'*l'dent i 5 adequately by ' --al 10wable 1 imits (Ref. :.3). . . :: . '* / .. --. -. r -e*iit.he worst. a:ssynipt ions 1 Ude< the dropping Of ?n _ .... the, *.** possibility exists'of ttie dropped assemoly striking the RPV _ *flange and releasing fission products. the _-. . 'm1nimillm _depth for water (::overage to acceptabl'e -rad1 ofogical' consequences: i specifi.ed from the RPV flange: . Slnce Ji the* worst case event: results in fai 1 e.o fuel asseinb.ll:es -"in the core; vvel.l as.:the dropped" .asseinbl y, ' -: : ' . . " . . . . . . ' ': " .... :*; *' -I ., . .... _ .. ,n I* : . *. Ji.;:: . -I[ .-i". --.ii l'i
• 1* -* __ .: ( conti hued')' *:***-" .. --' ...... ,.-. : _B 3.9-17 -* Revision >16 '.:.** ,. __
• ,' ,. ,. ' *>-*. --. BASES APPLICABLE.* SAFETY ANALYSES (continu*ed)
• LCO APPLICABILITY . ACTIONS.* ..... *, ... . . '.* * .. , " .. *. . . -. . PBAPS UNIT 3 --. . . . * ' :* < * * . :: II . JI . . !! if ii RPV Water Level B 3.9.6 dropp'i ng an assemb 1 y on the RPV flange wi 11 resu 1 t in redu.ced releases of fission gases. Based on this judgement, and :the physical dimensions which preclude normal operation with:: water 1 evel 23 feet above the flange, *a s 1 i ght
• reduction in thiS water level (to 20 ft 11 inches above the flange) is acceptable (Ref. 3}.
• 1 ' RPV.water level satisfies Criterion 2 of the NRC Policy
• Statement. . Ir jf A minimum water level of 458 inches above RPV instrument . zero:i ( 20 rt 11 inches
• above the top of the RPV fl ange) is requ:1red to ensure that the radiological consequences of a post;µl ated fuel handling accident are within acceptable limits. Ii . '* LCO is applicable when moving fuel assemblies or hand;l i ng contro 1 rods ( i . e. , movement with other than the control rod drive) within the RJ>V. The LCO minimizes the of a *fuel handling in containment that:: is beyond the assumptions of the safety analysis. If irradiated fuel is not present within the RPV, there can be no s:]gnificant radioactivity release as a result of a postulated fuel* handling accident. Requirements for fuel in'the spent fuel storage pool are covered by lCO 3. 7. 7, n Spent Fuel Storage Pool Water Leve 1 . II . ' .. i! .. .11_ If die water level is< 458 inches above RPV instrument zero::, all. operations i nv:olving movement of fue 1 assemblies and ing of control rods within the RPV shall be inunediately to ensure that a fuel handling acci;dent cannot occur. The suspension of fuel movement and rod handling shall not preclude completion of movement of a component to a safe position. !! . .. . " . ;i I' -.. 'ii ... 'ii' II *.Ii -I II 'I i1
• 1 I! --ii - .. 11-(continued) *. B 3.9-IS Revision No. 0 .*: * .

. : '* RPV Water Level B 3.9.6 BASES (continued) SURVEILLANCE REQUIREMENTS REFERENCES. *, . ' ' -.----,-* . .-:;" . .-. " ' -*,_ *. _: . . . PBAPS UNif 3 SR 3.9.6.l of a m1n1mum water level of 458 inches above RPV instrument zero ensures that the design basis for the postulated fuel handling accident analysis during refueling operations is met. Water at the required level limits the consequences of damaged fuel rods, which are postulated to a fuel handling accident in c6ntainment (Ref .. 1). The Surveillance Frequency is controlled under the Surveillance Frequency Control 1. UFSAR, Section 14.6.4. 2. UFSAR, Section 10.3 . .. '.* . ,*'". ---. :::*-**-*1**** ,,,-I,. .., -: .: : . . ***' B ,3.9-19 *.: '. No. 87 I Water Level B 3.9.7 B 3.9 REFUELING OPERATIONS B 3.9.7 Residual Heat Removal Water Level BASES BACKGROUND APPLiCABLE SAFETY ANALYSES LCO -: -. . . . '-*< -. . . . PBAPS UNIT 3' ._* .. The .purpose of the RHR System in MODE 5 is to remove decay heat and sensible heat from the reactor coolant, as required in UFSAR, Section 1.5. The RHR System has two loops with each loop consisting of two motor driven pumps, two heat and associated piping and valves. There are two RHR shutdown cooling subsystems per RHR System loop. The four RHR shutdown cool1ng subsystems have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchangers, to the reactor via the .associ.ated

• recirculation 1 oop. The RHR heat exchangers transfer heat to the High Pressure Service Water System . .. The RHR'shutdown cooling mode is manually controlled. Any one.of the four RHR shutdown cooling subsystems can provide the required decay heat removal function .. In to the.RHR the of water above the reactor pressure (RPV) flange provides a heat sink decay heat removal . . With the unit in.MODE 5, the RHR System is not required to mi t i:gate any events. or .accidents evaluated . in the safety analyses. *. The RHR System is required for removing decay heat to maintain the temperature of the reactor coolant . . The RHR System satisfies Criterion 4 of the NRC Pol icy * .. * * * * * .--* .... Only one.RHR *shutdowr( cooling *subsystem is required to be . OPERABLE and fo. operation in MODE 5 with-irradiated.fuel in *. the *RPV and the water level 458 inches above RPV . : .. * *. zero. Only one subsystem is required because .
• vo*l gf water (lbove the RPV: flange pro vi des backup. decay
• heat removal capabll ity. * * . . *. . _ . --. --An.OPERABLE-RHR shutdown cooling .subsystem consists of an *.RHR pump, a heat exchanger, a High Pressure Service Water. *S.Y&tem pump*capable of :providing cooling to the* heat '. exchanger, valves, pipfng*,. instruments, and controlS to * * . an-OPERAB.LE. fl ow path.
• In MODE 5; the RHR. cross-tie * * -*
• J * -.'* :.---{continued) ":t ** ..... _.-.--. . 0. **:* .-,...
• Revisio.ri No. o *. R 3.9..:20.

BASES LCD (continued) APP LI CAB I LITY

• ACT.IONS 'PBAPS-U.NIT 3 RHR-Hi gh Water* Level B 3.9.7 valve is not required to be closed; thus the valve may be opened to allow an RHR pump in one loop to discharge through the opposite recirculation loop to complete subsystem. In additi On, the HPSW cross-tie valve may be open to allow a HPSW pump in one loop to provide cooling to a heat* exchanger in the opposite loop to make a complete subsystem. Management of gas voids is important to RHR Cooling System OPERABILITY .. Additionally, each RHR shutdown cooling is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. Operation (either or intermittent) of one subsystem can maintain and reduce the coolant temperature as required. However, to ensure adequate core flow tO allow for average react6r coolant temperature monitoring, nearly continuous operation is required. A Note provided to allow a 2 hour exception to shut down the operating subsystem every 8 hours. One shutdown cooling subsystem must be OPERABLE .and in operation in MODE 5, with irradiated fuel in the RPV and the water 458 inches above RPV instrument zero (20 ft
• 11 inches.above the top of the RPV flange), to provide decay heat removal.
• RHR shutdown cooling subsystem requirements in other MODES are covered by lCOs in Section 3.4, *Reactor Coolant System (RCS); Section 3.5, Emergency Core Cooling Systems CECCS) and Reactor Core Isolation. Cooling CRCIC) Section }.6, Systems ..
• Cociling System requirement& in MODE. 5 with irradiated fuel the'RPV and the < 458 inches abOve RPV zero are given in LCD 3.9.8. With no RHR shutdown c6oling subsystem OPERABLE, an* alternate method of decay heat removal must be established within 1 hour. In this condition, the volume of water above the RPV flange provides adequate capability to remove decay heat 'tram the reactor core.' However, the overall reliabilitY is reduced because loss of water level could result) n *reduced decay heat removal ca pa bi l i ty. The 1 hour Completion Time is on decay heat removal function and continued Ii.-*--. B N6. 128 BASES ACTIONS* '1._'; .. *., . ;>;-PBAP,S .. UN Il 3 * *,., A. l (continued) Water Level B 3.9.7 the,.probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 *hours thereafter. This wil 1. ensure continued heat removal capability. Al te'rnate decay heat removal methods are avail able to the oper:ators for review and preplanning in the unit's Operating Procedures. For examp 1 e, this may . inc 1 ude the use of the Rea<tor Water Cleanup System, operating with the . regenerative heat exchanger bypassed. The method usedto remove the decay heat be the most prudent choice based on unit conditions. B.l, B.2, B.3, and B.4 . If no RHR shutdown cooling subsystem is OPERABLE and ari al tern.ate method. of decay heat removal is not available. in accorqance with Required Action A.1, actions shall be taken immediately to suspend operations involving an increase in reactor decay heat .1 oad by suspending 1 oad i ng of irradiated fuel assemblies into the RPV. *
• AdditionaJ are to minimize any potential fission product *release to the This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem for>Unit 3 is OPERABLE; and. secondary -isolation capability (i.e:, one secondary. containment isolation valve and associated instrumentatibn . are OPERABLE o_r *other' acceptable administrati_ve controls to. isol_ation capability) in each associated penetration not.isolated.that is a:ssumed to be isolated to mitigate radioactive *releases.* This may be performed as an. . administrative *check; by exa111ining logs or other informat.ion to.determine whether thetomporients are out of service* for. maintenance or other < It is not necessary to: < ' ,' . pe*rfo*fm the survetll.ance.s need"e!d. *to ..... , .....
• OPERABILITY of the components. If, however, any required then it be restored to . OPERABLE status.
• In this case, a survei 11 ance may' need to * * .. be performed to restore the *component to OPERABLE status.
• Actions must continue.until all required components are OPERABLE. Ccontiriuedl : .*.* B 3.9-22' Revfsi on No.*. 0 . . .
• ! ... : BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS . , , '* " PBAPS .UN IT 3 C.1 and C.2 RHR-Hi gh Water Level B 3.9.7 If no RHR _shutdown cooling subsystem is in operation, an method of coolant circulation is required to be established within 1 hour. This alternate method may utilize forced or natural circulation cooling. The Completion Time is modified such that the 1 hour is applicable separately for each occurrence involving a loss of cooJant circulation. During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem), the reactor coolant temperature must be periodically monitored to ensure proper functioning of the alternate method. The once per hour Completion Time is deemed appropriate. SR 3.9.7.1 This Surveillance demonstrates that the RHR shutdown cooling subsystem is in operation and circulating reactor coolant. Jhe required flow rate is determined by the flow rate necessary to provide heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. SR 3. 9. 7. 2 RHR Shutdown Cooling (SGC) System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas and accumulation is necessary for proper operation of the required RHR shutdown cooling subsystems and may also prevent hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.* Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of _system design information, including piping and instrumentation drawings, isometric drawings, plan and -elevation drawings, cal.culations, and operational procedures. The design review is supplemented by system walk.downs to validate the system high and to confirm continued B 3.9-23 Revision No. 128
• -'*,. -. . -,: BASES SURVEILLANCE REQUIREMENTS :. ... '*. * 'r :'*""' . : .. -.. :*--*.-PBAPS UN IT 3 SR 3.9.7.2 (continued) RHR-Hi gh Water Level B 3.9.7 . the location and orientation of important-components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system.configuration, such as stand-by versus operating conditions. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water.* For the RHR SOC piping on the discharge side of the RHR pump, acceptance criteria are for the volume pf accumulated gas at susceptible locations. *If accumulated gas is di.scovered that. exceeds the acc.eptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas vtilume in the RHR. SOC piping on the discharge side of a pump), the is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits' during per'formance of the Survei 11 ance, th_e SR is met and past system OPERABILITY is evaluated under the* Corrective Action Program. If it is determined by sub.sequent evaluation that t_he RHR Shutdown Cooling System *is i:iot, rendered inoperable by the accumulated gas (i.e., the is sufficieritlj fil.led with. water), the . Surveillance ma.Y be declared met: Accumulated gas should be eliminated. o.r* brought wit.hin the acceptance criteria . limHs ... Si"ihce :the RHR SOC piping on the discharge side of .*.the-pump is.the*.sarne.asthe Low Pressure Coolant Injection piping, performances of survei 11 ances for ECCS TS may
• satisfy *xhe* requirements of this s*urveil Yance. ** For* the RHR SOC piping on the on side of :the RHR-pump, the surveiJlanie is by virtue of the performance 6f o*peratJr19 procedure's that erisure. that the RHR SOC suction . . piping.' is adequately. fill e.d and vented ... The p.erformance *of. these inanual actions 'ensu:res the :survei 11 ance is met: *
• RHR SOC: Systeml9cations o'n the discharge: side of th_e RHR . pump sus'cepti bl e* to g*as accufnul ati on .a re .monitored.* and' if *'ga's is*fou'nd, *the gas volume 'i$ compared to the** acceptance*
• c r i t e r i a : for t h .e
• l 6 ca t i on . ' s u s c ep ti b le l o ca t i on s i n t h e *same, syste:m fl ow path which. a re subject to th_e *same gas tntrusion verified by-monitoring a* ' representative sub-.set (JJ* susceptible locations.: .MQnito.ring may .. not be p'racti'cal for locations that are .. . *. inaccessible*due_to*radiol.ogica1**or environmental concji't:jons, the pl ant configuration, or persqnnel safety, f o*r *these. l ocali ori s. l terna'ti ve methods-(e.g. , *opera ti rig * .. : '; :.-<* -: :, 0conti nued). ,:'* B 3:9-23a
• Revision .129 I I.* BASES SURVEILLANCE REQUIREMENTS REFERENCES .. ;* PBAPS UNIT: 3 RHR-High Water Level B 3.9.7 SR 3.9.7.2 (continued). parameters, remote monitoring) may be used to monitor the location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Sµrveillance interval. The SR can *be met by of having an RHR SOC subsystem inservice in accordance with operating procedures. The SR is modified by Note. The Note recognizes that the scope*of the surveillance is limited to the RHR system components. *The HPSW system components have been detefmined to not be to be iii the scope of thjs surveillance due operating expertence and the design of the system. The Frequency is controlled under the Survei:ll ance Frequency Control* Program. The Survei 11 ance may vary by location accumu'lat1 on.. * *
• None.* *, '.: -... . . .. ... . . **_:: . *:.:*. -* .. ** .. .... **:' . Revi si ori* No. 128 I .. , . .. ***-,:.* '--.*.'

