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| INSTRUCTIONS FOR UPDATING LOI Page 1 of 3 THE CRYSTAL RIVER UNIT 3 i i
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| IMPROVED TECHNICAL SPECIFICATIONS & BASES l I
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| : PUBLIC DOCUMENT ROOM COPY
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| l INSTRUCTIONS FOR UPDATING LOI Page 2 of 3 THE CRYSTAL RIVER UNIT 3 INPROVED TECHS '*L SPECIFICATIONS & BASES PUDLIC DOCUNENT ROON COPY 04/15/97 Page to be Removed Page to be Added 4
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| Paaefs) Revision Paaefs) Revision 1
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| INSTRUCTIONS FOR UPDATING LOI Page 3 of 3 THE CRYSTAL RIVER UNIT 3 i INPROVED TECHNICAL SPECIFICATIONS & BASES PUBLIC DOCUNENT R00N COPY !
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| 04/15/97 Page to be Removed Page to be Added i Paaefs) Revision Paae(s) Revision i i
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| L B 3.6-29/B 3.6-30 149/149 8 3.6-29/B 3.6-30 1/1 B 3.6-31/B 3.6-32 149/149 B3.6-31/B3.6-32 1/149 i B 3.6-35/B 3.6-36 149/149 8 3.6-35/8 3.6-36 2/2 ;
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| B 3.7-13/B 3.7-14 149/149 8 3.7-13/B 3.7-14 1/1 B 3~.7-15/B 3.7-16 149/149 B 3.7-15/B 3.7-16 1/1 B3.7-17/83.7-18 149/149 8 3.7-17/B 3.7-18 1/1 B 3.7-18A/B 3.7-18B 1/1-B 3.7-19/B 3.7-20 149/149 B 3.7-19/B 3.7-20 12/12 B 3.7-21/8 3.7-22 149/149 B 3.7-21/8 3.7-22 12/12 B3.7-71/B3.7-72 149/149 B 3.7-71/8 3.7-72 149/11 B 3.7-73/B 3.7-74 149/149 8 3.7-73/B 3.7-74 11/11 B 3.7-75/B 3.7-76 149/149 83.7-75/B3.7-76 11/11 1
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| CRYSTAL RIVER UNIT 3 ITS L0EPage 1 of 4 INPROVED TECHNICAL SPECIFICATIONS 01/15/97 List of Effective Pages (Through Amendment 155) l Eggg Amendment Eggg Amendment i 149 3.1-3 149 I 11 149 3.1-4 149 iii 149 3.1-5 149 iv 149 3.1-6 149 v 149 3.1-7 149 l vi. 149 3.1-8 149 vii 149 3.1-9 149 1.1-1 149 3.1-10 149 1.1-2 149 3.1-11 149 l; 1.1-3 149 3.1-12 149 1.1-4 149 3.1-13 149 1.1-5 149 3.1-14 149 1.1-6 149 3.1-15 149 1.1-7 149 3.1-16 149 ;
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| 1.1-8 149 3.1-17 149 1.2-1 149 3.1-18 149 l 1.2-2 149 3.1-19 149 1.2-3 149 3.1-20 149 i 1.3-1 149 3.1-21 149 1.3-2 149 3.2-1 149 1.3-3 149 3.2-2 149 1.3-4 149 3.2-3 149 1.3-5 149 3.2-4 149 1.3-6 149 3.2-5 149 1.3-7 149 3.2-6 149 1.3-8 149 3.2-7 149 1,3-9 149 3.2-8 149 1.3-10 149 3.2-9 149 1.3-11 149 3.2-10 149 1.3-12 149 3.2-11 149 1.4-1 149 3.2-12 149 1.4-2 149 3.2-13 149 1.4-3 149 3.3-1 149 1.4-4 149 3.3-2 149 2.0-1 149 3.3-3 149 2.0-2 149 3.3-4 152 2.0-3 149 3.3-5 149 3.0-1 149 3.3-6 149 3.0-2 149 3.3-7 149 3.0-3 149 3.3-8 149 3.0-4 149 3.3-9 149 3.0-S 149 3.3-10 149 3.1-1 149 3.3-11 149 3.1-2 149 3.3-12 149
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| CRYSTAL RIVER UNIT 3 ITS L0EPage 2 of 4 INPROVED TECHNICAL SPECIFICATIONS 01/15/97 i
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| List of Effective Pages (Through Amendment 155)
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| Eagg Amendment Eagg Amendment 3.3-13 149 3.4-14 149 3.3-14 152 3.4-15 149 3.3-15 149 3.4-16 149 3.3-16 149 3.4-17 149 3.3-17 152 3.4-18 149 3.3-18 149 3.4-19 149 1 3.3-19 155 3.4-20 149 3.3-20 149 3.4-21 149 3.3-21 149 3.4-22 154 i 3.3-22 149 3.4-23 149 I 3.3-23 152 3.4-24 149 3.3-24 149 3.4-25 149 3.3-25 152 3.4-26 149 3.3-26 149 3.4-27 149 3.3-27 149 3.4-28 149 3.3-28 152 3.4-29 149 3.3-29 149 3.4-30 149 I 3.3-30 149 3.4-31 149 l 3.3-31 149 3.4-32 149 3.3-32 149 3.4-33 149 3.3-33 149 3.5-1 149 l 3.3-34 149 3.5-2 149 l 3.3-35 149 3.5-3 149 3.3-36 149 3.5-4 149 3.3-37 149 3.5-5 149 3.3-38 149 3.5-6 149 3.3-39 149 3.5-7 149 j 3.3-40 152 3.5-8 149 i 3.3-41 149 3.5-9 149 3.3-42 149 3.5-10 149 3.3-43 152 3.6-1 149 3.3-44 149 3.6-2 149 3.4-1 149 3.6-3 149 3.4-2 149 3.6-4 149 3.4-3 149 3.6-5 149 3.4-4 149 3.6-6 149 3.4-5 149 3.6-7 149 3.4-6 149 3.6-8 149 3.4-7 149 3.6-9 149 3.4-8 149 3.6-10 149 3.4-9 149 3.6-11 149 3.4-10 149 3.6-12 149 3.4-11 149 3.6-13 149 3.4-12 149 3.6-14 149 3.4-13 149 3.6-15 149
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| CRYSTAL RIVER UNIT 3 ITS LOEPage 3 of 4 ,
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| INPROVED TECHNICAL SPECIFICATIONS 01/15/97 List of Effective Pages (Through Amendment 155) l Eagg Amendment Eagg Amendment 3.6-16 149 3.8-3 149 l 3.6-17 149 3.8-4 149 3.6-18 149 3.8-5 149 3.6 149 3.8-6 149 3.6-20 149 3.8-7 149 3.6-21 149 3.8-8 149 3.7-1 149 3.8-9 149 >
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| 1 3.7-2 149 3.8-10 149 3.7-3 149 3.8-11 149 3.7-4 149 3.8-12 149 3.7-5 149 3.8-13 149 3.7-6 149 3.8-14 149 3.7-7 149 3.8-15 149 1 3.7-8 149 3.8-16 149 3.7-9 149 3.8-17 149 3.7-10 149 3.8-18 149 3.7-11 149 3.8-19 149 3.7-12 149 3.8-20 149 3.7-13 149 3.8-21 149 3.7-14 149 3.8-22 149 3.7-15 149 3.8-23 149 3.7-16 149 3.8-24 149 3.7-17 149 3.8-25 149 )
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| 3.7-18 149 3.8-26 149 3.7-19 149 3.8-27 149 3.7-20 149 3.8-28 149 3.7-21 149 3.8-29 149 3.7-22 149 3.8-30 149 l 3.7-23 149 3.8-31 149 )
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| 3.7-24 149 3.8-32 149 3.7-25 149 3.8-33 149 3.7-26 149 3.8-34 149 3.7-27 149 3.9-1 149 3.7-28 149 3.9-2 149 3.7-29 149 3.9-3 152 3.7-30 151 3.9-4 149 3.7-31 151 3.9-5 149 3.7-32 151 3.9-6 149 3.7-33 151 3.9-7 149 3.7-33A 151 3.9-8 149 3.7-34 149 3.9-9 149 )'
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| 3.7-35 149 3.9-10 149 3.7-36 149 3.9-11 149 3.8-1 149 3.9-12 149 3.8-2 149 4.0-1 151
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| l CRYSTAL RIVER UNIT 3 ITS LOEPage 4 of 4 ,
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| IMPROVED TECHNICAL SPECIFICATIONS 01/15/97 ]
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| List of Effective Pages !
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| (Through Amendment 155) i Eggg bpendment Ea_qg Amendment l
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| l 4.0-2 151 4.0-3 149 5.0-1 149 5.0-2 149 .
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| 5.0-3 149 l 5.0-4 149 l 5.0-5 149 I 5.0-6 149 l 5.0-7 149 5.0-8 149 5.0-9 149 I 5.0-10 149 i 5.0-11 153 J 5.0-12 149 5.0-13 149 l 5.0-14 154 ,
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| 5.0-15 149 'I 5.0-16 154 1 5.0-16A 154 5.0-17 154 5.0-18 149 I 5.0-19 149 5.0-20 149 5.0-21 149 5.0-22 149 5.0-23 149 5.0-24 149 5.0-25 149 5.0-26 149 5.0-27 149 5.0-28 149 5.0-29 154 5.0-29A 154 5.0-30 149-5.0-31 149 Appendix B -Part II 1-1 58 2-1 58 3-1 58 3-2 58 3-3 58 4-1 58 4-2 58
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| !- CRYSTAL RIVER UNIT 3 ITS Bases L0EPage 1 of 8 i
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| : 01/15/97 i IMPROVED TECHNICAL SPECIFICATION BASES i >
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| ; List of Effective Pages l (Through ITS Bases Revision 12)
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| Eggg Revision Eagg Revision i B 2.0-1 09 B 3.1-7 149 4
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| 8 2.0-2 09 B 3.1-8 149 i B 2.0-3 09 B 3.1-9 149
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| ) B 2.0-4 09 B 3.1-10 149 l 1 B 2.0-5 09 B 3.1-11 149 1 B 2.0-6 09 B 3.1-12 149 i t B 2.0-7 11 B 3.1-13 149 !
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| B 2.0-8 11 B 3.1-14 149 ;
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| i B 2.0-9 11 B 3.1-15 149 :
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| i B 2.0-10 11 B 3.1-16 149 !
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| j B 2.0-11 11 B 3.1-17 149 B 2.0-12 11 B 3.1-18 149
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| ] B 3.0-1 149 B 3.1-19 149
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| ; B 3.0-2 149 B 3.1-20 149 B 3.0-3 149 B 3.1-21 149 i B 3.0-4 149 B 3.1-22 149
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| ; B 3.0-5 149 B 3.1-23 149 '
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| ' B 3.0-6 149 B 3.1-24 149 ,
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| j B 3.0-7 149 8 3.1-25 149
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| { B 3.0-8 149 B 3.1-26 149 B 3.0-9 149 B 3.1-27 149
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| -B 3.0-10 149 B 3.1-28 149
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| ! B 3.0-11 '149 B 3.1-29 149 B 3.0-12 149 B 3.1-30 149 B 3.0-13 149 8 3.1-31 149 i I 8 3.0-14 149 B 3.1-32 149 B 3.0-15 149 8 3.1-33 149 i B 3.0-16 149 B 3.1-34 149 i B 3.0-17 149 8 3.1-35 149 x B 3.0-18 149 8 3.1-36 149
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| ! B 3.0-19 149 8 3.1-37 149
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| . B 3.0-20 149 8 3.1-38' 149 i B 3.1-1 149 8 3.1-39 149
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| : j. B 3.1-2 149 B 3.1-40 149 4
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| B 3.1-3 149 B 3.1-41 149 1 B 3.1-4 149 8 3.1-42 149 B 3.1-5 149 8 3.1-43 149
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| , B 3.1-6 149 B 3.1-44 149 i
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| ). NOTE: Pages with footer as Amendment No.149 are initial issue, Revision 0 of the ITS Bases. Pages with footers containing Amendment Numbers other than i 149 are Bases approved by the NRC in subsequent License Amendments. Pages
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| ! with footers containing a Revision number are Bases changes issued under l CR-3's Technical Specificatlon Bases Control Program.
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| CRYSTAL RIVER UNIT 3 ITS Bases LOEPage 2 of 8 01/15/97
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| , INPROVED TECHNICAL SPECIFICATION BASES
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| ]
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| i List of Effective Pages !
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| (ThroughITSBasesRevision12)
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| Elag Revision EAga Egvision
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| B 3.1-45 149 B 3.2-37 149 i B 3.1-46 149 B 3.2-38 149 B 3.1-47 149 B 3.2-39 149 B 3.1-48 149 B 3.2-40 149 8 3.1-49 149 8 3.f:-41 149 8 3.1-50 149 B 3.E-42 149 8 3.1-51 149 B 3.2-43 149 B 3.1-52 149 B 3.2-44 149 8 3.2-1 149 B 3.3-1 07 l B 3.2-2 149 B 3.3-2 07 B 3.2-3 149 B 3.3-3 07 B 3.2-4 149 B 3.3-4 07 B 3.2-5 149 8 3.3-5 07 8 3.2-6 149 B 3.3-6 07 B 3.2-7 149 8 3.3-7 07 B 3.2-9 149 B 3.3-8 07 B 3.2-9 149 8 3.3-9 07 i 8 3.2-10 149 8 3.3-10 07 i B 3.2-11 149 8 3.3-11 07 !
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| B 3.2-12 149 B 3.3-12 07 l B 3.2-13 149 B 3.3-13 07 l B 3.2-14 149 B 3.3-14 07 !