,-_, .-.. __ Water Level

• B 3.9.8 B 3. 9 REFUELING OPERATIONS B 3.9.8 Residual Heat Removal Water Level BASES BACKGROUND The purpose of the RHR System in MODE 5 is to remove decay . heat and sensible heat from the reactor coolant, as required in UFSAR Section 1.5. The RHR System has two loops with each loop consisting of two motor driven pumps, two heat exchangers, and associated piping and valves.* There are two RHR shutdown cooling subsystems per RHR System loop. The *four RHR shutdown cooling subsystems have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after it has been cooled by circulation through the respective heat exchangers, to the reactor via the 'associated reci rcul at ion 1 oop. The RHR heat exchangers transfer heat to the High Pressure Service Water System. The HHR shutdown cooling mode is manually controlled. Any one of the four RHR shutdown cooling subsystems can provide the required decay heat removal function.
• APPLICABLE With the unit in MODE 5, the RHR System is not requfred to SAFETY ANALYSES mitigate any events or accidents. evaluated in the safety
• analyses. The RHR System is required for removing decay * *heat to maintain the temperature of the reactor coolant. _ .. Leo*.* . _,*' -*. UNIT 3 The RHR Systein sat i.sfi es Criterion 4 of th.e NRC Policy Statement.
• I In *MODE 5 with irradiated fuel in the RPV and the water level < 458 inches above* re.actor vess.el (RPV.) instrument zero both RHR shutdown cooling subsystems must be OPERABLE. . . . An a*PERABLE RHR shutdown cooling subsystem consists of an . RHR pump, a heat exchanger, a High Pressure Service Water System pump capable of providing cooling to the heat
• exchanger, piping,.instruments, and controls to ensure an OPERABLE fl ow path. The two. subsystems have a common suction source and are allowed to have common discharge piping. Since piping is a passive component that is assumed not to fail, it is allowed to be common to both . subsystems. In MODE 5, the RHR cross-tie valve is not * *.required to be c 1 osed, thus the valve may be ope.ned to al low (continued):* B 3 *. 9-24 Revision No,: o--. ,, __ ,. '* *.:.

BASES LCO ( cont i *nu e d ) APPLICABILITY " ' ACTIONS .' *,'. -* -PBAPS UNIT-3 RHR-Low Water Level B 3.9.8 an RHR pump in one loop to discharge through the opposite recirculation loop to make a complete In addition, the HPSW cross-tie valve may be open to allow a _ HPSW pump in one loop to provide cooling to a heat exchanger in the 6pposite loop to make a complete subsystem. Management of gas voids is important to RHR SOC System OPERABILITY. Additfonally, each RHR shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or 1 ocal) in the shutdown cooling mode for remov.al of decay . heat. *Operation (either continuous or intermittent) of one subsystem can maintain and reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant monitoring, nearly continuous operation is *required. A Note is provided to allow a 2 hour exception to shut the operating subsystem.every 8 hours. Two RHR shutdown cooling subsystems are required to be OPERABLE, and one must be in operation in MODE 5, with irradiated fuel* in the RPV and the water level < 458 inches above RPV instrument zero (20 ft 11 inches above the top of the RPV flange), t6 provide decay heat removal. RHR

• shutdown cooling subsystem requirements in other MODES are tovered *by LCOs in Section 3.4, React6r Coolant System CRCS); .. Secti.on 3.5; Cor.e Cooling Systems CECCS.*) and Reactor Core Isolation Cooling CRtIC) System; and
• Section 3.6, Containment Systems. _ RHR Shutdown Cooling system.requirements in MODE 5 with. irradiated fuel in the RPV the level 458 inches above RPV instrumeht zero :are given in LCO 3.9:7, !'Residual Heat-Removal CRHR)-High Water Level." .. '* . . ' . . . . With one of the two.required RHR shutdown cooling subsystems . inqperable, the rernaining*subsystem is capable of providing the required decay heat removal. However, the overall
• rel i abi:'l ity is reduced. Therefore ari *altern*ate method of decay heat must be provided. With both required RHR *-subsystems inoperable-, an method of heat must be provided in addition io provided for. the initial RH_R shutdown cooling subsystem i_nopera-bi li ty, *This re--e.stabl i shes. backup decay heat sim{lar to the requirementi of the continued B 3.9-25 *Revision No. 128 .. *

,1, .... :-. *.-*** ;*. ,. ,_ BASES ACTIONS .' '. Ii i[. j! " -II . 11-:_I :! 11 A.I:: *ccont*inued) ii Water Level B 3.9.8 LCO.:!-The l hour Completion Time is based on the decay heat remd,va l function and the probability of a loss of the

• avaiq able decay heat removal capabilities. . Furthermore, veri.:fication of the functional availability of this a lte'rnate method ( s) must be reconfirmed every 24 hours thereafter. This will ensure continued heat removal AltJ1rnate heat removal methods are available to the for review and in the unit's Operating Procedures. For this may include the use of the .
• Water Cl eanu-p System, operating with the heat exchanger bypassed. The method used to decay heat should be the most prudent choice based on unit:: conditions. II -!1 B.I.!' B.2.* and B.3 " '* Withil the required decay heat removal subsystem(s) inoperable -* -and required alternate method(s) of decay heat removal not in accordance with Required Action A.I, additional* actions are required to minimize any potential fiss*:ion product release to the environment. This includes *ensuring secondary containment is.OPERABLE;_ one standby gas tre.atment subsystem for Unit 3 .is OPERABLE; and secondary -_ containment i sol at ion_. capability * ( i . e. , one secondary -containment 'isolation valve and associated instrumentation -are QPERABLE or o.ther* acceptable administrative controls to *assure isolation capability) in each associated penetration that::*is a_ssumed to be isolated to mitigate radioactive : -' releases. -This may be performed as an administrative check, by e*arriining logs .or other information to determine whether the !=Omponents are out of service for maintenance or other _ It is not necessary to perform the Survei 11 ances needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it** must !I be restored to OPERABLE status. In this case, the
• surveillance may need to be performed to restore the compqnent to OPERABLE status. Actions must continue until all required components are OPERABLE. 1,-i: II . (continued).* . ... *.' -*. -.. : ' . . . . . . .PBAPS *,_.*. * *":c' * .. . '*-* .: -_-ii -. !! . :! * . . ii ! ii .** II II 'I " ' ... :11 !l**. -B 3.9-26 Revision O * ..
• -: .\",* . .* . . -*'.:_ BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS ,:*, *, *. '**** .... -<* .* C.l and C.2 RHR-Low Water Level B 3.9.8 If no RHR shutdown subsystem is in operation, an alternate method of coolant circulation is required to be established within 1 hour. This alternate method may utilize forced or natural circulation cooling. The Completion Time is modified such that the 1 hour is applicable separately for each occurrence involving a loss of cocilant Durin4 the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem), the reactor coolant.temperature must be periodically monitored to ensure functioning of the alternate method. The once per hour Completion Time is deemed appropriate. This dem6nst0ates that one RHR shutdown cooling subsystem is in opefation and circulating reactor coolant. The required flow rate is by the flow rate
• to provide sufficient de'cay heat removal capabi-li ty ... The Sur.veil lance Frequen.cy is controlled under the Survei ! lance, Frequency Control*. Program. *
• J * . . -. .. SR ' RHR Shutdown Coo ting :c SDC) System *Piping .and components have the pofe.ntiaJ .to develop. voids. and pockets of .entrained *.gases.* Preventing gas intrusion and: accurnµl atton i$ r:re,cessary 'for proper bperatl on of the' 'requi shutdown cool'i ng subsystems and m'ay al so Ar.Jater ha*rrrnier ,* pump tati and pu1npi n9 of . *"nOhcondensl-bl e ga*s .into the* reactor vessel; . ' , ' ., . . . . . . . ' ' *'* . Coolfng.System * *susceptible to .9as accumulation.is based on a ,review of* . system 'desjgn information,*. i ncl,udi ng piping and* . . .. , .i.r{stru.mentati on dr:awtng:s, i soriletri c dra*wi.ngs, pl an and .. el evatJ011 'drawings,. cal cul ati'ons :* and opera.ti on:a,. ' : . PBAPS UN fT 3 *, .*procedqfes.* The design 'revJew is s*up'plemented by system** walk do:wps .to va H date the *s.ystem high poi nts:and to.confirm. (continued) B j**._9-2.7,.. -. Revision No. :.128

,* -. BASES SURVEILLANCE . REQUIREMENTS .. **. ,* PBAPS UN::IT 3 '" '* SR 3.9.8.2 (continued) RHR-Low Water Level B 3.9.8 the 1ocation and orientation of important components that cari become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restor'ation. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions. The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. For the RHR SOC piping* on the side of the RHR pump, acceptance criteria are established for the volume of accumulated gas at susceptible locations* .. If accumulated *gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume. of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume in the RHR SOC piping on the discharge side of a pump), the SurJeillance is not If the accumulated gas is eliminated *or brought within* the acceptance criteria limits during performance rif the Surveillance, the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the* accumulated gas. (i.e., the system is suffi ci entl y fi 11 ed: with water), the .s_urvei 11 ance may be. de cl a red met. Ac_cumul ated gas.should be eliminated or brought within the acceptance criteria limits:. Since the RHR SOC piping on the discharge side of the pump is the same as the low Pressure Injection piping,-performances of surveiJlances for ECCS. TS may satisfy the requirements of this surveillance. For RHR SOC piping an the suction side of the RHR the survei.ll ance is met* by virtue of the performance of procedures that* ensure that the RHR *soc suction piping *i S: adeq*uately filled. and. vented. The performance of these man.Ua.l *actions ensufes that the survei 11 ance is met. * * * ,* * ;, c * -** *RHR SOG System* 1 ocations O'n the d.i scha'rge side of the RHR. pump sgscepti bl e to g_a s accumufat ion a re mo_n:itored and, H gas is-found, the gas volume. is.compared to the acceptance cr:iterta:.for the location/ .Susceptible locati'crns iri th*e same s,Xstem fl ow path which* are .subject to the same _gas . intrusio:n mechani'sms ma.y *be verified* by monitoring a * *'sub: set* of* susce.pti bl e:*1 ocat ions.* Mcinitor\ng may not be practical for loca.tions that are -inaccessible due* to radfolcigical or environmental <<:ondi tfons' the configuration; or personnel safety.-. For th.e'se"Jocatrons alter*nat:J.ve methods (e;g*., operating.

• pa remote mon.i tori ng l: may be. µsed to monitor :the*.* <._ .-.* (continued) .*.* * ... -B 3. 9-28-* Re vision No*. )29*-*

BASES SURVEILLANCE *REQUIREMENTS REFERENCES SR 3.9.8.2 (continued) RHR.:_Low Water Level B 3.9.8 susceptible location. M6nitoring is not required for susceptible where the maximum potential accumulated gas void volume. has been evaluated and determined to not chal 1 enge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be .sufficient to system OPERABILITY during the Surveillance iriterval. The -SR can be met by virtue of having an RHR SOC subsystem in acccirdance with operating procedures .. The SR is modified by a Note.* The Note recognizes that the scope of the surveillance is limited to the RHR system The HPSW system components have been determined to not be to be in the of this surveillance due to' operating experience and the design of the system. The Surveillance Frequency controlled under the Surveillahce Frequency Control Program. The Surveillance Frequency vary susteptible accumulation. None.

• B 3.9c29 Revision No .. 128 l *'* . . '.*' '>:. -:,. .. _* ,_

I I . Inservice Leak and Hydrostatic Testing Operation B 3.10.1 B 3.10 . SPECIAL OPERATidNS B 3.10.l Insefvice Leak and Hydrostatic Testing Operation BASES BACKGROUND ... * *-,-.* PBAPS UNIT 3. The purpose of this Special Operations LCO is to allow certain reactor coolant pressure tests to be performed in MODE 4 when the metallurgical characteristics of the reactor pressure vessel CRPV) or plant temperature control during these tests requife the pressure testing at temperatures> 212°F (normally corresponding to MODE 3) of to allow completing these reactor coolant pressure tests. when the initial conditions do not require.temperatures> 212°F. Furthermore, the purpose is to allow continued performance of control rod scram testing reqVired by SR 3.1.4.1 or SR 3.1.4.4 if reactor coolant temperatures exceed 212°F*when the control rod scram time testing is initiated

• in conjunction with an inservice leak or hydrostatic test. These control rod scram time tests would be performed in a cc or d a n ce wit h LC O 3 . 1 O . 4 , " S i n g 1 e Con t r o 1 Rod Wit h d raw a 1 -Cold Shutdown," during MODE 4 operation. Inservice hydrostatic testing and system leakage pressure tests tequired by Section XI of the American Society of
• Mechanical Engineets CASME) Boiler and Pressure Vessel Code (Ref. are pe0formed prior to.the going critical * *after a refueling putage.-Recirculation* pump operatioD and a water solid RPV (except for an air bubble for pressure c6ntrof) are used-to achieve the necessary and pressures required for tests. ihe minimum. temperatures Cat the .. required pressures) allowed for these tests are .determi,ned from the RPV pre"ssure and temperat.ure CP!T) limits required by LCO 3.4.9, "Reactor Coolant System . (RCS) Ptessure and Temperature (PIT) Limits." These limits are conservatively .based on the fracture of the reactor vessel, taking into account anticipated vessel neutron *
• With reactor vessel fluence o'ver dme, the mihimurh allowable vessel temperature increases at* a *gi Ven. pressure .. Periodic updates to the RCS P/T limit are perfofmed *._.*.* "'. as based upon results of analyses of irrgdia.ted surveillance ,specimens removed fr.om the vessel:. . Hydrosta'ti c anc;f leak testing may eventually be required with*. minimum > However, with required min.jm'um reactor 'coolant tempera:tures < 212°{,; ... ** temperatures a small the* _ ...... continued B 3.10-1 *Revision.No. l}l**
• BASES BACKGROUND (continued) APPLICABLE SAFETY ANALYSES
• PBAPS .UNlT 3 Inservice Leak and Hydrostatic Testing Operation B 3.10.1 test can be impractical. Removal of heat addition from recirculatiori and reactor core decay heat can be controlled by control rod drive. hydraulic system flow and reactor water cleanup system non-regenerative heat exchanger operation. Test conditions are focused on maintaining a steady state pressure, and tightly limited temperature control poses an unnecessary burden on the operatpr and may not be achievable in certain instances. The hydrostatic and RCS system leakage tests require increasing pressure to. approximately 1000 psig. *Scram time testing required by SR and SR 3.1.4.4 requires reactor 800 Other testing may be performed in conjunction with the allowances for inservice leak or hydrostatic tests and control rod scram time tests. Allowing the to be considered in MODE 4 when the reactor coolant temperature is> 212°F during, or as a consequence of, hydrostatic or leak testing, or as a consequence of control rod time testing initiated in conjunction with an inservice leak or hydrostatic test, effectively provides an exception to MODE 3 requirements, including OPERABILITY of primary containment the full complement of redundant Emergency Core Cooling Systems. Since the tests are performed nearly water solid (except for an air bubble for pressure coritrol ), at low decay heat values; and near MODE 4 conditions, the stored energy in the core will be very low. Under these conditions, the potential for failed fuel and a subsequent increase in coolant activity above the* LCO 3.4.6, "RCS Specific Activity," .limits are minimized. In addition, .the secondary containment will be OPERABLE, in accordance with this Special Operations LCO, and will be capable of handling any airborne radioactivity or steam leaks that could occur during the performance of hydrostatic or leak testing. The required pressure testing conditions provide adequate assurance that the consequences of a steam leak will be conservatively bounded by the consequences of the postulated main steam line break outside of primary containment* described in Reference 2. Therefore, these requirements will conservatively limit radiation releases to the environment. (continued) B 3.10-2 Revision No. 131
• . ',: BASES APPLICABLE SAFETY ANA_L YSES. (continued) lCO . . . . ., : PBAPS UNIT 3 ... Inservice Leak and Hydrostatic Testing Operation B 3.10.1 In the event of a large primary system leak, the reactor vessel would rapidly depressurize, allowing the low pressure core cooling systems to operate. The capability of the low pressure coolant injection and core spray subsystems, as required in MODE 4 by LCO 3.5.2, "ECCS-Shutdown," would be more than adequate to keep the core flooded under this low decay heat load condition. Small system leaks would be detected by leakage inspections before significant inventory loss occurred. For the purposes of this test, the protection provided by normally required MODE 4 applicable LCOs, in addition to the secondary tontainment requirements required to be met by this Special Operations LCO, will ensure acceptable consequences during normal hydrostatic test conditions and during po?tulated accident conditions. As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operatibns LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A . discussion of the criteria sati sfi.ed for the other LCOs is in their respective eases. As *descr-rned in LCO 3.; o :7, c'ompl i ance with th.is Special Opera ti ans lC(J' is opti onaL*
• Operat.i on at reactor coolant . temperatures > 2126 F can be 1 n* actordanc.e With Table 1.1 .*
• for MOD[*3. opera ti on wi.thout meeting this Special Opera ti ans its.ACTIONS.
• J.his option 111ay be required due to P/T l. irni ts,, however,
• require testing at temperatures . >. 212°p-, <whi Te the ASME_*i nservi ce *test itself the --l -. ' . -safety/rel i e.f val ve-s to be gagged, preventing *their *
• OPERAS I L:-(Tf *, Additi 6ria lTY; *even* with. required mini mum r_eaCtot:'**_cocii ant temperatures < 212°.F ,. *Rts temp.era fores may dri fL atlOVe 21°2°*-F duri.ng the: performance of ins.ervi ce l:eak >*and hYdfostat ic *t'esdng or:: duri hg subsequ.ent control. rod 'scram time testing; w_hich {s typically performed in . conjunct-ion with: inservice,ieak and hydrostatic testing ... . While for leak and hydrostatic. tesUng, .and for -scram t-ime testing. in:iti)ited i'rf conjurid:rori:w'ith-an inservice .leak or .* .* *hydrosta.tic_.test,* pa.ral l el performance of others and riot * . -*} :,.)*' ... continued' , __ -'B .. 3:10--2a Rev i s i 0 n N 6 .-i 31 I BASES LCD (continued) APPLICABIUTY .ACTIONS '.:" .. **' *' . PSAP.S UNIT 3 Inservice Leak and Hydrostatic Testing Operation B 3.10.l If it is desired to perform these tests while complying with this Special Operations LCD, then the MODE 4 applicable LCOs and specified MODE 3 LCOs must be met. This Special Operat1ons LCD cillows changing Table 1.1-1 temperature limits for MODE 4 to "NA" and suspending the requirements of LCD 3.4.8, "Residual Heat Removal CRHR) Shutdown Cooling d Shutdown." The additional requirements for . secondary containment LCOs to be met will provide sufficient protection for operations at reactor coolant temperatures > 212°F for the purpose of performing an inservice leak or hydrostatic .test, and for control rod scram time testing initiated .in conjunction with an inservice leak or test. This allows primary containment to be open for frequent unobstructed access to perform inspections, and for outage on various systems to continue consistent with the MODE 4 applicable requirements. The M9DE*4 requirements maf only be modified for the of, or as a inservice leak or tests, or as consequence of rod scram time testing initiated in conjunction with an inservice leak or hydrostatic test, so that these be considered as in MODt 4; though the reactor cocilant temperature is > 212°f. *The additional requirement for secondary ,containment OPERABILITY according to the imposed MODE3 *provides* conservatism in the response of the untt to any event may occur. in all other MODES *a re unaffected by this LCD. * ' " ' ' . . ,:*_ A 'has been ACTrDNS related to inservi:ce ie*ak*and hydrostatic testing operation. *Section i.3, Comple-tion T*i'mes*, specifies'tt:iat .. onc*e a . C0n'dltio'n' has been en.:te*red,, subsequent div.isions., in the Condifiori_piscoveted to be i:noperable or not within limits, will not+esult in>separate entry -into.the C.bridition. * * * * .... SectloD_ :f-:3 al so s.peci fies that Required Actions of the Condition continue .to ap*pry for. e*ach a*dditton*a1 fallure, with Completion Times ba.sed.oninitial entry"into the *condit:i'on:**Howeve'r-, the Required Actions-for each requi r¢meh,t of the not met pr.ovi de ap.propri :. -. *, **-. . .-.. * .B *3.10-.3 . -*. confi.nued Revision.No. 131 .-*: .

BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS -. *, -* '-',. .REFERENCES .. **.i.-PBAPS UNIT 3 .-.... -: .. : _.-.,-, .. . ,._: Inservice Leak and Hydrostatic Testing Operation B 3.10.1 If an LCO specified jn LCO 3.10.1 is not met, the* ACTIONS applicable to the stated requirements are entered and complied with. Required Action A.1 has been modified by a Note that c1arifies the intent of another LCO's Required Actitin to be in MODE 4 includes reducing the coolant temperature to s 212°F. A.2.1 and A.2.2 Action A.2.1 and Required Action A.2.2 are alternate Required Actions that can be taken instead of* Required Action A.l to restore compliance with the normal MODE 4 requirements, and *thereby exit this Special Operation LCO's Applicability. Activities that could f0rther increase reactor coolant temperature or press0re are suspended immediately, in accordance with Required Action A.2.1; and the reactor cool ant temper-ature is reduced to establish normal MODE 4 requirements.* The allowed *completion Time of 24 hours for Required Action A.2.2 is based on engineering judgment and provides sufficient time to reduce the average* temperature from the highest expected value to s 2126F with procedures. The Completion *Time is with the time provided in LCO 3.0.3 to reach MODE 4 f0om MODE 3. . SR* 3.10.1.1 . .

• The LCOs made applicable are required* to have their Surveillances met to establish that this* LCO being met. A discussion of the applicable is in their ... Bases. 1. American Society of Mechanical Engineers, Boiler and P0essure Vessel Code, XI. 2. UFSAR, Section *.i! B :3°.10-4 Revision No. 131

' ' . '.' ' *-.. Reactor Mode Switch Interlock Testing B 3.10.2 B 3.10 SPECIAL OPERATIONS B 3.10.2 Reactor Mode Switch Interlock Testing BASES BACKGROUND , .... The purpose of this Special Operations LCO is to permit operation of the reactor mode switch from one position to another to confirm certain aspects of associated interlocks* duriDg periodic tests and calibrations in MODES 3, 4, and 5. The reactor mode switch is a conveniently located, multi position, keylock switch provided to select the* necessary scram functions for various plant conditions (Ref. 1). The reactor mode switch selects the appropriate trip relays for scram functions and provides appropriate bypasses. The mode switch positions and related scram interlock functions are summarized as follows: a. Shutdown-Initiates a reactor scram; bypasses main steam line isolation and main condenser low vacuum **scrams; b. . Refuel -Selects Neutron Monitoring System (NMS) scram func:tion for low neutron flux level operation (wide *range neutron monitots and average power range monitor ;setdown scram); bypasses main steam line isolation and .. main condenser low vacuum scrams; II , . *

• c. .Startup/Hot Standby-: Selects NMS scram function for low_ . , neutron flux level operation (wide range neutron *monitors and average power range monitors); bypasses, . /ma in steam l foe i sol at ion and main condenser low 11vac*uum scrams; and . . d: *.*.*Run -Selects NMS scram function for power range .. operation. The reactor mode switch 'al so provides interlocllriterlock testing may consist of .--SurveiJ or*111ay be: the result of -mai.ntenance; ;repafr, or.Jroub]eshoo:tlng In MODE.S 3, 4, and 5,_ the *_interlock functions' provided by the reac:tor;.mode switch in shutdown Ji all control rods inserted and incapable* of : wi :and -refueling. (i refue1 i ng *interlocks -to .. *inadvertent< cri ti ca 11 ty during CORE ALTERATIONS) : * ...
• pos.ittons call be administratively controlled adequately the performance* of .certain tests. * * * * ., _*.,_ . -:*.*. *' '*-.' .-:-* .... * (continued_) , ' I . . -*" ;: .-.:' -. . . ' . .
• B 3.JO"-J *.Revision No. 0 -. . --

• • Reactor Mode Switch Interlock Testing B 3.10.2 BASES (continued) ACTIONS SU RV EI LLANC E . REQUJ RE'MENTS *. *-. * .. -*_";' .PBAPS UN IT 3 ;

• A.l. A.2 .. A.3.1. and A.3.2 These Required Actions are provided to restore compliance with the Technical Specifications overridden by this Special Operations LCO. Restoring compliance will also result in exiting the Applicability of this Special Operations LCO. A 11 AL TERA TI ONS except control rod insertion, if in are immediately suspended in accordance with Requi'red Action A.1, and all insertable control rods in core cells. that contain one or more fuel assemblies are fully inserted withfn 1 hour, in accordance with Required Action A.2. This will preclude potential mechanisms that could. lea_d' to criticality. Suspension of CORE ALTERATIONS shall not preclude the completion of movement of a component to a 'safe *c*ondition. Placing the reactor mode switch in the shutdown position will ensure that all inserted control rods remain. inserted and result in operating in accordance with Table Alternatively, if in MODE 5, the reactor mode switch may be placed in the refuel position, which will also result in operating in a_C:cordance with Tab*le. 1.1-1. A Note is added to Required Action A.3.2 to indicate that this Action onlY applicable MODE 5, since only the shutd.own position is allowed in MODES 3 and 4. The. allowed Completion Time df 1 hour *for Required Action A.2,* Required Action A.3.1; an.ct Action A.3.2 prov.ides s.ufficient time 'io :normally insert the control *rods and.place the reacfor*mode switch in the required position, based on operating experience,* arid j s. acceptable given that all operations that could increase core reacti:vity have been suspended. . . -S R i. 10 . 2 . 1 a n d S R
• 3 .: 10 . 2 . 2 . . .... -' .-... :* . Meeti.ng the .of.this Specla.l Operati ems LCO *ma i.nt*a i rjs opera ti on .cons-i stent. w-i th or conservat 1 ve t.o.
• operating with 'trie r.eactor' mode switch in {he .shutdown
• posit:for,**cor the refuei position for MODE -5). The functiens of tHe switch interlocks that* are not in . effect;*'.'due to tJie festing' 1n. progress, 'are adequately coriipe,nsilted fbr* by. the .. Special Operations LCO requirements. *The *adm.inistrative controls are to be periodically verified to ensure t.hat the .oper.at'iooa l requirements contint/e. to* be met >/The Surveillance Freq:uency is con,troTfed under the * .. Frequency Control* Program.*** *
• Ccontiriued) . ' .. ::.* .. '_,_.,-. * , ** 0. ...... --. *., '*:> Rev i sJ.o n *. N o . 8 7 ._.,_.._ .. *-.*' I BASES (continued) REFERENCES PB A PS UN IT 3 Reactor Mode Switch Interlock Testing B 3.10.2 1. UFSAR, Section 7.2.3.7. 2. UFSAR, Section 14.5.3.3. 3. UFSAR, Section 14.5.3.4. B 3.10-9 * -Revision No. 87. I

.* ,' . "' .... *.* ::_*..,.*_: .. Single Control Rod Shutdown B 3.10.3 B 3.10 SPECIAL OPERATIONS B 3.10.3 Single Control Rod Shutdown BASES. BACKGROUND The purpose of this. MODE 3 Special Operations LCO is to permit the withdrawal of a single control rod for testing while in hot shutdown, by imposing certain restrictions. In MODE 3,. the reactor mode switch is in the shutdown position, and all control rods are inserted and blocked from withdrawal. Many systems and functions are not required in these conditions, due to the other installed interlocks that are actuated when the reactor mode switch is in the shutdown position. However, circumstances may arise while in MODE 3 that present the need to withdraw a single control rod for various tests (e.g., friction tests, scram timing, and coupling integrity checks). These single control rod withdrawals are normally accomplished by selecting the refuel position for the reactor mode switch. This Special* LCO provides the appropriate additional controls . to allow a single control rod withdrawal in MODE 3. AP_PLICABLE * .. With the reactor mode switch in the refuel position, the _SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these are satisfied in MODE 3, these analyses will bound the

• consequences of an accident. Explicit safety analyses *in the UFSAR (Refs. 1 and 2) demonstrate that the.functioning of *the refueling interlocks and adequate SOM will preclude PBAPS UNIT 3 unacceptable excursions. * . ** . . .. . . . . . . ' Refueling interlocks restrict the movement of control rods to'reinforce operationa1 _procedures that prevent the reactor *from. becoming critical. These -interlo.cks .prevent the withdrawal OT more than one control rod .. Under these' . . conditions; since only one control rod can. be withdrawn, .the . be shut down even with the highest worth .* contra 1 rod withdrawn i:'f adequate SOM exists. . . .. The control.rod scram .function provides backup protection to normal refueling procedures and the refueling interlocks, which prevent. inadvertent cri ti ca 1 it i e.s during refue li n*g . .** ( cont'i nued) B 3 .10-10
• Revision* No. o. *. .'_ ..

i, 1* I BASES APPLICABLE SAFETY ANALYSES (continued) LCD PBAPS UNIT** 3 .* Single Control Rod Shutdown B 3.10.3 Alternate backup protection can be obtained by ensuring that five by five array of control rods,-centered on the withdrawn control rod, are inserted and incapable of withdrawal. ,, As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases. As in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 3 with the reactor mode switch in the refuel position can be performed* in accordance with other Special Operations LCOs (i.e., LCO "Reactor Mode Switch Interlock Testing") without meeting this Special Operations LCO its ACTIONS. However, if a single control rod withdrawal is desired in MODE 3, controls consistent with those required during refueling must be implemented and this Special Operations LCO "Withdrawal," in this application, includes the actual withdrawal of the control rod, as well as maintaining the control rod in a position other than the position, and reinserting the control rod. The interlocks.of LCO 3.9.2, "Refuel Position One-Rod-Out Interlock," required by this Special Operations LCO,

• wnl ensure that only one control rod can be withdrawn; To up the refueling interlocks (LCD 3.9.2), the ability to scram the withdrawn control rod in the event of an inadvertent criticality is provided by this Special Operations LCO's.requirements in Item d.l. Alternately, provided a sufficient number of control rods in the vicinity of the withdrawn control rod are known "to be inserted and incapable of withdrawal, Item d.2, the possibility of criticality on withdrawal of this control rod is sufficiently precluded, so as not to require the scram capability of the withdrawn control rod. Also, once this alternate (d.2) is completed, the SDM requirement to account for both the withdrawn untrippable (inoperable) control rod, and the highest worth control rod may be changed to allow the withdrawn untrippable (inoperable) control rod to be the single highest control rod. (continued) B 3.10-11 Revision No. O Single Control Rod Withdrawal-Hot Shutdown B 3.10.3 BASES (continued) APPLICABILITY ACTIONS . ,'-... ** ,_,* Control rod withdrawals are adequately controlled in MODES 1, 2, and 5 by existing.LCOs. In MODES 3 and 4, control rod is only allowed if performed in accordance with this Special Operations LCO or Special Operations LCO 3.10.4, and if limited to one control rod. This allowance is only provided with the reactor mode switch in the refuel position. For these conditions, the interlock (LCO 3.9.2), control rod position indication (LCO 3.9.4, "Control Rod Position Indication"), full insertion requirements for all other control rods and scram functions (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," and LCO 3.9.5, Control Rod OPERABILITY-Refueling"), or the added administrative controls in Item d.2 of this Special Operations LCO, minimize potential reactivity excursions. A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE. 3. Section 1.3, CompJetion Time-s, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed *in the Condition* discovered to be inoperable or n_ot-within limits, will not result in separate entry into the Section 1.3 also specifies *Required Actions of the Condition continue to apply for each . . * -additional failure, _with. Completion .Times based on initial
• entry into-the Condition. *However, the Required Actions for each requirement of.the LCO not met provide _appropriate compensatory measures for separate requirements that are not*
• met.** .A.s s*uch, a NO'te has been provided that -a 11 ows separate entry for e.ach-requirement. of the LCO. . If ohe or of "the -requirements if i ed in this Special Ope.rat.ions LCO_. are .not the ACTIONS applicable to the .* :_stated-requi remen"tS:' of *the affected Leos are immediately*.* entered directed by Req(Jired Action .Required Action A-.i has *been modified by a Note-that-clarifies.the . intent of any other LCO' s Re'qlii red Action to insert a 11 --control rods.-*_ Thi.s _Required Action includes exiting this* -Specjal -Operations* Applicabil_ity by r.eturriing the reactor *--niode,switch *to th_e-shutdown positio_n. *-*A' second Note_ has** . -,:been .. added, _which Clarifies that this Required Acfion is .. -. _, -orily applicable if the requirements.not met are for an. ** .. .. Leo.* * * ** * .... : _.. * ... .. -PBAPS UNIJ_3
• B -. Revision No. 0 _* .. .-** .. -