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| B 3.2-15 149 B 3.3-15 07 i B 3.2-16 149 B 3.3-16 07 B 3.2-17 149 B 3.3-17 07 8 3.2-1B 149 8 3.3-18 07 B 3.2-19 149 8 3.3-19 07 B 3.2-20 149 B 3.3-20 07 B 3.2-21 149 B 3.3-21 07 B 3.2-22 149 B 3.3-22 07 8 3.2-23 149 B 3.3-23 07 B 3.2-24 149 8 3.3-24 07 8 3.2-25 149 8 3.3-25 07 B 3.2-26 149 8 3.3-26 07 8 3.2-27 149 8 3.3-27 07 8 3.2-28 149 B 3.3-28 07 B 3.2-29 149 B 3.3-29 07 B 3.2-30 1^9 B 3.3-30 07 8 3.2-31 'i9 B 3.3-31 149 B 3.2-32 149 B 3.3-32 149 B 3.2-33 149 B 3.3-33 149 B 3.2-34 149 B 3.3-34 149 B 3.2-35 149 8 3.3-35 149 B 3.2-36 149 B 3.3-36 149
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| i CRYSTAL RIVER UNIT 3 ITS Bases L0EPage 3 of 8 01/15/97 l INPROVED TECHNICAL SPECIFICATION BASES l
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| List of Effect)ve Pages '
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| CRYSTAL RIVER UNIT 3 ITS Bases L0EPage 5 of 8 01/15/97 INPROVED TECHNICAL SPECIFICATION BASES List of Effective Pages (Through ITS Bases Revision 12)
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| Eagg Revision Engg Revision B 3.4-62 149 B 3.6-1 01 l B 3.4-63 149 B 3.6-2 01 B 3.4-64 149 B 3.6-3 01 B 3.4-65 -149 B 3.6-4 01 B 3.4-66 149 8 3.6-5 01 B 3.4-67 149 B 3.6-6 01 B 3.4-68 149 8 3.6-7 01 B 3.4-69 149 B 3.6-8 01 B 3.4-70 149 8 3.6-9 01 B 3.4-71 149 B 3.6-10 01 B 3.4-72 149 B 3.6-11 01 B 3.4-73 149 B 3.6-12 01 B 3.4-74 149 B 3.6-13 01 B 3.4-75 149 B 3.6-14 01 B 3.5-1 149 8 3.6-15 11 1 B 3.5-2 149 8 3.6-16 11 B 3.5-3 149 B 3.6-17 11 B 3.5-4 149 B 3.6-18 11 B 3.5-5 149 B 3.6-19 11 B 3.5-6 149 B 3.6-20 11 B 3.5-7 149 B 3.6-21 11 B 3.5-8 149 B 3.6-22 11 B 3.5-9 06 B 3.6-23 11 B 3.5-10 06 B 3.6-24 11 B 3.5-11 06 B 3.6-25 11 B 3.5-12 06 B 3.6-26 11 B 3.5-13 06 B 3.6-27 11 B 3.5-14 06 B 3.6-28 11 B 3.5-15 06 B 3.6-29 01 B 3.5-16 06 B 3.6-30 01 B 3.5-17 06 B 3.6-31 01 B 3.5-18 06 8 3.6-32 149 B 3.5-19 06 B 3.6-33 149 B 3.5-20 149 8 3.6-34 149 B 3.5-21 149 B 3.6-35 02 B 3.5-22 149 B 3.6-36 02 :
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| CRYSTAL RIVER UNIT 3 ITS Bases LOEPage 7 of 8 01/15/97 INPROVED TECHNICAL SPECIFICATION BASES
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| 1 B 3.7-82 149 B 3.8-42 08 B 3.7-83 149 B 3.8-43 08 8 3.7-84 149 B 3.8-44 08 8 3.8-1 149 B 3.8-45 08 B 3.8-2 149 8 3.8-46 08 ,
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| CRYSTAL RIVER UNIT 3 ITS Bases LOEPage 8 of 8 l 3 01/15/97 l INPROVED TECHNICAL SPECIFICATION BASES List of Effective Pages
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| ] (Through ITS Bases Revision 12)
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| PJgg Revision Eggg Revision ,
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| , l 1
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| 1 1
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| 0 l
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| 4
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| . . - = .
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| I React'or Core SLs B 2.1.1 l l
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| B 2.0 SAFETY LIMITS (SLs)
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| B 2.1.1 Reactor Core SLs j l
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| BASES BACKGROUND Crystal River Unit 3 FSAR Section 1.4 (Ref.1) Criterion 6 requires that acceptable fuel design limits are not exceeded during normal operation and anti'c ipated operational occurrences (A00s). The reactor core SLs are established to preclude violation of the following fuel design criteria:
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| : a. There must be at least 95% probability at a 95%
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| confidence level (95/95 DNB criterion) that the hot fuel rod in the core does not experience DNB; and
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| : b. The hot fuel pellet in the core must not experience fuel centerline melting. ;
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| 1 DNB cannot be measured directly during power operation.
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| However, THERMAL POWER, reactor coolant pressure, temperature, flow and power peaking can be correlated to the critical heat flux (CHF), which is the heat flux at which )
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| DNB occurs. CHF correlations have been developed experimentally to predict the departure from nucleate boiling ratio (DNBR), defined as the ratio of the heat flux required to cause DNB at a particular core location to the local heat flux. The DNBR is an indication of the margin to DNB for core design purposes and safety analysis evaluations.
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| Tha restrictions of this SL provide a high degree of p m ection against overheating of the fuel and cladding that would result in possible cladding perforation. Overheating of the fuel is prevented by maintaining the steady state peak linear heat rate (LHR) below the level at which fuel centerline melting occurs. Overheating of the fuel cladding is prevented by-restricting fuel operation to within the nucleate boiling regime, where the heat transfer coefficient
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| * is large and the cladding surface temperhture is slightly
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| * above the coolant saturation temperature.
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| The 95/95 DNB criterion is preserved by ensuring that the DNBR remains greater than the DNBR design limit b ed upon the applicable CHF correlation for the core design. In the development of the applicable DNBR design limit, uncertainties in the core state variables, power peaking (continued)
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| Crystal River Unit 3 B 2.0-1 Revision 9
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| Reactor Core SLs B 2.1.1 {
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| BASES !
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| ~
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| BACKGROUND factors, manufacturing related parameters, and the' CHF (continued) correlation may be statistically combined to determine a statistical DNBR design limit. Additional retained thermal margin may also be applied to the statistical DNBR design limit to yield a higher thermal design limit for use in l establishing DNB-based core safety and operating limits. In !
| |
| all cases, application of statistical DNBR design methods preserves the 95/95 DNB criterion. l Fuel centerline melting occurs when the local LHR, or power l peaking, in a region of the fuel is high enough to cause the -
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| fuel centerline temperature to reach the melting point of the fuel. Expansion of the pellet upon centerline melting l i
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| may cause the pellet to stress the cladding to the point of l failure, allowing an uncontrolled release of activity to the ,
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| reactor coolant. The melting point of uranium dioxide varies slightly with burnup. As uranium is depleted and fission products produced, the net effect is a decrease in the melting point. However, depletion of the uranium also reduces th? power produced in the fuel such that the closest the plant comes to the centerline melt SL is at the beginning of the fuel cycle. The formula presented is on a per fuel pin basis. -
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| t Operation above the boundary of the nucleate boiling regime could result in excessive cladding temperature because of the onset of DNB and the resultant sharp reduction in heat i 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 '
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| weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant.
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| i
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| .The proper functioning of the Reactor Protection System (RPS) prevents violation of the reactor core SLs.
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| (continued)
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| Crystal River Unit 3 B 2.0-2 Revision 9 l
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| Reactor Core SLs l B 2.1.1 ;
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| BASES B
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| APPLICABLE The RPS setpoints (Ref. 2), in combination with the DNB !
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| SAFETY ANALYSES operating limits LCO (LCO 3.4.1), are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System (RCS) temperature, pressure, and THERMAL POWER level that would result in a departure from-nucleate boiling ratio (DNBR)'of less thar the DNBR limit .
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| and preclude the existence of flow instabilities. l Automatic enforcement of these reactor core SLs is provided i by the following:
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| : a. . RCS High Pressure trip; ,
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| : o. RCS Low Pressure trip;
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| : c. Nuclear Overpower trip; !
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| : d. RCS Variable Low Pressure trip;
| |
| : e. Reactor Coolant Pump to Power trip; and
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| : f. Nuclear Overpower RCS Flow and AXIAL POWER IMBALANCE ,
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| . trip.
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| The SL represents a design requirement for establishing the ,
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| RPS trip setpoints identified previously.
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| Safety Limits that preclude fuel cladding failure are required to be included in the Technical Specifications !
| |
| pursuant to 10 CFR 50.36 (Ref. 5). !
| |
| SAFETY LIMITS SL 2.1.1.1, SL 2.1.1.2, and SL 2.1.1.3 ensure that the minimum DNBR is not less than the safety analyses limit and that fuel centerline temperature stays below the melting !
| |
| point, or the average enthalpy in the hot leg is less than or equal to the enthalpy of saturated liquid, or the exit quality is within the limits defined by the DNBR correlation. In addition, SL 2.1.1.3 addresses the l
| |
| l pressure / temperature operating region that keeps the reactor from reaching an SL when operating up to design power.
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| s (continued)
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| Crystal River Unit 3 8 2.0-3 Revision 9
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| | |
| Reactor Core SLs B 2.1.1
| |
| ; i BASES '(continued)
| |
| SAFETY LIMITS Examination of the limit curve in Figure 2.1.1-1 reveals that the temperatures corresponding to the pressures vary l between 20 and 30*F below the saturation temperature of the j coolant at that pressure, thus ensuring an even greater '
| |
| margin to DNB., .
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| ]
| |
| 1 i
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| ' The fuel centerline melt and DNBR SLs are not df rectly i monitorable by installed plant instrumentation. Instead, '
| |
| the SLs are preserved by monitoring the process variable.
| |
| 3
| |
| +
| |
| AXIAL POWER IMBALANCE to ensure that the core operates within the fuel design criteria. With AXIAL POWER IMBALANCE l .
| |
| within the protective limits, fuel centerline temperature and DNBR are also within limits. AXIAL POWER IMBALANCE protective limits are provided in the COLR.
| |
| 2 The AXff,L POWER IMBALANCE protective limits are preserved by
| |
| ) their corresponding RPS setpoints in LC0 3.3.1, " Reactor 1 Protection System (RPS) Instrumentation," as specified in
| |
| : the COLR. The trip setpoints are derived by adjusting the
| |
| , measurement system indepehdent AXIAL POWER IMBALANCE protective limit given in the COLR to allow for measurement system observability (the fact there are a finite number of
| |
| ? detectors) and instrumentation errors. The AXIAL POWER i .
| |
| IMBALANCE protective limits are separate and distinct from )
| |
| the AXIAL POWER IMBALANCE operating limits defined by !
| |
| . LCO 3.2.3, " AXIAL POWER IMBALANCE Operating Limits." The 1 j AXIAL POWER IMBALANCE operating limits in LCO 3.2.3, also i specified in the COLR, preserve initial conditions of the
| |
| ] safety analyses but are not reactor core SLs.
| |
| RCS pressure, temperature and flow DNB operating limits are defined by LCO 3.4.1.
| |
| APPLICABILITY SL 2.1.1.1, SL 2.1.1.2, and SL 2.1.1.3 only apply in MODES 1 and 2 because these are the only MODES in which the reactor is critical. Automatic protection functions are required to be OPERABLE during MODES 1 and 2 to ensure operatior within the reactor core SLs. The automatic protection actions serve to prevent RCS heatup to reactor core SL conditions by 1 dtiating a reactor trip which forces the plant into MODE 3. Setpoints for the reactor trip functions are specified in LCO 3.3.1.
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| (continued)"
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| Crystal River Unit 3 8 2.0 4 Revision 9
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| | |
| ~ Reactor Core SLs B 2.1.1 BASES (continued)
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| In MODES 3, 4, 5, and 6, Applicability is not required, APPLICABILITY since the reactor is not generating significant THERMAL (continued)
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| POWER.
| |
| The following SL violation responses are applic'able to the SAFETY LIMIT VIOLATIONS reactor core SLs.
| |
| L.L.1 If SL 2.1.1.1, SL 2.1.1.2, or SL .2.1.1.3 is violated, the requirement to go to MODE 3 places the plant in a MODE in which these SLs can not be violated.
| |
| The allowed Completion Time of 1 hour recognizes the importance of placing the plant in a MODE of operation where these SLs are not applicable and reduces the probability of fuel damage.
| |
| 2.2 A If SL 2.1.1.1, SL 2.1.1.2, or SL 2.1.1.3 is violated, the =
| |
| NRC Operations Center must be notified within I hour, in accordance with 10 CFR 50.72 (Ref. 3).
| |
| The 10 CFR 50.72 part against which a Safety Limit violation would be reported is the declaration of any of the Emergency Classes specified in the Emergency Plan (10 CFR 50.72(a)(1)(i)).
| |
| 1.L.!!
| |
| If SL 2.1.1.1, SL 2.1.1.2, or SL 2.1.1.3 is violated, the appropriate Nuclear Operations senior management and the Nuclear General Review Committee This 24 hour (NGRC) time period provides shallfor bethe notified within 24 hours.
| |
| plant operators and staff to take the appropriate immediate action and assess the conditicn of the plant before reporting to senior management.
| |
| (continued) l 8 2.0-5 Revision 9 f Crystal River Unit 3
| |
| | |
| - . . - . . . . . - . . ~ - _ - - . . . . -
| |
| Reactor Core SLs B 2.1.1 BASES i
| |
| SAFETY LIMIT 2,2,6 VIOLATIONS (continued)
| |
| If SL 2.1.1.1, SL 2 1.1.2, or SL 2.1.1.3 is violated, a Licensee Event Report shall be prepared and submitted within 30 days to the NRC in accordance with 10 CFR 50.73 (Ref. 4).
| |
| A copy of the report shall also be provided to the NGRC, the Director, Nuclear Plant Operations, 'and the Senior Vice President, Nuclear Operations.
| |
| The 10 CT.s 50.73 part against which a Safety Limit violation would be reported is: 1) completion of a plant shutdown required by Technical Specifications, (10 CFR 50.73(a)(2)(i)(A)), 2) an event which resulted in an unanalyzed condition that significantly compromised plant safety, (10 CFR 50.73(a)(2)(ii)(A)), 3) any condition outside the design basis for the plant (10 CFR -
| |
| j 50.73(a)(2)(ii)(B)), and 4) an event which resulted in an
| |
| ! RPS actuation (10 CFR 50.73(a)(2)(iv)).
| |
| i If SL 2.1.1.1, SL 2.1.1.2, or SL 2.1.1.3 is violated, '
| |
| operation of the plant shall not be resumed until authorized by the NRC. This requirement ensures the NRC that all i i necessary reviews, analyses, and actions are completed '
| |
| before the plant enters the applicable MODES for these SLs (MODES 1 and 2).
| |
| i REFERENCES 1. FSAR, Section 1.4.
| |
| : 2. FSAR, Tcble 7-2.
| |
| ! i
| |
| : 3. 10 CFR 50.72.
| |
| : 4. 10 CFR 50.73.
| |
| : 5. 10 CFR 50.36.
| |
| 4 i
| |
| 4 l
| |
| (continued) 1 Crystal River Unit 3 8 2.0-6 Revision 9 i
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| , , _,,r n , m .
| |
| | |
| d d
| |
| RCS Pressure SL B 2.1.2 P
| |
| rf B 2.0 SAFETYLIMITS(SLs) 4 8 2.1.2 Reactor Coolant System (RCS) Pressure SL BASES l
| |
| ! BACKGROUND According to FSAR Section 1.4, Criterion 9, " Reactor Coolant
| |
| ' Pressure Boundary," is designed and constructed so as to have an exceedingly low probability of gross rupture or significant leakage throughout its design lifetime (Ref.1),
| |
| the reactor coolant pressure boundary (RCPB). Criterion 33, RCPB Capability" (Ref. 1), specifies that reactivity accidents including rod ejection do not result in damage to j the RCPB greater than limited local yielding.
| |
| l The design pressure of the RCS is 2500 psig. During normal l
| |
| ' operation and anticipated operational occurrences (A00s),
| |
| the RCS pressure is kept from exceeding the design pressure ,
| |
| by more than 10% in order to remain in accordance with j l
| |
| Section III of the ASME Code (Ref. 2). Hence, the safety i limit is 2750 psig. To ensure system integrity, all RCS components were hydrostatically tested at 125% of design l pressure (3125 psig) prior to initial operation, ncording to the ASME Code requirements. Inservice operational l
| |
| ]
| |
| hydrotesting in accordance with the ASME Code is also required whenever the reactor vessel head has been removed or if other pressure boundary joint alterations have occurred. Following inception of plant operation, RCS 4
| |
| ' components are pressure tested in accordance with the requirements of ASME Code, Section XI (Ref. 3). ,
| |
| 3 APPLICABLE The RCS pressurizer safety valves, operating in conjunction j SAFETY ANALYSES with the Reactor Protection System trip settings, ensure l' that the RCS pressure SL will not be exceeded.