BASES ACTIONS (continued) SURVEILLANCE REQUIREMENTS :_.. *,*: :PBAPS UNIT 3: -Single Control Rod Withdrawal-Hot Shutdown B 3.10.3 . A.2.'l and A.2.2 Requjred Actions A:2.l A.2.2 are alternate Required Actions that can be taken instead of Required Action A.l to restore compliance with the normal MODE 3 requirements, exiting this Special Operations LCO's Applicability. Act{ons must be initiated immediately to insert all insertable control rods. Actions must continue until all . such: control rods are fully inserted. Placing the reactor mode1switch in the position will ensure all inserted rods remain inserted and restore operation in. accordance with Table 1.1-1. The allowed Completion Time of 1 to place the mode switch in the shutdown positipn sufficient time to normally insert the control r_og s. SR SR 3:10.3.2. and SR 3.10.3.3 The .other LCOs made applicable in this Special Operations LCO required to.have their met to

• establish that this Specfal Operations LCO is being met. If the local.array of control rods is inserted and disarmed .while tfie scram function for the withdrawn rod is not avail?ble, periodic verification in accorda.nce with SR 3-.J0.3.2 i.s required to ,preclude the possibility of criti:,caTity. SR .has been modified by a Note, which clar{f{es that this SR is.not required met if
• SR 3-.. 10.3.l is satisfied** for LCO 3.10.3.d.i requirements, since; SR 3.10.3.2 demonstrates -that the alternative .LCO 3;:10.3.d.2 requirements are Also, *.SR. 3.:11Q.J:3 verifies,, that all control rods other than the contr'61 rod being withdr9wn are fully-inserted. The Survei lTance °Frequency-ts' controlled under the Survei 11 a nee Frequ'ency':Contrc51 -Pro9:ra*ni. -* . -* 1. uFSfl,R;. Section 7 .6 .. **-. I*' . ;:* . 2 . _*u FS AR , Se ct ion 14 , 5 -. 3 . 3 * '.. * .... : -* -. -. . ,. :*._*_ B 3 .10-3 ' .. * -Revi sfon 87 i *_ Single Control Rod Withdrawal-Cold Shutdown B 3.10.4 B 3.10 SPECIAL OPERATIONS B 3 .10. 4 Single Control Rod Withdrawal -Cold Shutdown BASES BACKGROUND of this MODE 4 Special LCO is to permit the withdrawal of a single control rod for testing or maintenance, while in cold shutdown, by imposing certain restrictions. In MODE 4, the reactor mode switch is in the shutdown position,* and all control rods are inserted and blocked from withdrawal. Many systems and functions are not *.required in these conditions, due to the installed . interlocks associated with the reactor mode switch in the shutdown position.
• Circumstances may arise while in MODE 4, however, that present the need to withdraw a single control rod*for various tests (e.g., friction tests, scram time
• testing; and coupling integrity checks). Certain situations may.also require the removal of the associated control rod *drive (CRD). These single control rod withdrawals and possible subsequent.removals are normally accomplished by selecting.the refuel position for the reactor mode switch. APPLICABLE the reactor mode switch in.tile refuel position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are* PBAP:S UNIT '3 -*-. * ' * ' '**. ** --' ** , * < . and, provided the assumptions of these arialyses are *satisfied in MODE 4, these analyses will bound the consequences of an accident. Explicit safety analyses in the.UFSAR (Refs. 1 and 2) demonstrate that the functioning of the refueiing interlocks and adequate SOM will preclude unacceptable reactivity excursions. *
• Refueling interlocks restrict the movement of control rods to*r,'.einforce operational procedures that prevent the reactor These interlocks prevent the
• withdrawal of more than one control rod. Under these conditions, since only one control rod can be withdrawn, the core wi 11 always *be shut *down even with the highest worth control rod withdrawn if adequate SOM exists. The control rod scram function provides backup protection in the . event of normal . ref ue 1 i ng procedures and the ref ue 1 i ng interlocks fail to inadvertent criticalities during . refueling. Alternate backup protection can be obtained by . ensuring that a five by five array of control rods, centered *.on the withdrawn control rod, are inserted and incapable of (continued)* . . ' . . , B *:Revision No. O '"..

'* I,* '*:*** :*,.*.:*. *;1. _, . .. '.: BASES APPLICABLE SAFETY ANALYSES (continued) LCO PBAPS UNIT . Single Control Rod Shutdown B 3.10.4 withdrawal. This alternate backup protection is required when removing a CRD because this removal renders the withdrawn control rod incapable of being scrammed . . As described in LCO 3.0.7, compliance with Special LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs prQvide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases. As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 4 with the reactor mode switch in the refuel position can .be performed in accordance with other LCOs (i.e., Special Operations LCO "Reactor Mode Switch Interlock Testing") without meeting this Special Operations LCO or its ACTIONS. If a *single control rod withdrawal is desired in MODE 4, controls consistent with those required during refueling must be implemented and this Special Operations LCO applied. "Withdrawal," in this application, includes the actual withdrawal of the control rod, as well as maintaining-the control rod in a position other than the position, and reinserting the control rod.

• The refueling interlcicks of LCO 3.9.2, "Refuel Position* One'.""Rod-Out Interlock," required by this Special Operations LCO .will ensure that* orily one control rod can be At the time CRD removal begins, the disconnection of the
• posttion indication probe will cause LCO 3.9.4, "Control Rod Position Indication, .. -and therefore, LCO 3 *. 9.2 to fail to be .* met. _ Therefore, prior :to commencing CRD removal, a control rod withdrawal block.is required to be inserted to* ensure** . that no additional control rods can be withdrawn and. that . compliance with this: Special Oper.ations LCO
• To back up the interlocks (LCO 3.9.2) or the _*. * .. _. control rod withdrawal block, the ability to scram the ... *.*.*.
• withdrawn control rod in the event of an_ inadvertent . criticality is-provided by the Special Operations LCO _ reql!irenients in Item c.l. Alternatively, when the. scram (continued) B .*Revision No. -o: _*. .* ....

BASES LCD * (continued) *APPLICABILITY ACTIONS .. -PBAPS UNIT J Single Control Rod Withdrawal-Cold Shutdown B 3.10.4 function is not OPERABLE, or when the CRD is to be removed, a sufficient number of rods in the vicinity of the withdrawn control rod are required to be inserted and made incapable of withdrawal {Item c.2). This precludes the possibility of criticality upon withdrawal of this control rod. Also, once this alternate {Item c.2) is completed, the SOM requirement to account for both the withdrawn untrippable {inoperable) control rod, and the highest worth control rod may be changed to a 11 ow the withdrawn untri ppab 1 e {i noperab 1 e) control rod to be the single highest worth control rod. Control rod withdrawals are adequately controlled in MODES l, 2, and 5 by existing LCOs. In MODES 3 and 4, control rod withdrawal is only allowed if performed in accordance with Special Operations LCO 3.10.3, or this ,* Special Operations LCO, and if limited to one control rod. This allowance is only provided with the reactor mode switch in the refuel position. During these conditions, the full insertion requirements for all other control rods, the one-rod-out interlock {LCQ 3.9.2), control rod position indication (LCO 3.9.4), and scram functions {LCO 3.3.l.l, "Reactor Protection System {RPS) Instrumentation," and LCD 3.9.5, "Control Rod OPERABILITY-Refueling"), or the added administrative controls in Item b.2 and Item c.2 of this Special Operations Leo,: provide mitigation of potential reactivity excursions. A Note has been provided to modify the ACTIONS related to a single control rod withdrawal while in MODE 4. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3.also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for each;requirement of the LCD not met provide appropriate compensatory measures for separate requirements that are not

• met. As such, a Note has been provided that allows separate Condition entry for each requirement of the -LCD. (continued) B 3.10-16 Revision No. 0
• . , .. ---.. . *i' .-* BASES ACTIONS (continued) .* .. :" .* :'-.. *. Single Control Rod Shutdown B 3.10.4 A.I; A.2.I. and A.2.2 If one or of the of this Special Operations LCO are not met with the affected control rod insertable, these Required Actions restore operation consistent with normal MODE 4 conditions (i.e., all rods inserted} or with the exceptions allowed in this Special Operations LCO. Required Action A.I has been modified by a Note that clarifies that the intent of any other LCO's Required Action is to insert all control rods. This Required Action includes exiting this Special Applicability by returning the reactor mode switch to the *shutdown position. A second Note has been added to Required Action A.I to clarify that this Required Action is only applicable if the requirements not met are for an affected LCD *. Required Actions A.2.I and A.2.2 are specified, based on the assumption that the control rod is being withdrawn. If the control rod is still insertable, actions must be immediately initiated to fully insert all insertable control rods and withiti I hour place the reactor mode switch in the Shutdown positio*n. Actions must continue until all such control rods are .fully inserted. *The allowed Completion Time of I hour *for plaCing the reactor mode*switch in the.shutdown position _provides sufficient time.to normally insert the control.
• and B.2.2 .... If one**or more of the. of this Special Operatipns LCD. are not met with-the affected control rod not fosertab,le;. withdrawal of the co'ntrol rod.*and removal of the , associated must be immediately suspended. If the CRD has been removed, sudi that the control rod "is not. . .
• Actions requjre the most * -..
• actiol') "be_ taken to_ either action to.* restorE! the CRD. and insert: its cont.rel rod.; or initiate
• c** :*action to .. restore compliance with this.Special Operations LCD.*. . *.* . * .* . -.. -(continued) ,' .. --***" '.: .. :,::* .. ,.**. . -** .. *,. ,;_ .'.* .... * .,. -.Revision No. O I .. .. :°'-* Single Control Rod Withdrawal-Cold Shutdown B 3.10.4 BASES (continued} SURVEILLANCE REQUIREMENTS ',_., REFERENCES '-'*. . '* ,* .. .-: . ,*' *.-,, *, : .... SR 3.10.4.1. SR SR 3.10;4.3. and SR 3.10.4.4 The LCOs made applicable by this Special Operations LCO are to their associated surveillances met to establish that this Special Operations LCO is being met. If the local array of control is inserted and disarmed while: the scram function for the withdrawn rod is not periodic verification is required to ensure that possibility of criticality remains precluded. Verification that all the other control rods are fully is required to meet the SOM requirements. Verifjcation that a cpritrol rod withdrawal block has been inserted ensures that nrj other control rods can be i n a dv e .rt e n t l y wit h d r aw t1 u n de r c 0 n d i t i 0 n s w h en p 0 s it i 0 n indication instrumentation is inoperable for the affected cohntsrol r?d1. The Surveillance Fre1 quency is controlled under I**. t e Frequency Contra Program: SR'3:lci.4.2 and SR 3.10.4.4 have been modified by which. clarify that these* SRs are not required to be met if the demonstrated by SR 3.10.4,1 are satisfied. L UFS_AR, Section 7.6.4; 2, *.u FSAR, Sect i6n 14.5.3.3. -** .,** .. ..:_. ;, .-:-... ' --' ,.. .* ',. ----*-, "-.--* -._ .,_ :. . . : *' .. -:' _* -__ . -,**, . .... :** ' *B 3/10-18
• 87 ,*_*-.