| |
| l l The RCS pressurizer safety valves are sized to prevent j
| |
| system pressure from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code l'
| |
| for Nuclear Power Plant Components (Ref. 2). The transient that is most influential for establishing the required relief capacity, and hence the valve size requirements and lift settings, is a rod withdrawal from low power Both
| |
| ' pressurizer safety valves may be required for protection (continued)
| |
| B 2.0-7 Revision 11 Crystal River Unit 3
| |
| | |
| 1 RCS Pressure SL B 2.1.2 BASES )
| |
| i l
| |
| APPLICABLE from this event. During the transient, no control actions i SAFETY ANALYSES are assumed except that the Reactor Protection System (RPS) )
| |
| (continued) trips the reactor on high flux, and nominal feedwater supply is maintained. Main Steam Safety Valves, while not !
| |
| specifically modelled as part of the analysis, are qualitatively assumed to function to fix secondary side I pressures and temperatures (and thus, RCS cold leg temperature). !
| |
| It is important to emphasize that when the operating !
| |
| characteristics of the safety valves were selected, it was assumed that the reactor protection system provided the first overpressure protection. The safety valves alone l cannot prevent overpressure; they act in conjunction with !
| |
| the RPS to prevent overpressure. A single failure in the RPS will not result in a failure to trip the reactor.
| |
| Failure of the RPS to trip the reactor was not assumed to be credible when the operating characteristics of the safety valves were specified. The single failure criterion is not ,
| |
| considered to be applicable to pressurizer safety valves '
| |
| since the ASME code allows the use of the rated capacity of all OPERABLE spring-loaded safety valves. This allows the l total relieving capacity of both valves to be credited to s overpressure protection.
| |
| The overpressure protection analyses (Ref. 4) and the safety analyses (Ref. 5) are performed using conservative assumptions relative to pressure control devices. More i specifically, no credit is taken for operation of the !
| |
| following: I
| |
| : a. Pressurizer power operated relief valves (PORVs);
| |
| : b. Steam line turbine bypass valves; j
| |
| : c. Control system runback of reactor and turbine power; and i
| |
| : d. Pressurizer spray valve.
| |
| SAFETY LIMITS The maximum transient pressure allowed in the RCS pressure vessel under the ASME Code, Section III, is 110% of design (continued)
| |
| Crystal River Unit 3 8 2.0-8 Revision 11 I
| |
| h
| |
| | |
| RCS Pressure SL B 2.1.2 1 l
| |
| BASES
| |
| (
| |
| pressure. The maximum transient pressure allowed in the RCS SAFETY LIMITS piping, valves, and fittings under USAS, Section 831.7 the Therefore, (continued) (Ref 6), is also 110% of design pressure.
| |
| SL on maximum allowable RCS pressure of 2750 psig is consistent with the design criteria and associated code requirements.
| |
| Overpressurization of the RCS can result in a breach of the RCPB. If such a breach occurs in conjunction with a fuel cladding failure, fission products could enter the containment atmosphere, raising concerns relative to limits !
| |
| on radioactive releases specified in 10 CFR 100, " Reactor Site Criteria" (Ref. 7).
| |
| APPLICABILITY SL 2.1.2 applies in MODES 1, 2, 3, 4, and 5 because this SL I
| |
| could be approached or exceeded in these MODES during overpressurizatici, events. The SL is not applicable in l i
| |
| MODE 6 because the reactor vessel head closure bolts are not l fully tightened, making it unlikely that the RCS can be '
| |
| pressurized.
| |
| SAFETY LIMIT The following SL violation responses are applicable to the VIOLATIONS RCS pressure SL. .
| |
| 2.2.2 i If the RCS pressure SL is violated when the reactor is in MODE 1 or 2, the requirement is to restore compliance and be in MODE 3 within I hour.
| |
| Exceeding the RCS pressure SL may cause immediate RCS I
| |
| failure and create a potential for radioactive releases in l
| |
| excess of 10 CFR 100, " Reactor Site Criteria," limits (Ref7).
| |
| The allowed Completion Time of I hour is based on the l importance of reducing power level to a MODE of operation where the potential for challenges to safety systems is minimized.
| |
| (continued)
| |
| Crystal River Unit 3 B 2.0-9 Revision 11 ,
| |
| | |
| a i
| |
| RCS Pressure SL B 2.1.2 I BASES SAFETY LIMIT L1_u3_ 1 VIOLATIONS i (continued) If the RCS pressure SL is exceeded in MODE 3, 4, or 5, RCS l
| |
| pressure must be restored to within the SL value within 5 minutes. i 4
| |
| Exceeding the RCS pressure SL in MODE 3, 4, or 5 is potentially more severe than exceeding this SL in NODE 1 or 2, since the reactor vessel temperature may be lower and the vessel material, consequently, less ductile. As such, pressure must be reduced to less than the SL within 5 minutes. This action does not require reducing MODES, since this would require reducing temperature, which would compound the problem by adding thermal gradient stresses to the existing pressure stress.
| |
| 2 2.4 If the RCS pressure SL is violated, the NRC Operations Center must be notified within 1 hour, in accordance with j
| |
| 10 CFR 50.72 (Ref. 8).
| |
| . The 10 CFR 50.72 part against which a Safety Limit violation would be reported is the declaration of any of the Emergency Classes specified in the Emergency Plan (10 CFR j
| |
| 50.72(a)(1)(1)).
| |
| e 4
| |
| 2 2.5 l
| |
| ! If the RCS pressure SL is violated, the appropriate Nuclear i
| |
| , Operations senior management and the Nuclear General Review i Committee (NGRC) shall be notified within 24 hours. This '
| |
| : 24 hour period provides time for the plant operators and staff to take the appropriate immediate action and assess j the condition of the plant before reporting to the senior l management.
| |
| 4 (continued) -
| |
| 1 I
| |
| Crystal River Unit 3 B 2.0-10 Revision 11 l
| |
| | |
| i RCS Pressure SL B 2.1.2 i BASES SAFETY LIMIT 2,2.6 VIOLATIONS (continued) If the RCS pressure SL is violated, a Licensee Event Report
| |
| , shall be prepared and submitted within 30 days to the NRC in
| |
| ' accordance with 10 CFR 50.73 (Ref. 9). A copy of the r2 port shall also be provided to the NGRC, the Director, Nuclear 1 Plant Operations, and the Senior Vice President , Nuclear Operations.
| |
| l The 10 CFR 50.73 part against which a Safety Limit violation j would be reported is: 1) completion of a plant shutdown required-by Technical Specifications, (10 CFR 50.73(a)(2)(i)(A)), 2) an event which resulted in an l
| |
| unanalyzed condition that significantly compromised plant safety,(10CFR50.73(a)(2)(iv)).
| |
| : 2.2.7 If the RCS pressure SL is violated, operation of the plant shall not be resumed until authorized by the NRC. This requirement ensures the NRC that all necessary reviews,
| |
| , analyses, and actions are completed by establishing l limitations on ascending MODES or other specified conditions I 3 in the Applicability until the NRC review is complete.
| |
| l REFERENCES 1. FSAR, Section 1.4. j l
| |
| : 2. ASME Boiler and Pressure Vessel Code, Section III, Article NB-7000.
| |
| : 3. ASME Boiler and Pressure Vessel Code, Section XI, Articles IWA-5000 and IWB-5000.
| |
| l'
| |
| : 4. BAW-10043, May 1972.
| |
| : 5. FSAR, Section 14. !
| |
| : 6. ASME USAS B31.7, Code .for Pressure Piping, Nuclear l Power Piping, Februr y 1968 Draft Edition.
| |
| (continued)
| |
| Crystal River Unit 3 8 2.0 11 Revision 11
| |
| | |
| RCS' Pressure SL ,
| |
| B 2.1.2 i
| |
| t BASES (J, .
| |
| 3
| |
| .w-REFERENCES ). 10 CFR 100.
| |
| (continued) *
| |
| : 8. 10 CFR 50.72. ,
| |
| : 9. 10 CFR 50.73.
| |
| l l
| |
| 1 I
| |
| i
| |
| -. t i
| |
| .i i
| |
| 4 t
| |
| I I
| |
| e l i l !
| |
| i
| |
| !. (
| |
| 1 I i
| |
| i ! :
| |
| ~.,
| |
| ' Crystal River Unit 3. 8 2.0-12 Revision 11 !
| |
| . - . , - , . _ , _ , - --- .w,--
| |
| | |
| 1 RPS Instrumentation B 3.3.1 B 3.0 INSTRUMENTATION .
| |
| B 3.3.1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a reactor trip, (i.e., full insertion of all CONTROL RODS) to protect against violating core fuel l design limits and the Reactor Coolant System (RCS) pressure :
| |
| boundary during anticipated operational occurrences (A00s). l By tripping the reactor, the RPS also functions. in conjunction with the Engineered Safeguards (ES) Systems in mitigating accidents.
| |
| The RPS is part of a layered protection scheme designed to assure safe operation of the reactor. This defense-in-depth approach is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as providing LCOs on other reactor system ;
| |
| parameters and equipment performance. The LSSS, defined in ;
| |
| this Specification as the Allowable Value, in conjunction !
| |
| with these other LCOs, establishes the threshold for protective system action to prevent exceeding acceptable ,
| |
| limits during Design Bas.is Accidents (DBAs). f During A00s, (those events expected to occur one or more times during the plant's life) the RPS serves to automatically protect and maintain the following Safety Limits:
| |
| : a. The departure from nucleate boiling ratio (DNBR) shall be maintained greater than the Safety Limit (SL) value of Specification 2.1.1.2;
| |
| : b. Fuel centerline melt shall not occur; and
| |
| : c. The RCS pressure SL of 2750 psig shall not be ,
| |
| exceeded.
| |
| The RPS also assures offsite doses are maintained within 10
| |
| .CFR 100 limits following accidents. ,
| |
| (continued)
| |
| ' Crystal River Unit 3 B 3.3-1 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1 BASES ~
| |
| BACKGROUND RPS Overview (continued)
| |
| The RPS consists of four separate redundant protection channels that receive inputs of neutron flux, RCS pressure, RCS ficw, RCS temperature, RC pump status, reactor building (RB) pressure, main feedwater (MFW) pump status, and main turbine status.
| |
| FSAR Figure 7-1, (Ref. 1), shows the arrangement of a typical RPS protection channel. The channel is composed of measurement channels, a manual trip channel, a reactor trip module (RTM), and CONTROL ROD drive (CRD) trip devices. l LC0 3.3.1 provides requirements for the individual '
| |
| measurement channe.ls. These channels ercompass all equipment and electronics from the point at which the measured parameter is sensed through the bistable relay contacts in the trip string. LCO 3.3.2, " Reactor Protection ,
| |
| System (RPS) Manual Reactor Trip," LCO 3.3.3, " Reactor '
| |
| Protection System (RPS)-Reactor Trip Module (RTM)," and LC0 3.3.4, " CONTROL R0D Drive (CRD) Trip Devices," discuss the remaining elements in the RPS protection channel.
| |
| Ar. RPS instrumentation channel measures critical plant -
| |
| parameters (see above) and compares these to pre-determined setpoints. If the setpoint is exceeded, a channel trip signal is generated. The generation of any two trip signals in any of the four RPS channels will result in the full insertion of all CONTROL RODS. Development of the two-out-of-four logic is done in the RTM. Each RPS channel contains an RTM. The RTM receives signals from the associated measurement devices in the same channel that indicates a protection channel trip is required. The RTM transmits this signal to an internal two-out-of-four trip logic and to similar logic in the RTMs in the other three RPS channels.
| |
| The two-out-of-four logic is designed such that whenever any two RPS channels sense and transmit trip signals, the RTM logic in each channel actuates to remove 120 VAC power from its associated CRD trip device (s).
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-2 Revision No. 7
| |
| | |
| RPS fnstrumentation i B 3.3.1 i
| |
| BASES ,
| |
| 1 BACKGROUND The Reactor Trip System (RTS)~contains multiple CRD trip (continued) . devices. These include two AC trip breakers, and two DC I
| |
| trip breaker pairs that provide a path for power to the CRD Control System (CRDCS) caring normal operation.
| |
| The reactor is tripped by opening circuit breakers that
| |
| ; interrupt the power supply to the CRDCS. Six breakers are 5 installed to increase reliability and allow testing of the
| |
| ! trip system. A one-out-of-two taken twice logic is used to i
| |
| ! interrupt power to the rods. Additionally, the power for 1 1 -
| |
| the regulating rods (Groups 5, 6, 7), the APSRs (Group 8),
| |
| and the hold bus passes througn electronic trip' assembly (ETA) relays. The CRDCS design is such that there are two :
| |
| j separate paths with each path having either two breakers or )
| |
| a breaker and an ETA relay in series. Each path provides
| |
| ; independent power to the CRDs and either path can provide !
| |
| sufficient power to operate all CRDs. Two separate power I paths to the CRDs are provided to ensure that a single i failure that de-energizes one path will not cause an i undesired reactor trip.
| |
| }
| |
| l The RPS has two bypasses: a shutdown bypass and a channel
| |
| ] bypass. Shutdown bypass allows the withdrawal of safety
| |
| ~
| |
| rods for rapid negative reactivity insertion during periods
| |
| { when the plant is shut down. Channel bypass is used for i maintenance ar.d testing. Test circuits in the trip strings
| |
| ; allow complete testing of all RPS trip Functions. ;
| |
| I i The RPS receives inputs from the instrumentation channels l discussed in the next section. The specific relationship )
| |
| ; between measurenient channels and protection channels differs
| |
| : from parameter to parameter. Three basic configurations are 5
| |
| used:
| |
| ! a. Four completely redundant measurements (e.g., reactor l building pressure) with one channel input to each protection channel;
| |
| : b. Four channels that provide similar, but not identical, measurements (e.g., power range nuclear a
| |
| instrument.ation where each RPS channel monitors a different quadrant), with one channel input to each
| |
| ; protection channel; and j -
| |
| 1
| |
| ] (continued)
| |
| Crystal River Unit 3 B 3.3-3 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1 BASES -
| |
| t BACKGROUND c. Redundant measurements with combinational trip logic (continued) outside of the protection channels and the combined output provided to each protection channel (e.g., main feedwater pump trip instrumentation).
| |
| In addition to the three basic configurations aiscussed, the Reactor Coolant Pump Power Monitoring (RCPPM) " unction utilizes another relationship. Two'RCPPMs on aach RCP monitor pump Kw. Each RCPPM provides an indication of a '
| |
| tripped RCP to all four RPS channels. When the RPS channel
| |
| ~
| |
| senses less than three RCPs in operation, the RPS channel trips. Either RCPPM associated with one RCP is capable of providing the necessary input signal to the RPS, but two RCPPMs are provided for single failure considerations. In essence, the RCPPM Function is a one out-of-two at the sensor, a logic within the RPS that evaluates for less than three pumps in operation, and a two out-of-four in the RPS.
| |
| These arrangements and the relationship of instrumentation channels to trip Functions are discussed next to assist in !
| |
| understanding the overall effect of instrumentation channel failure.
| |
| i Fower Ranae Nuclear Instrumentation Power Range Nuclear Instrumentation channels (NI-5, -6, -7 and -8) provide inputs to the following RPS Functions. The ,
| |
| numbers associated with each Function correspond to those used in Table 3.3.1-1.
| |
| : 1. Nuclear Overpower
| |
| : a. Nuclear Overpower--High Setpoint; -
| |
| : b. Nuclear Overpower--Low Setpoint;
| |
| : 8. Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE (Power Imbalance Flow);
| |
| : 9. Main Turbine Trip (Control Oil Pressure); and
| |
| : 10. Loss of Main Feedwater (LOFW.) Pumps (Control Oil Pressure).
| |
| (continued) ,
| |
| Crystal River Unit 3 8 3.3-4 Revision No. 7
| |
| | |
| 1 RPS Instrumentation B 3.3.1 BASES BACKGROUND Power Ranae Nuclear Instrumentation (continued) l l
| |
| The power range nuclear instrumentation consists of four i compensated ion chamber detector channels, one to monitor each quadrant of the core. Each channel supplies an input to one RPS protection channel. The channel originates in a .
| |
| f detector assembly containing two uncompensated ion chambers.
| |
| The ion chambers utilize dual detectors to provide ,
| |
| information on neutron power in the top half and bottom half l of the core. The individual currents from the chambers are '
| |
| fed to individual linear amplifiers. The summation of the top and bottom is the total reactor power. The difference ,
| |
| of the top minus the bottom is input into the determination i of AXIAL POWER IMBALANCE.
| |
| Reactor Coolant System Outlet Temoerature (Tw)
| |
| The Reactor Coolant System Outlet Temperature provides input to the following RPS Functions:
| |
| ~
| |
| j 1
| |
| : 2. RCS High Outlet Temperature; and i
| |
| : 5. RCS Variable Low Pressure.
| |
| RCS Outlet Temperature is measured by two resistance temperature detectors (RTDs) in each hot leg. One RTD is associated with each protection channel.
| |
| Reactor Coolant System Pressure The Reactor Coolant System Pressure provides input to the following Functions:
| |
| : 3. RCS High Pressure;
| |
| : 4. RCS Low Pressure;
| |
| : 5. RCS Variable Low Pressure; and
| |
| : 11. Shutdown Bypass RCS High Pressure.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-5 Revision No. 7
| |
| | |
| e RPS Instrumentation l B 3.3.1 i
| |
| BASES
| |
| ('
| |
| BACKGROUND Reactor Coolant System Pressure (continued)
| |
| The RPS inputs of reactor coolant pressure are provided by i two pressure transmitters in each hot leg, for a total of
| |
| , four. One sensor is associated with each protection 4 channel. ,
| |
| i
| |
| ; Reactor Buildino Pressure i The Reactor Building (RB) Pressure measurements provide input solely to the RB High Pressure trip, Function 6. -
| |
| ; There are four RB High Pressure pressure switches, one j associated with each protection channel.
| |
| i
| |
| : )
| |
| Reactor Coolant Pumo Power Monitorino
| |
| : Reactor Coolant Pump Power Monitors (RCPPMs) are inputs to the Reactor Coolant Pump overpower /underpower trip, l Function 7. The operating current and voltage of each RCP
| |
| ! is measured by four current transformers and four potential
| |
| ! transformers inputting into two watt transducers to develop .
| |
| 1 pump KW. Each power monitoring channel consists of an !
| |
| overpower relay and an underpower relay. There are two pump i power monitor channels provided for each RC pump. Both !
| |
| ! monitoring channels associated with each RCP are needed to i
| |
| 4 meet the single failure criteria. ;
| |
| i <
| |
| Reactor Coolant System Flow l The Reactor Coolant System Flow measurements are an input to the Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE trip, Function 8. The reactor coolant flow inputs to the RPS are provided by eight high accuracy differential pressure transmitters, four on each RCS loop, which measure flow through calibrated flow tubes. One flow input in each loop is associated with each protection channel.
| |
| (continued) 3, 1
| |
| Crystal River Unit 3 8 3.3-6 Revision No. 7 !
| |
| | |
| RPS Instrumentation' B 3.3.1 BASES BACKGROUND Main Turbine Control Oil Pressure (continued)
| |
| Main Turbine Control Oil Pressure is an input to the Main Turbine Trip anticipatory reactor trip, Function 9. Each of the four protection channels receives turbine status information from four identical pressure switches monitoring main turbine automatic stop oil pressure. An open indication will be provided to the RPS on a turbine trip.
| |
| Contact buffers in each protection channel continuously monitor the status of the contact inputs and initiate an RPS trip when a turbine trip is indicatsd.
| |
| i Main Feedwater Pumo Control Oil Pressure Main Feedwater Pump Control Oil Pressure is an input to the Loss of Main Feedwater Pumps trip, Function 10. Control oil pressure is measured by four pressure switches on each feedwater pump. One switch on each pump is associated with each protection channel.
| |
| RPS Bvoasses The RPS is designed with two types of bypasses: channel bypass and shutdown bypass.
| |
| Channel bypass provides a method fo'r placing all Functions in one RPS protection channel in a bypassed condition, and shutdown bypass provides a method of leaving the safety rods withdrawn during cooldown and depressurization of the RCS.
| |
| Each bypass is discussed in more detail below.
| |
| Channel Byoass A channel bypass provision is provided to allow for maintenance and testing of the RPS. The use of channel bypass keeps the protection channel trip relay energized regardless of the status of the instrumentation channel or the bistable relay contacts. In order to place an RPS channel in channel bypass, two conditions must be met.
| |
| First, the other three channels must not be in channel bypass. This interlock prevents more than one channel at a time being placed in bypass and is ensured by in-series (continued)
| |
| Crystal River Unit 3 B 3.3-7 Revision No. 7
| |
| | |
| RPS instrumentation B 3.3.1 BASES
| |
| ("'
| |
| BACKGROUND Channel Byoass (continued) contacts from the other channels with the channel bypass relay. If any contact is open, the second channel cannot be ,
| |
| bypassed. The second condition is the closing of the key l switch. When the bypass relay is energized, the bypass !
| |
| contact closes, maintaining the channel trip relay in an !
| |
| energized condition. All RPS trip logics are reduced to a i two-out-of-three logic in channel bypass. j Shutdown Bvoass During plant cooldown, it is desirable to maintain the !
| |
| safety rods withdrawn to provide shutdown capabilities in !
| |
| the event of unusual positive reactivity additions (moderator dilution, etc.). However, if the safety rods are withdrawn too soon following reactor shutdown as RCS pressure is decreased, an RCS Low Pressure trip will occur at 1800 psig and the rods will re-insert into the core. To avoid this, the protection system allows the operator to -
| |
| bypass the low pressure trip and maintain shutdown capabilities.
| |
| ~
| |
| During the cooldown and depressurization, the safety rods t are inserted prior to the low pressure trip of 1800 psig. '.
| |
| The RCS pressure is decreased to less than 1720 psig, then each RPS channel is placed in shutdown bypass.
| |
| p In shutdown bypass, a normally closed contact opens and the operator closes the shutdown bypass key switch in each RPS channel. This action bypasses the RCS Low Pressure trip, Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE trip, Reactor Coolant Pump overpower /underpower trip, and the RCS Variable Low Pressure trip, and inserts a ,
| |
| new RCS High Pressure, 1720 psig trip. The operator can now !
| |
| withdraw the safety rods for additional available reactivity insertion.
| |
| The insertion of the new high pressure trip performs two functions. First, with a trip setpoint of 1720 psig, the bistable prevents operation at normal system pressure, 1 2155 psig, with a portion of the RPS bypassed. The second ;
| |
| function is to ensure that the bypass is removed prior to l normal operation. When the RCS pressure is increased during )
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-8 Revision No. 7 !
| |
| I
| |
| | |
| RPS instrumentation B 3.3.1 BASES BACKGROUND Shutdown Byoass (continued) a plant heatup, the safety rods are inserted prior to reaching 1720 psig. The shutdown bypass is removed, which returns the RPS to normal, and system pressure is increased to greater than 1800 psig. The safety rods can then be withdrawn and remain at the full out condition for the rest of the heatup. ,
| |
| In addition to the Shutdown Bypass RCS High Pressure trip, the nuclear overpower high flux trip setpoint is administratively reduced to 5% RTP while the RPS is in shutdown bypass. This provides a backup to the Shutdown Bypass RCS High Pressure trip and allows low temperature physics testing while preventing the generation of any significant amount of power.
| |
| Module Interlock and Test / Interlock Trio Relav Each channel and each trip module is capable of being individually tested. When a module is placed into the test mode or is removed from the system, it causes the test /
| |
| interlock trip relay tg de-energize and to indicate an RPS channel trip. Under normal conditions, the channel to be tested is placed in bypass before a module is tested. This ensures the channel trip relay remains energ-ized during testing and the channel does not trip.
| |
| APPLICABLE Each of the analyzed accidents and transients can be SAFETY ANALYSES, detected by one or more RPS Functions. The accident LCO, and analysis contained in Chapter 14 of the FSAR takes credit APPLICABILITY for most RPS trip Functions. Functions not specifically credited in the accident analysis were qualitatively credited in the safety evaluation report (SER) written for the CR-3 operating license. Functions not specifically credited include high RB pressure, high RCS temperature, main turbine trip, shutdown bypass-RCS pressure high, and loss of both main feedwater pumps.
| |
| The LC0 requires all instrumentation performing an .RPS Function to be OPERABLE. Failure of any instrument renders the affected channel (s) inoperable and reduces the j l
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-9 Revision No. 7 I
| |
| | |
| . ._- -- . -. _ - - . - - - - - . . _ ~ .
| |
| RPS fnstrumentation B 3.3.1 BASES
| |
| [
| |
| APPLICABLE reliability of the affected Functions. Four channels of SAFETY ANALYSES, each RPS instrumentation Function listed in Table 3.3.1-1 LCO, and shall be OPERABLE during the MODES and conditions specified APPLICABILITY to ensure that a reactor trip will be actuated if conditions (continued) require. Additionally, during shutdown bypass with any CRD trip breaker closed and the CRDCS capable of rod withdrawal, the applicable RPS Functions must also be OPERABLE. This ensures the capability to trip withdrawn CONTROL RODS at all tinies that rod motion in possible.
| |
| ~
| |
| Reduired Actions allow naintenance (protection channel) bypass of individual ctannels, but the bypass activates interlocks that ensure only one channel can be bypassed at a i time. Bypass effectively places the trip system in a two-out-of-three logic configuration that can still initiate a reactor trip, even with a coincident single failure within the system.
| |
| Only the Allowable Values are specified in Table 3.3.1-1.
| |
| Nominal trip setpoints are specified in the plant specific ,
| |
| setpoint calculations and procedures. The nominal setpoints '
| |
| are selected to ensure that the setpoint measured by CHANNEL FUNCTIONAL TESTS does not exceed the Allowable Value if the -
| |
| bistable is performing as required. Operation with a trip '
| |
| setpoint less conservative than the nominal trip-setpoint, but within its Allowable Value, is acceptable provided that operation and testing are consistent with the assumptions of specific setpoint calculations. Each Allowable Value specified is more conservative than instrument uncertainties ,
| |
| appropriat to the trip Function. The Allowable Values for bypass removal Functions are stated in the Applicable MODE c or Other Specified Condition column of Table 3.3.1-1.
| |
| The safety analyses applicable to each RPS Function are discussed next.
| |
| : 1. Nuclear Overoower
| |
| : a. Nuclear Overoower-Hiah Setooint i The Nuclear Overpower-High Setpoint trip initiatos a reactor trip when the neutron power reaches a pre-defined setpoint corresponding to the design overpower limit. Because THERMAL POWER lags neutron power, tripping the reactor (continued)
| |
| Crystal River Unit 3 8 3.3-10 Revision No. 7
| |
| | |
| RPS Znstrumentation B 3.3.1 BASES APPLICABLE a. Nuclear Overoower - Hiah Setooint (continued)
| |
| SAFETY ANALYSES, LCO, and when the nc +ron power reaches the design APPLICABILITY overpower wil: limit THERMAL POWER to a maximum value of the design overpower.
| |
| Because it serves to limit THERMAL POWER levels the Nuclear Overpower--High Setpoint trip protects against violation of the DNBR and fuel centerline melt SLs. However, th.e RCS Variable Low Pressure, and Nuclear Overpow'er RCS Flow and Measured AXIAL POWER IMBALANCE, provide more direct protection of these Safety Limits. The role of the Nuclear Overpower--High Setpoint trip is to limit reactor THERMAL POWER below the highest power at which the other two trips are known to provide protection.
| |
| The Nuclear Overpower--High Setpoint trip also provides transient protection for rapid positive reactivity excursions during power operations.
| |
| These events include the rod withdrawal accident, the rod ejection accident, and the steam line break accident. By providing a trip during these events, the Nuclear Overpower--High Setpoint trip protects against excessive power levels and also serves to reduce' reactor power to prevent violation of the RCS pressure SL.
| |
| Rod withdrawal accident analyses cover a large spectrum of reactivity insertion rates (rod worths), including slow and rapid rates of power increase. At high reactivity insertion rates, the Nuclear Overpower--High Setpoint trip provides the primary protection. At low reactivity insertion rates, the high RCS pressure trip provides primary protection. The specified Allowable Value is selected to ensure that a trip occurs before reactor power exceeds the highest point at which the RCS Variable Low Pressure and the Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE trips are analyzed to provide protection against DNB and fuel centerline melt.