Single CRD Removal-Refueling B 3.10.5 B 3.10 SPECIAL OPERATIONS B 3 .10.5 Sirigl e Control Rod Drive (CRD) Removal-Refueling . . BASES. BACKGROUND ',' -' UNIT>3 : f". -: ***-,:. :. ---The purpose of this MODE 5 Special Operations LCO is to perniit the removal of a single CRD during refueling operations by imposing certain administrative controls. Refueling interlocks restrict the movement of control rods and the operation of the refueling.equipment to reinforce operational procedures that prevent the reactor from becoming critical during refueling operations. During refueling operations, no more than one control rod is permitted to be withdrawn from a core* cell containing one or* more fuel assemblies. The refueling interlocks use the* 11full-in11 position indicators to determine the position of all control rods .. If the "full-in" position signal is not present for every control rod, then the all .rod.s in permissive for the refueling equipment interlocks is not present and fuel loading is prevented. Also, the refuel position one-rod-out interlock will not allow the withdrawal of a second control rod. The control rod scram function provides backup protedion in the event normal refuel i ilg procedures' and the refueling .. *interlocks describec;t abo.ve fail to prevent inadvertent criticalities during refueling. The 'requirement for this function* to be OPERABLE precludes the possibility of removing the CRD once a control rod is withdrawn from a core cell containing one or more fuel assemblies. This Special* LCO controlS sufficient to -ensure the pos.sibil ity of an inadvertent criticality is precluded, . wh.i l e a 11 owing* a single CRD to be. removed from a core eel l. containing one or more fuel assemblies. The removal of the CRD involves disconnecting the position indication probe, which causes noncompliance with LCO 3.9.4, "Control Rod

• Position Indication," and, therefore, LCO 3.9.l, "Refueling Equipment Interlocks;11 and LCO 3.9.2, "Refueling Position One"'.Rod-Out Interlock." The CRD removal also requires isolation of the CRD from the CRD Hydraulic System, thereby causing i noperabi li ty of the control rod. ( LCO 3. 9. 5; "Control Rod OPERABILITY:_Refuel ing") * (continued) .*.* -. :: . ' -__ ::;:: . . . B 3A0-19 .* .Rev*ision 0 * ***-; . *, *_:..

... -. -, *. '*' BASES (continued) Single CRD B 3.10.5 APPLICABLE With the reactor mode switch in the refue*l position, the SAFETY ANALYSES analyses for control rod withdrawal during refueling are applicable and, provided the assumptions of these analyses are satisfied, these analyses will bound the consequences of accidents. Explicit safety analyses in the UFSAR (Refs. l and 2) demonstrate that proper operation of the refueling interlocks and adequate SDM wil 1 preclude unacceptable reactivity excursions. ., *.' . *'* .* .. ' ... . PBAPS UNIT 3 *'* Refuel1ng interlocks restrict the movement of control rods and the operation of the refueling equipment to reinforce operational procedures that prevent the reactor from . becoming critical. These interlocks prevent .the withdrawal of more than one control rod.

• Under these conditions, since only one control rod can be withdrawn, the core will always be shut down even with the highest worth control rod withdrawn if adequate SDM exists. By requiring all other control rods to be inserted and a control rod withdrawal block initiatedJ the function of the inoperable one-rod-out interlock (LCO 3.9.2) is adequately maintained. This Special Operations LCO requirement to suspend all CORE ALTERATIONS adequate 1 y compensates for the inoperable all rods in permissive for the refueling equipment interlocks (LC03.9.l) . (continued} 8 3.10-20--* Revision. NO. O .* ... *.*. . ! !

"" ... *. Single CRD B 3.10.5 BASES . (continued) LCD APPLICABILITY * -PBAPS UNIT 3 . As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Operation in MODE 5 with any of the following LCOs, LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," LCO 3.3.8.2, "Reactor Protection System (RPS) Electric Power Monitoring," LCO 3.9.1, LCO 3.9.2, LCO 3.9.4,, or LCO 3.9.5 not met, can be performed in accordance with the Required Actions of these LCOs without meeting this Special Operations LCO or its ACTIONS. However, if a single CRD removal from a core cell containing one .or more fuel assemblies is desired in MODE 5, controls consistent with those required by LCO 3.3.1.1, LCO 3.3.8.2, LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, and LCO 3.9.5 must be implemented, and this Special Operations LCO applied. By_requiring all other control rods to be inserted and a control rod withdrawal block initiated, the function of the inoperable one-rod-oOt (LCO 3.9.2) is adequately maintained. This Special Operations LCO requirement to suspend all CORE ALTERATIONS adequately compensates for the inoperable all rods in permissive for the refueling equipment interlocks (LCO 3.9.1). Ensuring that the five by five array of control rods, centered on the withdrawn control rod, are inserted and incapable of withdrawal adequately satisfies the backup protection that LCO 3.3.1.1 and LCO 3.9.2 would have otherwise provided. Also, once these requirements (Items a, b, and c) are completed, the

• SOM. requirement to account for both the withdrawn untrippable (inoperable) control rod and the highest worth control rod may be changed to allow the withdrawn untrippable (inoperable) control rod to be the single highest worth control rod. Operation in MODE 5 .is controlled by existing LCOs. The allowance to comply with this Special Operations LCO in lieu of the ACTIONS of LCO 3.3.1.1, LCO 3.3.8.2, LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, and LCO 3.9.5 is appropriately controlled with the additional administrative controls required by this Special Operations LCO, which reduce the potential for reactivity excursions. (continued) B 3.10-21 Revision No. 0

': Single CRD Removal-Refueling B 3.10.5 BASES ACTIONS A.1. A.2.1. and A.2.2 SURVEILLANCE REQUIREMENTS ...... ' * .. :. PBAPS UNIT 3 If one or more of the requirements-of this Special Operations LCO are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements for failure to meet LCO 3.3.1.1, LCO 3.9.1, LCO 3.9.2, LCO 3.9.4, and LCO 3.9.5 Ci .e., *all control rods inserted) or with the allowances of this Spectal Operations LCO. The Completion Times for Required Action A.l, Required Action A.2.1, and Required Action A.2.2 are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious manner to either initiate action to restore the CRD and insert its control rod, or initiate action to restore. compliance with this Special Operations LCO. Actions must continue until either Required Action A.2.1 or Action A.2.2 is satisfied. SR 3.10.5.1. SR 3.10.5.2. SR 3.10.5.3. SR 3.10.5.4. and SR 3.10.5.5 Veri fi ca ti on that all_ the control rods, other than the contr.ol rod withdrawn for the removal of the asSOGiated CRD, are fylly inserted is required to ensure. the SOM is w_ithin limits-. Verification that.the local five by five array of control. rods: other than 'the control rod Wi thdrawil for reriloval.-of the associated CRD, is inserted and disarmed, ,* whi*l e *the scram function* for the w'i thdrawn rod is not required to ensure that.the possibility of criticanty rema1ns precluded. Verification that a control rod withdrawal .block has be_en i iiserted enst,Jres,, that* no other co*ntrol. -rods can. be inadvertently :Withdrawn* under conditions whe'n position*. in-di cat ion i nstrume.ntat i oh i's i rioperable for the withdrawn drntrbl rod:;

• The Surveillance for LCO ;. which is m9de -applic?ble*.by this *special Operations LCO, is *.* r::eqlri-.r.e9 in or:.der tq>es:t'abli sh that' thfs _Spedal Operations LCO is; being met.< Verification that nb other CORE. * * :. ft,LTERt\TtON.S aTe* being made fs re.qui red t6 erisure the assumptions .of the safety irnalysis are saf1sfied. Per tS di. c *.v eri f-;l cat i *a*n: of . the ad mi n i strati v e
• control s *establisheqby this Special Operations LCO* is*prudent to* prec}ud e .. pas s.i bi l ity. n 1 n ad ve r.tent *.critical i ty The Surve*i 11 a nee Frequency is coritro:li'ed under the, Surveillance Frequency Contr'ol Program. * * ** * * * * :. -*-.* _: .. ; , ***. : .. " '* .. ** * * (cont1nued) .,*, .. Revision No. 87 ;: .

. BASES (continued) REFERENCES 1. UFSAR, Section 7.6.4 . . 2 .. *. UFSAR, Section *. *, -...... .. -, -*. -*-. -: -.'*.;: -' *' ' :'**, *, '*. -' -* . . *.--:* .. :', :'.' ___ ,.

• PBAPS-UNIT 3* . *-B 3 .J0-23 :---.. -.. . --: -Single CRD B 3.10.5 o I--. I I Multiple Control Rod Withdrawal-.,..Refueling . B 3.10.6 B 3 .10 SPECIAL OPERATIONS B 3.10.6 Multiple Control Rod . BASES. BACKGROUND APPL'!CABLE SAFETY ANALYSES PBAPS UNiT*J' *_ **-.-. :: . The purpose of this MODE 5 Special Operations LCO is to *permit multiple control rod withdrawal during refueling by imposing certain administrative .controls . . Refueling interlocks restrict the movement of control rods and the operation of the refueling equipment to reinforce **ope rational procedures that prevent the reactor from *becoming critical during refueling operations. During refueling operations, no more than one control rod is permitted to be withdrawn from a core*cell containing one or more fuel assemblies. When all four fuel assemblies are removed from a cell,the control rod may be withdrawn with no restr1ctions. Any number of control rods may be withdrawn and removed from the reactor vessel if their cells contain no fuel. * *
• The refueling use the "full-in" position indicators to determine the position of all control rods. If the "full-in" position s*ignal is not present for every control rod, then the all in permissive for the ref(Je ling equipment interlocks is riot *.present and fuel loading is prevented. Also, the refuel position one-rod-out inter 1 ock wil 1 -not a 11 ow the wi thdrawa 1 of a: second cont ro 1 . Til.* al 1 o.w more than one contra l rod to be withdrawn during . refueling, these interlocks must be defeated .. This Special OperatiOns LCO establishes the necessary administrative* controls to allow* bypassing the "full-in" position ind it at ors. . * * *
• Explicit .safety analyses in the *uFSAR (Refs. 1, 2, and 3} .. demonstrate that the functioning of the refueling interlocks and adequate SDM will-prevent unacceptable reactivity excursions during refueling. To allow. multiple control rod withdrawals, control. rod removals, associated rod drive (CRD) removal, or any combination of these, the "full in ... -position indication is allowed to be bypassed for each withdrawn control rod if all fuel has been removed from the* cell. With no.fuel assemblies in the core cell, the . -. . .. (continued) . . ' B 3:.10-24 * *. Revision No. o * *
• '",,:;.*. BASES APPLICABLE SAFETY ANALYSES (continued) LCO .. ... '"* -.,,--PBAPS UNIT.3 Multiple Control Rod Withdrawal -Refueling B 3.10.6-associated control rod has no reactivity *control function and. is not required to remain inserted. *-Prior to re 1 oad ilig fue 1 . into the ce 11 , however, the associated contro 1. rod must . be inserted to ensure that an iriadvertent criticality does not occur, as evaluated in the Reference 3 analysis. As described in LCD 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by
• appropriately modifying requirements of other LCOs. A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases.
• As described in LCO 3.0.7, compliance with this Operations LCO is optional. Operation in MODE 5 with either LCO 3.*9.3, "Control Rod Position," LCO 3.9.4, "Control Rod Position Indication," or LCO 3.9.5, "Control Rod OPERABILITY-Refueling, 11 not met, ca*n be performed in accordance with the Required Actions of these LCOs without. meeting this Special Operations LCO or its ACTIONS. If multiple control rod withdrawal or removal, or CRD removal . is desired, all four fuel assemblies are required to be* removed from the associated cells. Prior to entering this LCO, any fuel remaining in a cell whose CRD was previously .'. removed under the provisions of another lCO must be removed. "Wi thdrawa 1," in this application, i nc.l udes the actuaJ * .* withdrawal of the control rod, as well as maintaining the control rod ,;n a positi6h other thah the full-in and reinserting* the* control rod.* , *
• Wheri::fuel is lo.aded into the core with multiple control. rods .*. special modified. quadrant spiral reload sequences *are used to ensure that reactivity additions are Spira 1 reloading encompas*ses reload irig a ce 11 . (four fue 1 . *1ocations .immediateiy*adjacent to a control rod) on the edge* . of a. continuous : fue 1 ed region (the ce 11 .. can be 1 oaded in any . . sequence)! Otherwise*, al 1 control rods*.must be fully.* : inserted before 1 oadi ng fuel. . ; . (continued) . :::*** . B 3.10-25. . '