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-11 Revision No. 7
| |
| | |
| ; RPS Instrumentation B 3.3.1 BASES
| |
| (,s.
| |
| APPLICABLE a. Nuclear Overoower - Hioh Setooint SAFETY ANALYSES, (continued)
| |
| LCO, and The Allowable Value does not account for harsh APPLICABILITY environment induced errors, because the trip will actuate prior to degraded environmental conditions being reached.
| |
| : b. Nuclear Overoower-Low Setooint While in shutdown bypass, with the Shutdown Bypass RCS High Pressure trip OPERABLE, the Nuclear Overpower setpoint trip must be administratively reset to :s; 5% RTP. The low power setpoint, in conjunction with the 1720 psig Shutdown Bypass RCS High Pressure setpoint, -
| |
| ensure the plant is protected from excessive power conditions when other RPS trips are bypassed. The Allowable Value was chosen to be as low as practical and still lie within the range of the power range nuclear instrumentation.
| |
| ~
| |
| : 2. RCS Hioh Outlet Temoerature j The RCS High Outlet Temperature trip, in conjunction with the RCS Low Pressure and RCS Variable Low Pressure trips, provides protection for the DNBR SL.
| |
| A trip is initiated whenever RCS hot leg temperature approaches the conditions necessary for DNB. Portions of each RCS High Outlet Temperature trip channel are common with the RCS Variable Low Pressure trip. The RCS High Outlet Temperature trip provides steady state protection for the DNBR SL.
| |
| The RCS High Outlet Temperature trip limits the maximum RCS temperature to below the highest value for which DNB protection by the Variable Low Pressure trip is ensured. The Allowable Value is selected to ensure that a trip occurs before hot leg temperatures reach the point beyond which the RCS Low Pressure and Variable Low Pressure trips are analyzed. The (continued)
| |
| Crystal River Unit 3 B 3.3-12 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1 BASES APPLICABLE 2. RCS Hiah Outlet Temoerature (continued)
| |
| SAFETY ANALYSES, LCO, and Allowable Value does not reflect errors induced by APPLICABILITY harsh environmental conditions that the equipment is expected to experience because the trip is not required to mitigate accidents that create harsh conditions in the RD.
| |
| : 3. RCS Hioh pressure The RCS High Pressure trip functions in conjunction with the pressurizer and main steam safety valves to prevent RCS overpressurization, thereby protecting the RCS Pressure SL.
| |
| The RCS High Pressure trip has been credited in the accident analysis calculations for slow positive reactivity insertion transients (rod withdrawal accidents and moderator dilution) and loss of feedwater accidents. The rod withdrawal accidents cover a large spectrum of reactivity insertion rates and rod worths that exhibit slow and rapid rates of power increases. At high reactivity insertion rates, the Nuclear Overpower-High Setpoint trip LCO, and provides the primary protection. At low reactivity insertion rates, the RCS High Pressure trip provides the primary protection.
| |
| The Allowable Value is selected to ensure that the RCS Pressure SL is not challenged during steady state operation or slow power increasing transients. The Allowable Value does not reflect errors induced by harsh environmental conditions because the equipment is not required to mitigate accidents that create harsh conditions in the RB.
| |
| : 4. RCS Low Pressure The RCS Low Pressure trip, in conjuncti'on with the RCS High Outlet Temperature and Variable Low Pressure trips, provides protection for the DNBR SL. A trip is initiated whenever the system pressure approaches the (continued)
| |
| Crystal River Unit 3 8 3.3-13 Revision No. 7 i
| |
| | |
| RPS instrumentation B 3.3.1 BASES
| |
| [u' .
| |
| 1 APPLICABLE 4. RCS Low Pressure (coontinued)
| |
| SAFETY ANALYSES, LCO, and conditions necessary for DNB. The RCS Low Pressure !
| |
| APPLICABILITY setpoint Allowable Value is selected to-ensure that a l reactor trip occurs before RCS pressure is reduced below the lowest point at which the RCS Variable Low Pressure trip is analyzed. The RCS Low Pressure trip provides protection for primary system depressurization events and is credited in the accident analysis calculations for small break loss of coolant accidents (SBLOCAs). Consequently, harsh RB
| |
| . conditions created as a result of SBLOCAs can potentially affect performance of the RCS pressure sensors and transmitters. Therefore, degraded environmental conditions are considered in the Allowable Value determination.
| |
| : 5. RCS Variable low Pressure The RCS Variable Low Pressure trip, in conjunction with the RCS High Outlet Temperature and RCS Low Pressure trips, provide protection for the DNBR SL. g The Allowable Value is selected such that a trip is -
| |
| initiated whenever RCS pressure and temperature 2 approach the conditions necessary for DNB. The RCS Variable Low Pressure trip provides a varying low pressure trip based on the RCS High Outlet Temperature within the range specified by the RCS High Outlet Temperature and RCS Low Pressure trips.
| |
| The RCS Variable Low Pressure trip is not credited in !
| |
| the safety analysis; therefore, determination of the setpoint Allowable Value does not account for errors induced by a harsh RB environment.
| |
| : 6. Reactor Buildina Hiah Pressure The Reactor Building High Pressure trip provides an early indication of a high energy line break (HELB) inside the RB. By detecting' changes in the RB ,
| |
| , pressure, the RPS can provide a reactor trip before j (continued)
| |
| Crystal River Unit 3 8 3.3-14 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1
| |
| . BASES APPLICABLE 6. Reactor Buildina Hioh Pressure (continued) l SAFETY ANALYSES, l LCO, and the other RCS parameters have varied significantly; I APPLICABILITY thus, minimizing accident consequences. This trip !
| |
| Function also provides a backup to RPS trip strings exposed to an RB HELB environment.
| |
| The Allowable Value for RB High Pressure trip is at the lowest value consistent with avoiding spurious
| |
| , trips during normal operation. The electronic components of the RB High Pressure trip are located in an area outside the RB and are not exposed to high temperature steam environments during a LOCA.
| |
| However, the components would be potentially exposed to high radiation levels. Therefore, the determination of the setpoint Allowable Value accounts for errors induced by the high radiation.
| |
| : 7. Reactor Coolant Pumo Power Monitors The Reactor Coolant Pump Power Monitor (RCPPM) trip provides protection for changes in the reactor coolant flow due to the loss of multiple RCPs. Because the flow reduction lags loss of power indications due to the inertia of the RCPs, the trip initiates protective action earl.ier than a trip based on a measured flow signal.
| |
| The trip also prevents single loop operation (operation with both pumps in an RCS loop tripped).
| |
| Under these conditions, core flow and core fluid mixing are insufficient for adequata hat transfer.
| |
| The RCPPM trip has been credited in the accident analysis calculations for the loss of four RCPs. The monitors were added as part of the power level upgrade (2452 to 2544 MW.) to provide DNB protection at greater than 97% RTP. Analyses has shown this trip Function is not necessary when conditions are such that THERMAL POWER is less than 2475 MW and four RCPs are in operation (Ref. 8).
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-15 Revision No. 7 1
| |
| | |
| RPS Znstrumentation B 3.3.1
| |
| ! BASES fn '
| |
| \.
| |
| APPLICABLE 7. Reactor Coolant Power Pumo Monitors SAFETY ANALYSES, (continued) !
| |
| LCO, and The Allowable Value for the Reactor Coolant Pump to APPLICABILITY Power trip setpoint is selected to prevent normal (continued) power operation unless at least three RCPs are operating. RCP status is monitored by two power transducers on each pump. These relays indicate a i loss of an RCP on overpower with an Allowable Value of 2: 14,400 kW and on underpower with a setpoint of 1 s 1152 kW. The overpower setpoint is selected low enough to' detect locked rotor conditions (although credit is not allowed for this capability) but high enough to avoid a spurious trip due to the current associated with start of an RCP. The underpower Allowable Value is selected to reliably trip on loss of voltage to the RCPs. The RCPPM satpoints do not account for instrumentation errors caused by harsh environments because the trip Function is not required to respond to events that could create harsh environments around the equipment.
| |
| There are two pump power monitors provided for each i RCP. Both monitors are required to satisfy the .-
| |
| instrumentation channel requirements of this LCO. !
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-16 Revision No. 7
| |
| %s u m - r
| |
| | |
| RPS Instrumentation B 3.3.1 BASES APPLICABLE 8. Nuclear Overoower RCS Flow and Measured AXIAL POWER i SAFETY ANALYSES, IMBALANCE LCO, and APPLICABILITY The Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE trip provides steady state protection ;
| |
| (continued) for the power imbalance SLs. A reactor trip is ,
| |
| initiated when neutron power AXIAL POWER IMBALANCE, and reactor coolant flow conditions indicate an approach to DNB or fuel centerline melt limits.
| |
| This trip supplements the ilrotection provided by the Reactor Coolant Pump Power trip, through the power to flow ratio, for loss of reactor coolant flow events. .
| |
| The power to flow ratio provides direct protection for i the DNBR SL for the loss of a single RCP and for locked RCP rotor accidents. The imbalance portion of the trip is credited for steady state protection only.
| |
| The power to flow ratio of the Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE trip also provides steady state protection to prevent reactor power from exceeding the allowable power during three '
| |
| l pump operation. Thus, the power to flow ratio i prevents overpower conditions similar to the Nuclear Overoower trip. This protection ensures that during reduced flow conditions the core power is maintained below that required to initiate DNB.
| |
| The Allowable Value is selected to ensure that a trip occurs when the core power, axial power peaking, and reactor coolant flow conditions indicate an approach to DNB or fuel centerline melt limits. By measuring reactor coolant flow and by tripping only when conditions begin to approach an SL, 3 pump operation can be justified. The Allowable Value for this Function is contained in the COLR due to the cycle- !
| |
| specific nature of the limit. i
| |
| : 9. Main Turbine Trio (Control Oil Pressure)
| |
| The Main Turbine Trip Function provides an early '
| |
| reactor trip in anticipation of the loss of heat sink associated with a turbine trip. The Main Turbine Trip *
| |
| }
| |
| - (continued) l Crystal River Unit 3 8 3.3-17 Revision No. 7 l
| |
| l l
| |
| l
| |
| | |
| - - - . ~ . - - - - - . . - - - . - - -, . - - . - - . - - . -
| |
| l RPS Instrumentation 1 8 3.3.1 l 1
| |
| BASES '"' i I: !
| |
| L APPLICABLE 9. Main Turbine Trio (Control Oil Pressure)
| |
| SAFETY ANALYSES, (continued)
| |
| LCO, and !
| |
| Function was added to B&W plants in accordance with 1
| |
| 4 APPLICABILITY !
| |
| NUREG-0737 (Ref. 4) following the Three Mile Island j i
| |
| ; Unit 2 accident. The trip lowers the probability of an RCS power operated relief valve (PORV) actuation i for turbine trip events. This trip is activated at !
| |
| higher power levels, thereby limiting the range through which the Integrated Control System must provide an automatic runback on a turbine trip.
| |
| l J, Each of the four turbine oil pressure switches .
| |
| i provides input to an associated RPS channel through buffers that continuously monitor the status of the contacts. Failure of an individual pressure switch
| |
| , affects only the associated RPS channel.
| |
| For the Main Turbine Trip (Control Oil Pressure)
| |
| : bistable, the Allowable Value of 45 psig was selected to provide a trip whenever turbine control oil pressure drops below the normal operating range. To
| |
| ' ensure that the trip is enabled as required by the LCO, an automatic bypass at reactor power Allowable Value' of 45% RTP is provided. The turbine trip is not I required to protect against events that create a harsh I
| |
| environment in the turbine building. Therefore, errors induced by harsh environments are not included i in the determination of the setpoint Allowable Value.
| |
| 4
| |
| : 10. loss of Main Feedwater Pumos (Control Oil Pressure)
| |
| The Loss of Main Feedwater Pumps (Control Oil Pressure)- trip Function provides an early reactor trip in anticipation of the loss of heat sink associated with a LOFW event. This trip was added in accordance with NUREG-0737 (Ref. 4), following the Three Mile Island Unit 2 accident. This trip provides a reactor trip at high power levels following a LOFW to minimize challenges to the PORV.
| |
| (continued)
| |
| Crystal River Unit 3- B 3.3 Revision No. 7
| |
| | |
| 1 RPS Instrumentation B 3.3.1 BASES APPLICABLE 10. Loss of Main Feedwater pumos (Control Oil Pressure)
| |
| SAFETY ANALYSES, (continued)
| |
| LCO, and i APPLICABILITY For the feedwater pump control oil pressure bistable, the Allowable Value of 55 psig is selected .to provide j a trip whenever feedwater pump control oil pressure j drops below the normal operating range. To ensure ;
| |
| that the trip is enabled as required by the LCO, the ;
| |
| reactor power bypass is set with an Allowable Value of ;
| |
| 20% RTP. The Loss of Main Feedwater Pumps (Control
| |
| '0il Pressure) trip is not required to protect against events that can create a harsh environment in the turbine building. Therefore, errors caused by harsh "
| |
| environments are not included in the determination of the setpoint Allowable Value. l
| |
| : 11. Shutdown Byoass RCS Hiah Pressure The RPS Shutdown Bypass RCS High Pressure TRIP is provided to allow for withdrawing the CONTROL RODS '
| |
| prior to reaching the normal RCS Low Pressure trip setpoint. The shutdown bypass provides trip .
| |
| protection during deboration and RCS heatup by allowing the operator to withdraw the safety rod groups. This makes additional negative reactivity readily available to terminate inadvertent reactivity excursions. Use of the shutdown bypass trip requires that the nuclear overpower trip setpoint be administratively reduced to s 5% RTP. The Shutdown Bypass RCS High Pressure trip forces a reactor trip to occur whenever the plant switches from power operation to shutdown bypass or vice versa. This ensures that all CONTROL RODS are inserted and the flux distribution is known before reactor startup can i begin. The operator is required to remove the ;
| |
| shutdown bypass, reset the Nuclear Overpower-High ;
| |
| Power trip setpoint, and again withdraw the safety rod groups before proceeding with startup.
| |
| FSAR, Chapter 14, (Ref. 2), accident analysis does not address events that occur during shutdown bypass )
| |
| operation, because the consequences of these events l ar: assumed to be enveloped by the MODE 1 events that are presented.
| |
| I (continued) j l
| |
| Crystal River Unit 3 8 3.3-19 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1 BASES
| |
| \r '.
| |
| APPLICABLE 11. Shutdown Bvoass RCS Hiah Pressure SAFETY ANALYSES, (continued)
| |
| LCO, and During shutdown bypass operation with the Shutdown APPLICABILITY Bypass RCS High Pressure trip active with a setpoint of <; 1720 psig and the Nuclear Overpower-Low Setpoint set at or below 5% RTP, the trips listed below can be bypassed. Under these conditions, the Shutdown Bypass RCS High Pressure trip and the Nuclear Overpow'er-Low Setpoint trip prevent conditions from reaching a point where actuation of these Functions would be re. quired.
| |
| l 1.a Nuclear Overpower-High Setpoint;
| |
| : 4. RCS Low Pressure; 1
| |
| : 5. RCS Variable Low Pressure; 1 1
| |
| : 7. Reactor Coolant Pump Power Monitors; and '
| |
| : 8. Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE.
| |
| The Shutdown Bypass RCS High Pressure Function's .-
| |
| Allowable Value is selected to ensure a trip occurs !
| |
| before producing THERMAL POWER.
| |
| The RPS satisfies Criterion 3 of the NRC Policy Statement. j In MODES 1 and 2, the following trips shall be i OPERABLE. These trips are designed to rapidly make i the reactor subcritical in order to protect the SLs during A00s and to function along with the ESAS to provide acceptable consequences during accidents, l.a Nuclear Overpower-High Setpoint;
| |
| : 2. RCS High Outlet Temperature;
| |
| : 3. RCS High Pressure;
| |
| : 4. RCS Low Pressure;
| |
| : 5. RCS Variable Low Pressure;
| |
| . (continued)
| |
| Crystal River Unit 3 8 3.3-20 Revision No. 7
| |
| | |
| RPS instrumentation B 3.3.1 BASES .
| |
| APPLICABLE 11. Shutdown Bvoass RCS Hioh Pressure (continued)
| |
| SAFETY ANALYSES, LCO, and 7. Reactor Coolant Pump Over/Under Power; and APPLICABILITY
| |
| : 8. Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE.
| |
| Functions 1, 4, 5, 7, and 8 may be bypassed in MODE 2 or below (higher numerical MODE) when RCS pressure is below 1720 psig, provided the, Shutdown Bypass RCS High Pressure and the Nuclear Overpower-Low setpoint trip are placed in operation. Under these conditions, the Shutdown Bypass RCS High Pressure trip and the Nuclear Overpower-Low setpoint trip prevent conditions from reaching a point where actuation of these Functions is necessary.
| |
| Two other Functions are required to be OPERABLE during portions of MODE 1. These are the Main Turbine Trip (Control Oil Pressure) and the Loss of Main Feedwater Pumps (Control Oil Pressure) trip. The:e Functions are required to be OPERABLE above 45% RTP and 20% RTP, respectively.
| |
| Analyses presented in SW-1893 (Ref. 5) showed that for operation below these pom levels, these trips are not necessary to minimize challenges to the PORVs as required by NUREG-0737 (Ref. 4).
| |
| Because the only safety function of the RPS is to interrupt power to the CONTROL RODS, the RPS is not required to be OPERABLE in MODE 3, 4, or 5 if the reactor trip breakers are open, or the CRDCS is incapable of rod withdrawal.