BASES (continued) APPLICABILITY . ACTIONS SUR V EI L LANCE REQUIREMENTS REFERENCES . PBAPs:uNIT 3 Multiple Control Rod Withdrawal-Refueling B 3.10.6 Operation in MODE 5 is controlled by existing LCOs. The exceptions from other LCO requirements (e.g., the ACTIONS of LCO 3.9.3, LCO 3.9.4, or LCO 3.9.5) allowed by this Special LCO *are appropriately controlled by requiring all fuel to. be removed from cells 'whose "full-in" indicators are allowed to be bypassed . A.l. A.2. A.3.1. and A.3.2 If one or more of the requirements of this Special Operations LCO are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements for refueling (i.e., all control rods inserted in core cells containing one or more fuel assemblies) or with the exciptions granted by this Special Operations LCO. The Completion Times for Required Action A.l, Required Action A.2, Required Action A.3.1, and Required Action A.3.2 are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious to either initiate action to restore the affected CRDs and insert control rods, or initiate action to restore compliance with this Special Operations LCO. SR 3.10.6.1. SR 3.10.6.2. and SR 3.10.6.3 Periodic verification of the.administrative controls established by this Special Operations LCO is prudent to preclude the possibilfty of an inadvertent criticality. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. UFSAR, Section 7.6;4. 2. UFSAR, Section 14.5.3.3. 3. UFSAR, Section 14.5.3.4 . B 3.10-26 Revision No. 87 Control Rod Testing-Operating B 3.10.7 B 3 .10 SPECIAL OPERATIONS , B,3.10.7 Control Rod Testing-Operating BASES BACKGROUND The purpose of this Special Operations LCO is to permit control rod testing, while in MODES 1 and 2, by imposing certain administrative controls. Control rod patterns during startup conditions are controlled by the operator and the rod worth minimizer (RWM) (LCO 3.3.2.1, "Control Rod Block Instrumentationn), such that only the specified control rod sequences and relative positions required by LCO "Rod Pattern Control," are allowed over the operating range from all control rods inserted to the low power setpoint (LPSP) of the RWM. The sequences effectively limit the potential amount and rate of reactivity increase that could occur during a control rod drop acc.ident (CRDA). During these conditions, control rod testing *is sometimes requi.red that may result in contra l rod patterns not in compliance with the prescribed sequences of .LCO 3.1.6. These tests include SDM demonstrations, control rod scram time testing, control rod friction testing, and testing performed during the Startup Test Program. This Special Operations LCO provides the necessary exemption to the of LCQ 3.1.6 and additional .. administrative controls to allow the dev.iations in such

• tests from the prescribed: sequences in LCO 3 .1. 6. APPLICABLE' The methods and.assumptions used in evaluating , SAFETY ANALYSES
• the: CROA are summarized itt References l and 2. CRDA *. . . *:. _ .. : ' : . **. ' : ' _.,-._*.:*; . .**-. -. *. : . PBAPs.**uNIT.3 anal}'se's assume' the reactor operator follows prescribed *w.i:thdrawa 1 . seqljences. The.se sequences '.defi ne***the
• potenti a 1 .iilitial for .. the CRDA analyses. The RWM provides** . . backup" to. op.erator :control of the withdrawal sequences to ensure tbe init.ial qmditiQn*s .of the CRDA analyses are :not , vi
• For: specia 1 sequence's developed for control rod *testing,*: the* ifii.ti al contra 1 rod. patterns in the *
• References I and. 2 may not .. be .preserved. Therefore.special CRDA an*a *.are*, req*uired to demonstrate . that these special 'sequences will. not result in unacceptable
• consequences;*should.a CRDA occur during the testing. Tt:iese performed in with an NRC approved
• methodology, are ciependent on* the specific test :being . perf6rmed. * * * * * ' .. *":, ,_ ,.*** '.ff 3 .10-27 .. * *Revision No .. O*

BASES APPLICABLE SAFETY .ANALYSES (continued)

• LCO . APPLICABILITY -' . -, : '., *' : . *_ _:. . ., . '. PBAPS-'UNIT 3: Control Rod B 3.10.7 As described in LCO 3.0.7, compliance with Special . Operations LCOs is optional, and therefore, no criteria of *the NRC Policy Statement apply. Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs. A discussion of the satisfied for the other LCOs is provided in their respective Bases. As described in LCO 3.0.7, compliance with this Special Operations LCO is optional. Control rod testing may be performed in compliance with the prescribed sequences of LCD 3 .1. 6, and during* these tests, no exce,pt ions to the requirements of LCO 3.1.6 are necessary. For *testing performed with a sequence not in compliance with LCO 3.1.6, the requirements of LCO 3 .1. 6 may be suspended, provided additional administrative controls are placed on the test to ensure that the assumptions of the special safety analysis for the test sequence are satisfied. Assurances that the test sequence is followed can be provided by either
• programming the. test sequence into the RWM, with conformance verified as specified *in SR 3.3.2.1.8 and allowing the RWM to*monitor control rod withdrawal and provide appropriate control rod blocks if necessary, or by verifying conformance to the approved test sequence by a second .licensed operator 'or other qualified member of the technical *staff. These controlS are consistent with those normally applied to
• operatfon in the startup range. as defined in the SRs and of LCO 3.3.2.1, "Control Rod Block Instrumentation." **,-Control r:od testing, while in MODES 1 and 2; with THERMAL
• _ POWER, .greater than 10% .RTP, is adequately controlled by the existing Leos on power distribution -limits_ and control rod block rod during these
• conditions is -riot restri.c:t:ed to prescribed-sequences and can be performed wfthin. the.constraints "AVERAGE -PLANAR.LINEAR-HEAT GENERATION RATE (APLHGR), 11 LCD 3. 2*. 2, -POWER RATIO (MCPR)' II LCO 3.2.3, "LINEAR -, . )!EAT.GENERATION AATE (lHGR),"-.and* LCO -With*THERMAL *POWER _less than-*m<equal .to 10%. RTP, the .provtsions*of this **Sped al Operations JCO are -necessary to perform -*. * ' tests' that are riot in tonforinance with 'the.-prescribed . o( LCD 3.1.6. Wh.ile in MODES 3.and 4,-control rod
• wi tbdrawa 1 is only al l_owed ; f performed in accordance with ' -.-. 'r . . .* .* .(continued} *._:, , , , B 3_:10-28 Revi si.on No*. o *-.-.,.

1. BASES APPLICABILITY (continued) ACTIONS. : SURVEILLANCE REQUIREMENTS .. PBAPS. lJN IT 3 . -*-*."* .,. Control Rod Testing-Operating B 3.10.7 Special Operations LCO 3.10.3, "Single Control Rod Withdrawal-Hot Shutdown," or Special Operations LCO 3.10.4, "Single Control Rod Withdrawal-Cold Shutdown," which provide adequate controls to ensure that the assumptions of the safety analyses of Reference 1 and 2 are .satisfied. During these Special Operations and while in MODE 5, the one-rod-out interlock (LCO 3.9.2, "Refuel Position One-Rod-Out Interlock,") and scram functions (LCO 3.3.1.1, "Reactor.Protection System (RPS). Instrumentation," and LCO 3.9.5, "Control Rod OPERABILITY-Refueling"}, or the added administrative controls prescribed in the applicable -Special Operations LCOs, .pro vi de mitigation of potential reactivity excursions. With the requirements of the LCO not met (e.g., the control rod pattern is not in compliance with the special test the sequence is improperly loaded in the RWM) the testing is required to be immediately suspended.* Upon suspension of the special test, the provisions of LCO 3 .1. 6 are no longer excepted, and appropriate actions are.to be taken to restore the control rod sequence to the prescribed sequence of LCO 3.1.6, or to shut down the reactor, if required by LCO 3.1.6. . SR 3.10.7.1. With the special test sequence not programmed irito the RWM, a: second .. 1 i censed operator or other qualified member of the

• iri accordance with an approved training program for this test) is required to verify conformance w1th the approved sequence for the test . . This verification must be performed during control rod *movement to ptevent deviations from the specified sequence. A Note is*added to indiCate that this Surveillance does not need to be met if SR 3.10.7.2 is satisfied. ' ' ' (continued) *_3.** . Revision O
  • , :*-* BASES SURVEILLANCE REQUIREMENTS (continued) I . -_*, PBAPS .UNIT. '3 .*****=' Control. Rod Testing-Operating B 3.10.7 SR 3.10.7.2 the *RWM provides conformance to the special test sequence, the test sequence must be verified to be correctly l.oaded 'into the RWM prior to control rod movement. This Surveillance demonstrates compliance with SR 3.3.2.1.8, therepy demonstrating that the RWM is OPERABLE. A Note has been added to indicate that this Surveillance does not need to be met if SR 3.10.7.1 is satisfied. 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision. i. Letter from T. Pickens (BWROG) to G.C. Lainas (NRC) ;'Amendment 17 to General Electric Licensing Topical Report NEDE-24011-P-A," August 15, 1986 . ' .. _,, . . B 3.ld__:_io .*.Revision No. 73*

I SOM Test-Refueling B 3.I0.8 8 3.IO SPECIAL OPERATIONS 8 3. IO .8 SHUTDOWN MARGIN (SOM) Test-Refueling BASES BACKGROUND APPLICABLE SAFETY ANALYSES PBAPS UNIT.3 The purpose of this MODE 5 Special Operations LCO is to permit SOM testing to be performed for those plant configurations in which the reactor pressure vessel (RPV) head is either not in place or the head bolts are not fully tensioned. LCO 3.1.I, "SHUTDOWN.MARGIN (SOM)," requires that adequate SOM be demonstrated following fuel movements or control rod replacement within the RPV. The demonstration must be performed prior to or _within 4 hours after criticality is reached. .This SOM test may be performed prior to or during tHe first startup following the refueling. Performing the SOM test prior to startup*requires the test to be performed while in MODE 5, with the vessel head bolts less than fully tensioned (and possibly with the vessel head removed). While in MODE 5, the reactor mode switch is required to be in the shutdown or refuel position, where the applicable control rod blocks ensure that the reactor will not become critical . -The SOM test requires the reactor mode switch to be in the startup/hot standby position, since more than one control rod will be withdrawn for the purpose of . demonstrating adequate SDM. This Special Operations LCO provides the appropriate additional controls to allow withdrawing more than one control rod from a core cell containing one or more fuel assemblies when the reactor vessel head bolts are less than-fully tensioned. Prevention and mitigation of unacceptable reactivity excursions during control rod withdrawal, with the reactor mode switch in the startup/hot standby position while in MODE 5, is provided by the wide range neutron monitor (WRNM) peri ad-short scram ( LCO 3. 3. I. I, "Reactor Protection System (RPS) Instrumentation"), and control rod block instrumentation (LCD 3.3.2.I, "Control Rod Block Instrumentation"). The limiting reactivity excursion during conditions while in MODE 5.is the control rod drop accident (CRDA}. {continued) B 3.I0-3I Revision No. 17