| |
| Similarly, the RPS is not required to be- OPERABLE i.n MODE 6 when the CONTROL RODS are decoupled from the CRDs. However, in MODE 2, 3, 4, or 5, the Shutdown Bypass RCS High Pressure and Nuclear Overpower-Low Setpoint trip Functions are required to be OPERABLE if the CRD trip breakers are closed and the CRDCS is capable of rod withdrawal. Under these conditions, the Shutdown Bypass RCS High Pressure and Nuclear Overpower-Low setpoint trips are sufficient to prevent an approach to conditions that could challenge SLs.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-21 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1 BASES (continued) .
| |
| {
| |
| ACTIONS Conditions A, B, and D are applicable to all RPS protection Functions. If a channel's trip setpoint is found nonconservative with respect to the required Allowable Value in Table 3.3.1-1, or any individual component in the trip string is found inoperable (with the exception of the RCPPM), the channel must be declared inoperable. Conditions C and E address the appropriate ACTIONS for an inoperable RCPPM from the sensor to the output of'the watt transducer.
| |
| Inoperable components downstream of the watt transducers are addressed by Conditions A and B.
| |
| 8d ,
| |
| If one or more Functions in an RPS channel become inoperable, the affected channel must be placed in bypass or trip within 1 hour. If the channel is bypassed, the RPS is placed in a two-out-of-three logic configuration and the bypass of any other channel is prevented. In this configuration, the RPS can still perform its safety function given a single failure of any other channel. Operation in the two-out-of-three configuration may continue indefinitely based on the NRC SER for BAW-10167, Supplement 2 (Ref. 6). ,
| |
| In this configuration, the RPS is capable of performing its (
| |
| trip Function in the presence of any single random failure.
| |
| Alternatively, the inoperable channel can be placed in trip.
| |
| Tripping the affected protection channel places the RPS in a one-out-of-three configuration.
| |
| The 1 hour Completion Time is of adequate duration to perform Required Action A.1. Thus, the 1 hour Completion Time is based on engineering judgment.
| |
| B.1 and B.2 If one or more Functions in two channels become inoperable, one of the two inoperable channels must be placed in trip and the other in bypass. These Required Actions place all RPS Functions in a one-out-of-two logic configuration and prevent bypass of a second channel. In this configuration, the RPS can still perform its safety functions in the presence of a single failure of any channel. The 1 hour .
| |
| Completion Time is of adequate duration to perform Required Action B.1 and Required Action B.2. Thus, the 1 hour Completion Time is based on engineering judgment.
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-22 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1 BASES
| |
| , ACTIONS L.1 (continued)
| |
| If one or both RCPPMs associated with a single RCP are inoperable, the RCPPM must be placed in the trip condition ;
| |
| within 4 hours. Placing one of the RCPPMs for the pump in l the tripped condition restores the single failure aspect of the design of the Function. This ACTION also places the RPS )
| |
| 1 4
| |
| Function in a condition where only one additional RCPPM '
| |
| associated with another RCP need indicate a loss of its ,
| |
| associated RCP to initiai.e a reactor trip. Since each RCPFM '
| |
| provides input to all four RPS channels, care must be exercised when surveillance testing RCPPM coincident with !
| |
| operation in this Condition. The 4 hour Completion Time is l adequate to perform Required Action C.1 and is acceptable i
| |
| , based upon engineering judgment. j L .
| |
| D.1 and 0.2 i
| |
| Required Action D.1 directs entry into the appropriate Function-dependent Condition referenced in Table 3.3.1-1. ;
| |
| Whenever a Required Action of Condition A or 8, and the associated Completion Time are not met, Condition D directs the operator to the Condition containing the appropriate ACTIONS.
| |
| E.1.1. E.1.2. and E.2 If the. Required Actions and associated Completion Times of Condition C are not met, the plant must be placed in a MODE or condition in which the RCPPM are not required to be OPERABLE. To achieve this status, four reactor coolant pumps must be verified to be in operation and THERMAL POWER must be reduced to less than 2475 MW. within one hour. The Required Actions are based upon analysis (Ref. 8) which demonstrates that the Nuclear Overpower RCS Flow and Measured AXIAL POWER IMBALANCE RPS Function provides adequate protection of DNBR limits for loss of coolant flow accidents postulated to occur under these conditions. Thus, the RCPPM Function is not required. Similar analysis for three RCP operation was never approved. The allowed Completion Times of one hour are reasonable, based on I operating experience, to perform the specified Required Actions.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-23 Revision No. 7
| |
| | |
| _._ . . _ _ _ . _ _ - . _ _ _ _. _ _ _ _ . ~ . ._ __ _ _ _ _ _ . _ _ . . - .
| |
| 1
| |
| )
| |
| RPS Instrumentation !
| |
| B 3.3.1 l 1
| |
| -BASES . th l ACTIONS E.1.1. E.1.2. and E.2 (continued)
| |
| As an alternative to Required Action E.1.1 and Required i Action E.1.2, Condition F may be entered within one hour. .
| |
| This results in placing the plant in MODE 3 and opening the !
| |
| CRD trip breakers within 6 hours. This is the default !
| |
| - Condition in the event the Required Actions for an ;
| |
| inoperable RPS RCPPM Function channel cannot be completed in !
| |
| the specified Completion Time, As such, this ACTION is conservative. Again, the allowed Completion Time of one ,
| |
| hour is reasonable, based on engineering judgment, to perform the specified Required Action. .
| |
| j F.1 and F.2 !
| |
| If the Required Action and associated Completion Time of Condition A or B are not met and Table 3.3.1-1 directs entry into Condition F, the 9 nt must be placed in a MODE in which the specified Rb trip Functions are not required to be OPERABLE. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and to open l all CRD trip breakers without challenging' plant systems. k 9d r If the Required Action and associated Completicn Time of I Condition A or B are not met and Table 3.3.1-1 directs entry '
| |
| ~
| |
| into Condition G, the plant must be placed in a MODE in ;
| |
| which the specified RPS trip Functions are not required to i' be OPERABLE. To achieve this status,^all CRD trip breakers must be opened. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to open CRD trip breakers without challenging plant systems.
| |
| L (continued) ,, !
| |
| Crystal River Unit 3 B 3.3 24 Revision No. 7 j
| |
| _m --..m
| |
| | |
| RPS Instrumentation B 3.3.1 BASES ACTIONS 1L1 (continued)
| |
| If the Required Action and associated Completion Time of Condition A or B are not met and Table 3.3.1-1 directs entry into Condition H, the plant must be placed in a MODE in which the specified RPS trip Function is not required to be OPERABLE. To achieve this status, THERMAL POWER must be reduced < 45% RTP. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach 45% RTP from full power conditions in an orderly reanner without challenging plant systems.
| |
| L.1 If the Required Action and associated Completion Time of -
| |
| Condition A or B are not met and Table 3.3.1-1 directs entry into Condition I, the plant must be placed in a MODE in which the specified RPS trip Function is not required to be OPERABLE. To achieve this status, THERMAL POWER must be reduced < 20% RTP. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach 20% RTP from full power conditions in an orderly manner without challenging plant systems.
| |
| SURVEILLANCE The SRs are modified by a note indicating the SR required REQUIREMENTS for each RPS Function are identified by the SRs column of Table 3.3.1-1. Most Functions are subject to CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION, with those
| |
| ; credited in the accident analysis also requiring RPS l RESPONSE TIME testing.
| |
| SR 3.3.1.1 Performance of the CHANNEL CHECK once every 12 hours ensures that a gross failure of instrumentation has not occurred.
| |
| For the majority of RPS functions, the CHANNEL CHECK consists of a comparison of the parameter indic.ted on one channel to 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, (continued)
| |
| Crystal River Unit 3 8 3.3-25 Revision No. 7 l
| |
| l l
| |
| | |
| RPS Instrumentation B 3.3.1 BASES
| |
| {-
| |
| SURVEILLANCE SR 3.3.1.1 (continued)
| |
| REQUIREMENTS Significant deviations between two instrument channels could 3 be an indication of excessive instrument drift in one of the channels or of something even more serious. In the case of the Reactor Building High Pressure, Main Turbine Trip, and Loss of Main Feedwater Pumps Trip' Functions, the CHANNEL ;
| |
| CHECK is more qualitative in nature. For these Functions, '
| |
| the SR cannot be accomplished by comparing indication of the parameter on the individual channels. .Instead, the CHANNEL CHECK consists of a verification the channel trip light is not illuminated. While this'does not provide the same level of detail as the indication comparison, it does provide some i confidence that a channel failure will be detected in the '
| |
| interval between CHANNEL FUNCTIONAL TESTS.
| |
| Acceptar e criteria for the CHANNEL CHECK are determined by the plant staff and presented in the Surveillance Procedure.
| |
| The criteria may consider, but is not limited to channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the acceptance criteria, it may be an indication that the transmitter or the signal processing equipment has excessively drifted. If ~
| |
| the channels are within the acceptance criteria, it is an indication that the channels are OPERABLE.
| |
| The 12 hour Frequency'is based on operating experience that demonstrates channel failure is an infrequent occurrence.
| |
| SR 3 . 3 .1. P, I SR 3.3.1.2 is a heat balance calibration for the power range nuclear instrumentation channels. The heat balance is performed once every 24 hours when reactor power is
| |
| > 15% RTP and consists of a comparison of the results of the l calorimetric with each power range channel output. The outputs of the power range channels are normalized to the calorimetric. If the calorimetric exceeds the NI channel i output by > 2% RTP, the NI must be adjusted. In this Condition, the trip Functions which receive an input from the NI are not considered inoperable provided the channel is !
| |
| adjusted to within the limit. A Note clarifies that this (continued)
| |
| Crystal River Unit 3 8 3.3-26 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1 BASES -
| |
| SURVEILLANCE SR 3.3.1.2 (continued)
| |
| REQUIREMENTS Surveillance is required only when reactor power is 215% RTP and that 24 hours is allowed for performing the first Surveillance after reaching 15% RTP. This SR 3.0.4 type allowance is provided since at lower power levels, calorimetric data tends to be inaccurate.
| |
| The power range channel's output must be adjusted consistent with the calorimetric results if the calorimetric exceeds the power range channel's output by > 2% RTP. The value of 2% is consistent with the value assumed in the safety analyses of FSAR, Chapter 14 (Ref. 2) accidents. These checks and, if necessary, the adjustment of the power range channels ensure that channel accuracy is maintained within the error margins assumed in the analysis. The 24 hour Frequency is adequate, based on plant operating experience, which demonstrates the change in the difference between the power range indication and the calorimetric results rarely exceeds a small fraction of 2% in any 24 hour period.
| |
| Furthermore, the control room operators monitor redundant indications and alarms to detect deviations in channel outputs.
| |
| SR 3.3.1.3 A comparison of power range nuclear instrumentation channels (excores) against incore detectors shall be performed at a 31 day Frequency when reactor power is 1 30% RTP. A Note clarifies that 24 hours is allowed for performing the first Surveillance after reaching 15% RTP. If the absolute difference between the power range and incore measurements is 2 2.5% RTP, the trip Functions which receive an input from the NI are not considered inoperable, but a CHANNEL CALIBRATION that adjusts the measured imbalance to agree with the incore measurements is necessary. If the power range channel cannot be properly recalibrated, the channel is declared inoperable. The calculation of the Allowable Value envelope assumes a difference in out of core to incore measurements of 2.5%. Additional inaccuracies beyond those that are measured are also included in the setpoint envelope calculation. The 31 day Frequency is adequate, considering ;
| |
| that long term drift of the excore linear amplifiers is !
| |
| l l
| |
| , (continued)
| |
| Crystal River Unit 3 B 3.3-27 Revision No. 7
| |
| | |
| RPS Instrumentation B 3.3.1
| |
| . BASES
| |
| ("'
| |
| SURVEILLANCE SR 3.3.1.3 (continued)
| |
| REQUIREMENTS small and depletion of the detectors is slow. Also, the excore readings are a strong functior of the power produced in the peripheral fuel bundles, and oc not represent an integrated reading across the core. The slow changes in neutron flux during the fuel cycle can also be detected at this interval.
| |
| 9 SR 3.3.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required RPS channel to ensure that the entire channel will perform the intended function. Setpoints must be found within the Allowable Values specified in Table 3.3.1-1.
| |
| The Frcquency of 45 days on a STAGGERED TEST BASIS results in each channel being tested every 6 months and is based on the results of the analysis approved in Reference 7. That analysis indicates the RPS retains a high level of reliability for this test interval.
| |
| i SR 3.3.1.5 This SR is the performance of a CHANNEL CALIBRATION of Functions utilizing an NI signal in the trip logic. This CHANNEL CALIBRATION normalizes the power range channel output to the calorimetric coincident with the imbalance output being normalized to the imbalance condition predicted by the incore neutron detector system.
| |
| The calibration for both imbalance and total power is integrated in the power imbalance detector calibration procedure. Operating experience has shown the reliability of the trip string is acceptable when calibrated on a 92 day interval. Thus, the Frequency is based on engineering judgment.
| |
| 1 1
| |
| 1
| |
| . (continued)
| |
| Crystal River Unit 3 B 3.3-28 Revision No. 7 l
| |
| I
| |
| | |
| ~
| |
| RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.5 (continued)
| |
| REQUIREMENTS This Surveillance is modified by two Notes. The first 7
| |
| clarifies that neutron detectors and RC flow sensors (tubes) l are not required to be tested as part of this Surveillance.
| |
| I In the case of the neutron detectors,Furthermore, there is no adjustment adjustment that can be made to the detectors.
| |
| of the detectors is unnecessary because they are passive Slow changes in detector devices with minimal drift.
| |
| sensitivity are compensated for by performing the daily calorimetric calibration and the monthly axial channel calibration. RCS flow detectors are excluded from this SR, but are surveilled as part of SR 3.3.1.6 on a refueling basis. This is based on their inaccessibility during power The second note clarifies that the bypass operations.
| |
| function associated with the test Functions need only be performed once per fuel cycle. This is consistent with the definition of CHANNEL CALIBRATION.
| |
| SR 3.3.1.6 The CHANNEL CALIBRATION is a complete check of the instrument channel, including the sensor. The 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 drift to ensure that the instrument channel remains operational The 24 month Frequency is based between successive tests.
| |
| on the results of a review of instrument drift data conducted in accordance with NRC Generic Letter 91-04.
| |
| A Note to the Surveillance indicates that neutron detectors and RCPPM current and voltage sensors are excluded from In the case of the neutron detectors, CHANNEL CALIBRATION.
| |
| this Note is necessary because of the difficulty inExcluding generating an appropriate dete. c tor input signal.
| |
| the detectors is acceptable because the principles of detector response.
| |
| operation ensure a virtually instantaneousRCPPM qurre due to the fact no adjustments can be made to these sensors.
| |
| (continued)
| |
| I Revision No. 7 Crystal River Unit 3 8 3.3-29
| |
| | |
| 1 RPS fnstrumentation B 3.3.1 BASES t
| |
| SURVEILLANCE SR 3 . 3.1. 7_
| |
| REQUIREMENTS (continued) This SR verifies individual channel actuation response times are less than or equal to the maximum values assumed in the accident analysis. Individual component response times are not modeled in the analyses. The analyses model the overall, or total, elapsed time from the point at which the parameter exceeds the analytical limit at the sensor to the point of rod insertion. Response time testing acceptance
| |
| . criteria are included in Reference 1.