*;. I -..... ' . ***.:, .. , . .-**:: *;_ ;.** . -:*, . . . *' :*:' . ***.-* i -.* ' *._ .. ,--. BASES APPLICABLE .*SAFETY -ANALYSES (continued) . ,;.-.'. ,, . "\ .. .* .. . .* ' .. '* ..... *.,I **,i---> .* .... SOM Test -Refueling 8 3.10.8 CRDA .analyses assum*e that the reactor operator follows prescribed withdrawal For SOM tests performed .within these defitied*sequences, the analyses of References 1 and' 2 .are.applicable. However, for some sequences developed for the SOM testing, the. control rod patterns assumed in the safety an_alyses of References 1 and 2 may not be met. Therefore, spec'i al CRDA analyses, performed in accordance an NRC approved methodology, required to demonstrate. the SOM test .sequence will not result in consequences should a tRDA 6ccur during the For the purpose of this test, the protection . provide(j by the normally required MODE 5 applicable LCOs, in addition to the requirements of this LCD, will maintain normal test operations .a*s well a*s postulated accidents bounds of the appropriate safety analyses * (Refs: larid'.2); Iri:addition to the added requirements for the RWM, WRNM-, APRM, and control rod coupling, the notch out .mode for otit pf withdrawals.-. Requiring the nbtch out mode limits withdrawal steps to a sing'l{notch: which.limits_ inserted reactivity, and allows . aclequat_e 'monitoring-of changes in neutron flux, which may _ :occur .. 9uri n*g the tesL _ .. -As<descri_bed ;in LCD 3:o.v>compl;ianc:e with Special _ Operations *LCOs is optionaT, and therefore, 'no<criteriaof . '.*.the* *.*.NRC Policy Statenienf apply:* Special Op er at ions tCO's * * . *providff:flexibilit.Y-to'perform certain operations by --. at>rl'ropt'.'.latelY *modifyfog reqtiiremenls of oth_er LCOs .. A *. -. _*'di scu.s'sion .of :the -criterta. ..

• satisfi:ed for. the other lCOs is provided in their respective Bases. ' , -' ' > .1 * *: <. .,*.* .*.,: Leo*.>.,, ** ** * .l{s ih -lCO 3,.'(L'J;. comp-i*-i'ance -Special: * -Opef,afions {CO 'is' _opt fona.l ;
• SOM may be performed : .* .-'. while jn with Table Ll-1; without _. . --... * :*;* : --LCO-ar*-irs**AcTIONS0;:*rar*suM __ .-_* * \ -* .... _-.. _. __ tests*;::p$Y'f9rmed whiJe'i_rf MODE 5, additi.onal :requirements._;_:** . , ... . . ' ..... '* ,,. *,, __ .*:.:. . .-*. -. _>:-, * **:inu-sfJie against _. *-. * *--*. * -.. is Jo p*rov.i;de : ----. :.-** . -,_ .. . \ .. _ .. ' ,. ' . .,. *-. ' ,: . ,:.:.._ ':-... , .. add.rti onaJ s'cr(lin; protecfj"on beypnd .no:Y'll)alJY , * *>.WRNMs are al sq reqlilred to be OPERABLE ( LCO --.. .
• 3 ;3 .J'!'l/ fµnc\1ons:.'2A,* 2 .-d, .ahd 2.e) as though**.the rea;cto*r*. -* 2. : Because,*mulJiplf control rods will *** _ .. -:wi theL reactor :_wi l r potentially _become crrttca l, *:'the' *approved _control rod _w.i t_hd-rawal sequence must be . ** * -* en-forced* ttie RWM '( LC0.-.3-. 3*. 2 .. 1,' function 2, MODE 2) ,<cir must< be verified by a '. .. _-. " ' .:* . . . .. *.:-.* <, -, _.i:* '"t*' .< -*-,, -.. '*>. ..... :-: .... "' _ ... . -: -*.* -. _: ( cont_i nued) -**----.-, . . Revision '"*'*., " :*'"" .. t:, . . . . . -. _._, '* :, *. --. _,.,_ *****.*-*. ... -_; . .-... . -.-'!: .' ****: . *:1 ---

I* . i BASES LCO (continued) APPLICABILITY ACTIONS \ SOM Test-Refueling B 3.10.8 second or other qualified member of the technical staff. To provide addit.ional protection against an inadvertent criticality, control rod withdrawals that do not conform to the analyzed rod position sequence specified in LCD 3.1.6, "Rod Pattern Control," (i.e., out of sequence control rod withdrawals) must be made in the individual notched withdrawal mode to minimize the potential reactivity insertion associated with each movement. Coupling integrity .of withdrawn control rods is required to minimize the probability of a CRDA and ensure proper functioning of the withdrawn control rOds, if they are required to scram. Because the reactor vessel head may be removed during these tests, no other CORE ALTERATIONS may be in progress. Furthermore, since the c6ntrol rod scram function with the RCS at atmospheric pressure relies solely on the CRD accumulator, it that the CRD charging water remain pre5surtzed. This Special Operations LCD then . changing the Table 1.1-1 reactor mode switch position requirements to include the startup/hot standby position, such that the SOM may be performed while in MODE 5. . . These SOM test Special Operations are only if the.SOM tests are to be performed while MODE 5 w.i th the reactor* vessel head removed. or the head . bolts hot fully tensio.ned. Additional requirements during to enforce rod sequences and restrict other CORE AL TERAJIONS provide pr"otecti on against reactivtty excursions, Operations in all other MODE*s. are unaffected* by this LCD. *

• With one :or tnor.r{ c6ntr.of rods discovered.uncoupled during this Speclal inserti.on of each*. uncoupleCt control rod-is* required; either to attempt rec:ou'pi{n_g*, o_r. to preclude' a control* rod drop.: This. c*onfrol}e_d* 'i nserti.on i si nee, iJ the* cont r01 rod falls to* follow the:drive.as it is with.drawn Ci:e .* , i>s .* in an inserted positi*on); plac;:ing the reador mode switch :in t.he*s*hutdown position*per Req_uired .. Actio_n B.1 **could c;ause substanti_al secondary dainage> _*If recoupling i,s * ... not *accomplished, <o*peratio"n may provided the* ** .... *. control .rods ar{ fully i nseTt*e'd within *3 hours and di sarnied cir hydraulically) within 4 hours: Inserting a* (continued) . . ,' -.-.-** .... -. : . B 3.10-33 Revi.si on' NO. 64 -. '

. *BASES ACTIONS . ..;_* . PBAPs*. UNIT 3 SOM . B 3.I0.8 A.I and A.2 (continued) control rod ensures the shutdown and scram capabilities are

• not adversely affected. The control rod is disarmed to prevent inadvertentwithdrawal during subsequent operations. The control rods can be hydraulically disarmed by closing the drive water and exhaust water valves. Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve solenoids.* Required Action A.I is modified by a Note that .allows the RWM to be bypassed* if required to allow insertion of the inoperable control rods and continued operation.
• LCO 3.3.2.I, "Control Rod Block Instrumentation," ACTIONS provide additional requirements when the RWM is bypassed to ensure compliance with the CRDA analysis. . ' . The allowed Completton Times are considering the small number of allowed inoperable control* rods, and provide time to insert* arid disarm the control rods* in an orderly* manner and without challenging plant systems. Condition A is modified bY a Note allowing separate Condition entry for each uncoupled control rod .. This is. acceptable since the Required Actions for this Condition. provide appropriate compensatory actions 'for each uricoupled control rod. Complying with the Required Actions.may allow for continued operation. Subsequent uncoupled control rods are* governed by subsequent entry into the Cond.i ti on and appljcation Df the Required Actions. With one or more of. the requirements of this LCO not met for . reasonsother than an uncoupled control rod, the testing should be immediately stopped by placing the reactor mode switch in shutdown or refuel position. This results tn a condition that is consistent with the re4uirements for MODE 5 where the provisions of this Special Operations LCO are no longer required. (continued) *. B :** . . . *Revision No. o:

.. :* . .-* ; . :' . ,.-_. SOM Test-Refueling . B 3.10.8 BASES (continued) SURVEILLANCE REQUIREMENTS PBAPS. UNIT. 3 SR 3.10.8.1. SR 3.10.8.2. and SR 3.10.8.3 LCO 3.3.1.1, Functions 2a, 2.d and 2e, made applicable Special Operations LCO, are required to have their

• Surveillances met to establish that this Special Operations LCO is being met. However, the control rod withdrawal sequences during the SOM tests may be enforced by the RWM CLCO 3.3.2.1, Function 2, MODE 2 requirements) or by a second licensed operator or other qualified member of the technical staff. As noted, either the applicable SRs for the RWM (LCO 3.3.2.1) must be satisfied according to the applicable Frequencies CSR 3.10.8.2), or *the proper movement of control rods must be verified CSR 3.10.8.3). This 19tter verification (i.e., SR 3.10.8.3) must be performed during control rod movement to prevent deviations from the
• specified sequence. These surveillances provide adequate assurance that the specified test sequence is being followed. SR 3.10.8.4 verification of the controls established by this LCO will ensure that the reactcif operated within the bounds of the safetf analysis. Jhe Survei 11 ance Frequency is control l e.d under the Survei 11 ance Contr9l Program . . SR 3.10.8.5 _.Coupling verification is per.formed.to ensure the control rod
• is'.co.nnected to the contro*l rod drive mechanism and will perform .its intended *function. when necessary. *The veHfii:ation is required to be performed any time a contr.ol rod is withdrawn to the."full out" notch position, *or prior.** to declaring the control. rod OPERABLEafte-r work on the . control rod or CRD System that c.oul d. affect coupling .. *. This . Ftequency is acceptable, considefing the low probabilitj that a control rod win become uncoup_l ed when it is not
• be{ng.moved as as. operating experience related to uncoupling cont i hued .* .. . > .. *s 3.10-35 Re vision No:.* 87 BASES SURVEILLANCE REQUIREMENTS (continued) REFERENCES
• PBAPS UN IT 3 SOM Test-Refueling B 3.10.8 SR 3.10.8.6 CRD ,charging water header pressure veri fi ca ti on is performed to ensure the motive force is available to scram the control rods in the event of a scram signal. Since the reactor is depressurized in MODE 5, there is insufficient reactor pressure to scram the control Verification of charging water header pressure ensures that if a scram were required, capability for rapid coritrol rod insertion would exist. The minimum pressure of 940 psig is well below the expected pressure of approximately 1450 psig while still *.ensuring pressure for rapid control rod insertion. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision. 2. Letter from T. Pickens (BWROG) to G.C. Lainas; NRC, "Amendment 17 to General Electric Licensing Topical Report NEDE-24011-P-A," August 15, 1986. B Revision No. 87}}