| |
| A Note to the Surveillance indicates that neutron detectors !
| |
| and RCPPM current and voltage sensors and the watt transducer are excluded from RPS RESPONSE TIME testing. l This Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding i i
| |
| the detectors is acceptable because the principles of !
| |
| detector operation ensure a virtually instantaneous response.
| |
| Response time tests are conducted on an 24 month STAGGERED l
| |
| ?EST BASIS. This results in testing all four RPS channels every 96 months. The 96 month Frequency is based on operating experience, which shows that random failures of instrumentation components causing serious response time l degradation, but not channel failure, are infrequent I occurrences. .
| |
| REFERENCES 1. FSAR, Chapter 7.
| |
| : 2. FSAR, Chapter 14.
| |
| : 3. 10 CFR 50.49.
| |
| : 4. NUREG-0737, November 1979.
| |
| : 5. BAW-1893.
| |
| : 6. NRC SER for BAW-10167, Supplement 2, July 8, 1992.
| |
| : 7. NRC SER for BAW-10167A and Supplement 1, December 5, 1988.
| |
| : 8. Amendment No. 56 to the CR-3 Technical Specifications, dated July 16, 1982.
| |
| Crystal River Unit 3 B 3.3-30 Revision No. 7
| |
| | |
| CRD Trip Devices B 3.3.4 BASES ACTIONS _.1 E and E.2 (continued) If the Required Actions of Condition A, B, or C are not met within the associated Completion Time while the plant is in MODE 4 or 5, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, all CRD trip breakers must be opened or all power to the CRDCS removed within 6 hours. The Completion Time of 6 hours is reasonable, based on operating experience, to open all CR0 trip breakers or remove all power to the CRDCS without challenging plant systems.
| |
| SURVEILLANCE SR 3.3.4.1 REQUIREMENTS SR 3.3.4.1 is a CHANNEL FUNCTIONAL TEST to the CRD trip devices once every 31 days. This test verifies the OPERABILITY of the trip devices by actuation of the end devices. Also, this test independently verifies the undervoltage and shunt trip mechanisms of the CRD trip
| |
| # breakers. The Frequency of 31 days is based on operating experience, which has demonstrated that failure of more than one trip device in any 31 day interval is unlikely.
| |
| : 1. FSAR, Chapter 7.
| |
| REFERENCES
| |
| =
| |
| A l
| |
| Amendment No. 149 B 3.3-43 Crystal River Unit 3 i
| |
| | |
| ESAS Instrumentation B 3.3.5 B 3.3 INSTRUMENTATION B 3.3.5 Engineered Safeguards Actuation System (ESAS) Instrumentation BASES BACKGROUND The ESAS initiates Engineered Safeguards (ES) Systems, based on the values of selected plant parameters, to protect core design and reactor coolant pressure boundary limits and to mitigate accidents.
| |
| ESAS actuates the following:
| |
| : a. High Pressure Injection (HPI);
| |
| : b. Low Pressure Injection (LPI);
| |
| : c. Reactor Building (RB) Isolation and Cooling;
| |
| : d. RB Spray; j
| |
| : e. Emergency Diesel Generator (EDG) Start; and
| |
| , f. Control complex normal recirculation. l ESAS also provides two signals to the Emergency Feedwater Initiation and Control (EFIC) System. One signal initiates emergency feedwater (EFW) when an actuation of HPI Channel A l and HPI Channel B is present. The other functions to trip i the motor driven emergency feedwater pump when an RCS Pressure-Low Low initiation coincident with a loss of
| |
| ; offsite power is present.
| |
| The ESAS operates in a distributed manner to initiate the appropriate systems. The ESAS does this by monitoring RCS pressure actuation parameters in each of three channels and RB pressure actuation in each of six channels (3 per actuation train). Once the setpoint for actuation is j reached, the signal is transmitted to automatic actuation logics, which perform the two-out-of-three logic for actuation of each end device. However, all automatic actuation logics receive signals from the same channels for each parameter.
| |
| Four parameters are used for actuation:
| |
| : a. Low Reactor Coolant System (RCS) Pressure; (continued)
| |
| Crystal River Unit 3 B 3.3-44 Revision No. 11
| |
| | |
| ESAS Instrumentation B 3.3.5 r
| |
| BASES
| |
| : b. Low Low RCS Pressure; BACKGROUND (continued) c. High RB Pressure; and
| |
| : d. High High RB Pressure.
| |
| This LC0 covers only the instrumentation channels that monitor these parameters. These channels include all intervening equipment from (including) the sensor, to (not LCO 3.3.6, " Engineered including) the actuation logic.
| |
| Safeguards Actuation System (ESAS) Manual Initiation," and LC0 3.3.7, " Engineered Safeguards Actuation System (ESAS)
| |
| Automatic Actuation Logic," provide requirements on the manual initiation and automatic actuation logic Functions.
| |
| The ESAS RCS Pressure Parameters consists of three analog The digital portion of the string instrumentation channels.
| |
| (from the output of the bistable on) is essentially sixThe ES channels. Each of instrumentation throughout the entire trip string.
| |
| channel provides input to logics that initiate equipment with a two-out-of-three logic in each train. Each protection channel includes bistable inputs from oneinstru Pressure and pressure switch inputs from three channels cf Automatic High RB Pressure and High-High RB Pressure. actuation logi in each train to actuate the individual Engineered Safeguards (ES) components needed to initiate each ES System Function. Figure 7-5 of the FSAR, (Ref. 1), illustrates how instrumentation channel trips combine to cause protection channel trips.
| |
| The RCS pressure sensors are common to both actuation trains. Separate RB pressure sensors are used for the high and high high pressure Functions in each train, and separate sensors are used for each train.
| |
| FSAR Table 7-3 identifies the measurement channels used for ES actuation and the Function actuated by each.
| |
| The ES equipment is divided between the two redundant The division of the equipment actuation trains A and B.
| |
| between the two actuation trains is based on the equipment redundancy and function and is. accomplished in such a manner that the failure of one of the actuation channels and the (continued) 8 3.3-45 Revision No. 11 Crystal River Unit 3
| |
| | |
| . . _ . _ _ . - . - . ~._ --
| |
| ESAS Instrumentation B 3.3.5 BASES BACKGROUND related safeguards equipment will not inhibit the overall ES (continued) Functions. Where a motor operated or a solenoid operated valve is driven by either of two matrices, one is from actuation train A and one from actuation train B. Redundant ES pumps are controlled from separate and independent actuation channels.
| |
| Enaineered Safety Feature Actuation System Bvoasses No provisions ne made for maintenance bypass of ESAS instrumentation channels. Operational bypasses are provided, as discussed below, to allow accident recovery actions to continue and, to allow plant cooldown without spurious ESAS actuation.
| |
| The ESAS RCS pressure instrumentation channels include permissive bistables that allow manual bypass when reactor pressure is below the point at which the low and low low pressure trips are required to be OPERABLE. Once permissive conditions are sensed,.the RCS pressure trips may be manually bypassed. Bypasses are automatically remr//ed when ,
| |
| bypass permissive conditions are no longer applicable. !
| |
| No more than two (of the three) High RB Pressure channels may be manually bypassed after an actuation. The manual bypass allows operators to take manual control of ES Functions after initiation to allow recovery actions.
| |
| Reactor Coolant System Pressure RCS pressure is monitored by three independent pressure transmitters located in the RB. These transmitters are separate from the transmitters that provide an input to the Reactor Protection System (RPS). Each of the pressure signals generated by these transmitters is monitored by four bistables to provide two trip signals, at 1500 psig and 500 psig, and two bypass permissive signals, at 1700 psig and 900 psig.
| |
| i (continued) .
| |
| Crystal River Unit 3 8 3.3-46 Revision No. 11
| |
| | |
| 1 ESAS Instrumentation B 3.3.5 l 1
| |
| BASES l
| |
| BACKGROUND Reactor Coolant System Pressure (continued)
| |
| The outputs of the three channels trip bistables, associated I with the low RCS pressure (1500 psig) actuate bistable trip auxiliary relays in two sets (actuation trains A and B) of identical and independent trains. The two HPI trains each use three logic channels arranged in two-out-of-three coincidence networks. The outputs of the three bistables associated with the Low Low RCS Pressure (500 psig) actuate bistable trip auxiliary relays in two sets (actuation trains A and B) of identical and independent trains. The two LPI trains each use three logic channels arranged in two-out-of-three coincidence networks for LPI Actuation. The outputs of the three Low Low RCS Pressure bistables also trip the automatic actuatico relays, via a LPI bistable trip auxiliary relay, in the corresponding HPI train as previously described.
| |
| Reactor Buildina Pressure ESAS RB pressure signal information is provided by 12 pressure switches. Six pressure switches are used for the High RB Pressure Parameter, and six pressure switches are used for the High-High RB Pressure Parameter.
| |
| The output contacts of six High RB Pressure switches are used in two sets of identical and independent actuation i trains. These two trains each use three logic channels. l The outputs of these channels are used in two-out-of-three l coincidence networks. The output contacts of the six RB pressure switches also trip, via a pressure switch trip auxiliary relay, the automatic actuation relays in the corresponding HPI and LPI trains as previously described.
| |
| The output contacts of six High High RB Pressure switches are used in two sets of identical and independent actuation trains. The outputs of the High High RB Pressure switches are used in two-out-of-three coincident networks for RB Spray Actuation. The two-out-of-three logic associated with each RB Spray train actuates spray pump operation when the High-High RB signal and the HPI signal are coincident in that train.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-47 Revision No. 11
| |
| | |
| ; ESAS Instrumentation B 3.3.5 p,.
| |
| BASES (continued) l APPLICABLE Accident analyses rely on automatic ESAS actuation for SAFETY ANALYSES protection of the core temperature and containment pressure 4
| |
| limits and for limiting off site dose levels following an ,
| |
| accident. These include LOCA, SLB, and feedwater line break ,
| |
| events that result in RCS inventory reduction or severe loss '
| |
| of RCS cooling.
| |
| The following ESAS Functions are assumed to operate to q mitigate design basis accidents.
| |
| Hiah Pressure iniection The ESAS actuation of HPI has been assumed for core cooling in the small break LOCA analysis and is credited in the SLB analysis for the purposes of adding boron and negative reactivity. HPI is also credited in the Steam Generator Tube Rupture (SGTR) accident analysis.
| |
| Low Pressure In.iection The ESAS actuation of LPI has been assumed for large break ,~
| |
| LOCAs. ?
| |
| Reactor Buildino Sorav. Reactor Buildina Coolino, and Reactor Buildina Isolation
| |
| 'ESAS actuation of the RB coclers and RB Spray is credited in RB analysis for LOCAs, both for RB performance and equipment ,
| |
| environmental qualification pressure and temperature envelope definition. Accident dose calculations credit RB Isolation and RB Spray.
| |
| Emeroency Diesel Ger.erator Start The ESAS initiated EDG Start has been assumed in the LOCA ,
| |
| analysis to ensure that emergency power is available j throughout the limiting LOCA scenarios.
| |
| The small and large break LOCA analyses assume a conservative 35 second delay time for the actuation of HPI and LPI in FSAR, Chapter 6, (Ref. 3). This delay time i.e small and large break LOCA analyses assume a conservative 35 second delay time for the actuation of HPI 4
| |
| (continued) E_
| |
| Crystal River Unit 3 B 3.3 48 Revision No. 11
| |
| | |
| ._ . . ._ _ . . _ _ _ _ .. _. __ __ ~-
| |
| ESAS instrumentation 8 3.3.5
| |
| ?
| |
| 4 i
| |
| BASES 1 APPLICABLE Emeraency Diesel Generator Start (continued)
| |
| ! SAFETY ANALYSES
| |
| : and LPI in FSAR, Chapter 6, (Ref 3). This delay time
| |
| ; includes allowances for EDG starting, EDG output breaker closure, EDG voltage recovery, EDG loading, Emergency Core Cooling Systems (ECCS) pump starts, and valve openings.
| |
| Similarly, RB Isolation and Cooling, and RB Spray have been analyzed with delays appropriate for the entire system
| |
| : analyzed. Values used in the analysis are 25 seconds for RB Cooling, 60 seconds for RB Isolation, and 90 seconds for RB
| |
| ! Spray.
| |
| ESAS instrumentation channels satisfy Criterion 3 of the NRC
| |
| - Policy Statement.
| |
| (i The LC0 requires the specified ESAS instrumentation'for each l
| |
| LC0 Parameter in Table 3.3.5-1 to be OPERABLE. Failure of any instrument renders the affected channel inoperable and i reduces the margin to meeting the single failure criteria l for the affected Functions.
| |
| l 1
| |
| Two channels of RCS Pressure ESAS instrumentation and two l channels of ESAS RB pressure instrumentation in each actuation train shall be OPERABLE to ensure that a single failure in one channel will not result in loss of the l ability to automatically actuate the required safety function.
| |
| The bases for the LCO on ESAS Parameters include the following. :
| |
| Reactor Coolant System Pressure Three channels each of RCS Pressure-Low and RCS Pressure-Low-Low are required to be OPERABLE. Each channel includes a sensor, trip bistable, bypass bistable, bypass relays, and bistable trip auxiliary relays. In addition, each RCS Pressure-Low channel also includes time delay auxiliary relays. The analog portion of each pressure channel is common to both trains of both RCS Pressure Parameters. Therefore, failure of one analog channel renders one channel of the low pressure and low low pressure Functions in each train inoperable. The bistable portions of the channels are Function and train specific.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-49 Revision No. 11
| |
| | |
| ESAS Instrumentation B 3.3.5 c'
| |
| BASES l LC0 Reactor Coolant System Pressur.g (continued)
| |
| Therefore, a bistable failure renders only one Function in one train inoperable. Failure of a bypass bistable or bypass circuitry, such that a trip channel cannot be bypassed, does not render the channel inoperable. Bistable trip auxiliary relays and auxiliary time delay relays are train specific but may be shared among Parameters.
| |
| Therefore, bistable trip auxiliary or auxiliary time delay relay failure has the potential to render all affected functions in one train inoperable.
| |
| : 1. Reactor Coolant System Pressure-Low Setooint
| |
| - The RCS Pressure-Low Setpoint is based on HPI 1 actuation for small break LOCAs. The setpoint ensures i that the HPI wili ce actuated at a pressure greater than or equal to tha value assumed in accident analyses plus the instrument uncertainties.
| |
| : 2. Reactor Coolant System Pressure-Low Low Setooint i The RCS Pressure-Low Low Setpoint LPI actuation occurs (
| |
| in sufficient time to ensure LPI flow prior to the emptying of the core flood tanks during a large break i LOCA. The Allowable Value of 2: 500 psig ensures sufficient overlap of the core flood tank flow and the LPI flow to keep the reactor vessel downcomer full during a large break LOCA.
| |
| Reactor Buildina Pressure Two channels each of RB Pressure-High and RB Pressure-High l High are required to be OPERABLE in each train. Each channel includes a pressure switch, bypass relays, and pressure switch trip auxiliary relays. An inoperable prdssure switch renders only one channel in one train inoperable. Pressure switch trip auxiliary relays are train specific but may be shared among Parameters. Therefore, trip relay failure has the potential to render all affected Functions in one train inoperable.
| |
| (continued)
| |
| Crystal River Unit 3' B 3.3-50 Revision No. 11
| |
| | |
| 1 a
| |
| s ESAS Instrumentation l B 3.3.5 BASES l d
| |
| LCO 1. Reactor Buildina pressure-Hiah Setooint
| |
| ;. (continued)
| |
| The RB Pressure-High Setpoint Allowable Value s 4 psig was selected to be low enough to detect a rise in
| |
| ; RB Pressure that would occur due to a small break !
| |
| ; LOCA, thus ensuring that the RB high pressure actuation of the safety systems will occur for a wide ,
| |
| spectrum of break sizes. The trip setpoint also causes the RB coolers to shift to low speed (performed as part of the HPI logic) to prevent damage to the cooler fans due to the increase in the density of the air steam mixture present in the containment following '
| |
| a LOCA,.
| |
| .2. Reactor Buildina Pressure-Hiah Hiah Setooint The RB Pressure-High High Setpoint Allowable Value s 30 psig was chosen to be high enough ta avoid ,
| |
| actuation during an SLB, but also low enough to ensure :
| |
| a timely actuation auring a large break LOCA.
| |
| APPLICABILITY The ESAS instrumentation for each Parameter is required to be OPERABLE during the following MODES and specified conditions. ,
| |
| : 1. Reactor Coolant Systen,9 nsure-Low Setooint The RCS Pressure-Low Setpoint actuation Parameter ,
| |
| shall be OPERABLE during operation above 1700 psig. i This ensures the capability to automatically actuate safety systems and components during conditions indicative of a LOCA or SLB. Below 1700 psig, the low RCS Pressure :tuation Parameter can be bypassed to avoid actuation during normal cooldown when safety system actuations are not required.
| |
| i The allowance for the bypass is consistent with the l plant transition to a lower energy state, providing greater margins to core and containment limits. The response to any event, given that the reactor is already shut down, will be less severe and allows sufficient time for operator action to provide manual safety system actuations. This is even more appropriate during plant heatup from an outage when the RCS energy content is low.
| |
| l (continued) ;
| |
| Crystal River Unit 3 8 3.3-51 Revision No. 11
| |
| | |
| ESAS Instrumentation B 3.3.5 BASES Y APPLICABILITY 1. Reactor Coolant System Pressure--Low Setooint
| |
| , (continued)
| |
| To ensure the RCS Pressure--Low trip is not bypassed when required to be OPERABLE by the safety analysis,
| |
| )
| |
| each channel's bypass removal bistable must be set with a setpoint of 5; 1700 psig. The bypass removal does not need to function for accidents initiated from RCS Pressures below the bypass removal setpoint.
| |
| : 2. Reactor Coolant System Pressure--Low low Setooint 2
| |
| The RCS Pressure--Low Low Setpoint actuation Parameter
| |
| ; shall be OPERABLE during operation above 900 psig.
| |
| This ensures the capability to automatically actuate safety systems and components during conditions indicative of a LOCA. Below 900 psig, the low low RCS Pressure actuation Parameter can be bypassed to avoid actuation during normal plant cooldown.
| |
| The allowance for the bypass is consistent with plant ,,-
| |
| transition to a lower energy state, providing greater 4 margins to core and containment limits. The response to any event, given that the reactor is already tripped, will be less severe and allows sufficient time for operator action to provide manual safety system actuations. This is even more appropriate during heatup from an outage when the RCS energy content is low.
| |
| To ensure the RCS Pressure--Low Low trip is not bypassed when assumed OPERABLE by the safety analysis, each channel's bypass removal bistable must be set with a setpoint of s; 900 psig. The bypass removal does not need to function for accidents initiated by RCS Pressure below the bypass removal setpoint.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-52 Revision No. 11 t
| |
| | |
| ESAS Instrumentation 8 3.3.5 BASE 3 i l
| |
| 3,4. Reactor Buildina Pressure--Hich and Reactor Buildina l APPLICABILITY (continued) Pressure--Hiah Hiah Setooints The RB Pressure--High and RB Pressure--High High actuation Functions of ESAS shall be OPERABLE in MODES 1, 2, and 3. In MODES 4, 5 and 6, there is insufficient energy in the primary and secondary systems to raise containment pressure to either the RB Pressure--High or RB Pressure--High High Setpoints in the event of a line break. Furthermore, there is adequate time for the operator to evaluate plant conditions and manually respond.
| |
| ACTIONS Required Actions A and B apply to all ESAS instrumentation Parameters listed in Table 3.3.5-1.
| |
| A Note has been added to the ACTIONS indicating separate Condition entry is allowed for each Parameter.
| |
| A_d Condition A applies when one instrumentation channel in one or more RCS Pressure Parameters becomes inoperable. If one ESAS channel is inoperable, placing it in a tripped condition leaves the system in a one-out-of-two condition for actuation. Thus, if another channel were to fail, the ESAS instrumentation could still perform its actuation
| |
| ' functions. For RCS Pressure-Low, this action is completed when all of the affected bistable trip auxiliary relays and time delay auxiliary relays are tripped. For RCS Pressure-Low tow, this action is completed when all of the affected bistable trip auxiliary relays are tripped. This is normally accomplished by tripping the affected bistable.
| |
| The 1 hour Completion Time is based on engineering judgment and is sufficient time to perform the Required Action.
| |
| l (continued)
| |
| Crystal River Unit 3 8 3.3-53 Revision No. 11
| |
| | |
| i ESAS Instrumentation B 3.3.5 m :
| |
| BASES ( '
| |
| ACTIONS Ed (continued) ,
| |
| Condition B applies when one required instrumentation i channel in one or more RB Pressure Parameters becomes inoperable. !
| |
| If one required channel is inoperable, placing i it in a tripped Condition leaves the affected actuation train in one-out-of-one condition for actuation and the other actuation channel in a two-out-of-two condition !
| |
| (making the worst case-assumption the third channel in each :
| |
| actuation train is not OPERABLE). In this condition, if j another RB Pressure ESAS channel were to fail, the ESAS i instrumentation could stili perform its actuation function.
| |
| For RB Pressure Parameters, all affected pressure switch I trip auxiliary relays must be tripped to comply with this i Required Action. This is normally accomplished by tripping the affected pressure switch test switch. !
| |
| The 72 hour Completion Time is based on engineering judgment t.nd is sufficient time to perform the Required-Action.
| |
| C.1. C.2. C.3. and C.4 .
| |
| l.
| |
| If Required Actions A.1 or B.1 cannot be met within the !
| |
| associated Completion. Time, the plant must be placed in a j MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within i 6 hours and, for the RCS Pressure-Low Parameter, to
| |
| < 1700 psig, for the RCS Pressure-Low Low Parameter, to ;
| |
| < 900 psig, and for the RB Pressure High Parameter and High 4 High Parameter, to' MODE 4 within 12 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 plant systems.
| |
| SURVEILLANCE All ESAS Parameter instrumentation listed in Table 3.3.5-1 REQUIREMENTS are subject to CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, CHANNEL CALIBRATION, and response time testing.
| |
| (continued)
| |
| . Crystal River Unit 3 8 3.3-54 Revision No.-11
| |
| | |
| s-ESAS Instrumentation B 3.3.5 l
| |
| l .
| |
| BASES I SURVEILLANCE SR 3.3.5.1 REQUIREMENTS (continued) Performance of the CHANNEL CHECK every 12 hours ensures 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. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.
| |
| Significant deviations between the two instrument channels -
| |
| could be an indication of excessive instrument drift in one of the channels or of something even more serious.
| |
| ! The 12 hour Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK 4
| |
| supplements less formal, but more frequent, checks of channel OPERABILITY during normal operational use of the displays associated with the LC0's required channels.
| |
| d Acceptance criteria are determined by the plant staff, and i are presented in the Surveillance Procedures. The criteria
| |
| ; may consider, but is not limited to channel instrument i- uncertainties, including isolation, indication, and readability.
| |
| 4 1 SR 3.3.5.2 i
| |
| A CHAhNEL FUNCTIONAL TEST is performed on each required ESAS
| |
| : channel to ensure the entire channel will perform the intended functions.
| |
| 1 The Frequency of 31 days is based on plant operating experience, with regard to channel 0PERABILITY and drift, which demonstrates that failure of more than one channel of
| |
| ! a given function in any 31 day interval is unlikely.
| |
| A Note has been added to indicate entry into the Required Actions of this Specification may be deferred for up to 8 hours for a channel inoperable for Surveillance testing i
| |
| provided the remaining two ESAS channels are capable of performing the associated ES Function. This allowance
| |
| ! considers the average time required to perform the SR and is 1
| |
| based on the inability to perform the Surveillance in the time permitted by the Required Actions or the undesirability 3 of performing those ACTIONS.
| |
| 4 (continued)
| |
| Crystal River Unit 3 B 3.3-55 Revision No. 11
| |
| | |
| CSAS Instrumentation B 3.3.5 s ..
| |
| * k BASES l
| |
| SURVEILLANCE SR 3.3.5.3 REQUIREMENTS ,
| |
| (continued) CHANNEL CALIBRATION is a complete check of the instrument l channel, including the sensor. The test verifies that the channel responds to a measured parameter within the I necessary range and accuracy. CHANNEL CALIBRATION leaves .
| |
| the channel adjusted to account for instrument drift to !
| |
| ensure that the instrument channel remains operational between successive tests.
| |
| 1 The 24 month Frequency is based on the results of a review 1 of instrument drift data conducted in accordance with NRC Generic Letter 91-04.
| |
| SR 3.3.5.4 SR 3.3.5.4 ensures that the ESAS actuation channel response times are less than or equal to the maximum times assumed in the accident analysis. The response time values are the maximum values assumed in the safety analyses. Individual component response times are not modeled in the analyses. .
| |
| Response time testing acceptance criteria are on a Function 4 basis and are included in Reference 1. The analyses model the overall or total elapsed time from the point at which the parameter exceeds the actuation setpoint value at the sensor to the point at which the end device is actuated.
| |
| Thus, this SR encompasses the automatic actuation logic components addressed under LCO 3.3.7 and the operation of 1 the ES end devices.
| |
| Response time tests are conducted on an 24 month STAGGERED 1 TEST BASIS. This results in response time verification of i all instrument channels every 72 months. The Frequency is i based on plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation but not channel failure are infrequent occurrences.
| |
| REFERENCES 1. FSAR, Chapter 7.
| |
| : 2. FSAR, Chapter 14.
| |
| : 3. FSAR, Chapter 6.
| |
| Crystal River Unit 3 8 3.3-56 Revision No. !!
| |
| | |
| . . . .- . - -. . - . - . - -- . - . . ~ - - . - - . -
| |
| I ESAS Manual Initiation B 3.3.6
| |
| (
| |
| B'3.3 INSTRUMENTATION i B 3.3.6 Engineered Safeguards Actuation System (ESAS) Manual Initiation i
| |
| i e BASES g i
| |
| 1
| |
| ; BACKGROUND The ESAS manual initiation capability allows the operator to ,
| |
| ; actuate ESAS Functions from the main control room in the
| |
| ! absence of any other initiation condition. Functions '
| |
| t capable of being manually actuated include High Pressure 4 Injection, Low Pressure Injection, and Reactor Building (RB)
| |
| * Isolation and Cooling.
| |
| This LCO covers only the system level manual initiation of '
| |
| these Functions. LC0 3.3.5, " Engineered Safeguards Actuation System (ESAS) Instrumentation," and LCO 3.3.7,
| |
| " Engineered Safeguards Actuation System (ESAS) Automatic Actuation Logic," provide requirements on the portions of- ;
| |
| the ESAS that automatically initiate the Functions described j
| |
| earlier.
| |
| . A manual trip push button is provided on the ES panel of the
| |
| + main control board for each Function for each' actuation train. Operation of the push button energizes relays whose ,
| |
| contacts perform a logical "0R" function with the matrices of the automatic actuation logic, except for the matrices -
| |
| which are part of the ES buses loading sequence. Manual actuation of the ES buses loading sequence .is made by de-energizing the block timers and the time delay auxiliary rel ays . The power supply for the manual . trip relays .is taken from the station batteries. Different batteries are used for the two trains.
| |
| The ESAS manual initiation channel is defined as the instrumentation between the console switch and the automatic actuation logic, (not to include the AAL) which actuates the end devices. Other means of manual initiation, such as controls for individual ES devices, may be available in the control room and other plant locations. These alternative means are not required by this LCO, nor are they credited to fulfill the requirements of this LCO.
| |
| The most notable example of a manual initiation not addressed by the Technical Specification is Reactor Building Spray. The manual actuation of the Reactor Building Spray was designed to be done in two steps. The first step is the l
| |
| )
| |
| \ j (continued)
| |
| Crystal River Unit 3 B 3.3-57 Revision No. 7 l
| |
| J l
| |
| C - , - I
| |
| | |
| ESAS Manual Initiation B 3.3.6 1
| |
| BASES ,,
| |
| BACKGROUND manual actuation of the Reactor Building Isolation and (continued) Cooling to open the valves and the second step is the manual !
| |
| actuation of the Reactor Building Spray pumps. Since -l Reactor Building Spray pumps have individual control switches on the centrol board, separate ESAS manual 1 actuation switches were not provided. This logic scheme l relies on the individual Reactor Building Spray pump control switches to meet the requirements of section 4.17 of proposed IEEE-279 dated August 30, 1968 (FSAR section
| |
| ~7.1.1).
| |
| 1 I
| |
| l APPLICABLE The ESAS manual initiation Function is a backup to automati.c l SAFETY ANALYSES initiation and allows the operator to initiate 55 Systems operation whenever plant conditions dictate. The manual initiation Function is not assumed or credited in any accident or safety analysis. 1 The ESAS manual initiation instrumentation functions are i included in Technical Specifications even though they do not i strictly satisfy any Criterion of the NRC Policy Statement. I I
| |
| l
| |
| .LC0 Two manual initiation channels of each ESAS Function are i required to be OPERABLE whenever conditions exist that could require ES protection of the reactor or RB. Two OPERABLE channels ensure that no single failure will prevent system ,
| |
| level manual initiation of at least one train of any ESAS '
| |
| Function. The ESAS manual initiation Function allows the ,
| |
| operator to initiate protective action prior to automatic '
| |
| initiation or in the event the automatic initiation does not occur. l APPLICABILITY The ESAS manual initiation Functions shall be OPERABLE in MODES 1, 2, and 3, and in MODE 4 when the associated Engineered Safeguard equipment is required to be OPERABLE.
| |
| The manual initiation channels are required consistent with the requirements for ES Functions to provide protection in these MODES. In MODES 5 and 6, accidents are slow to develop and would be mitigated by manual operation of individual components. Adequate time is available to evaluate plant conditions and to respond by manually operating the ES components, if required.
| |
| (continued) _
| |
| Crystal River Unit 3 B 3.3-58 Revision No. 7
| |
| | |
| _ __ __. _ __. ._ __ _ _ _ _ ~ . . _ . _
| |
| ESAS Manual Initiation B 3.3.6
| |
| ! BASES (continued)
| |
| ACTIONS A Nate has been added to the ACTIONS indicating separate Condition entry is allowed for each ESAS manual initiation Function.
| |
| .A.1 With one manual initiation channel of one or more ESAS Functions inoperable, the channel must be restored to OPERABLE status within 72 hours. The Completion Time of 72 hours is based on plant operating experience and administrative controls, which provide alternativa means of ESAS Function initiation via individual component controls.
| |
| The 72 hour Completion Time is also consistent with the allowed outage time for a loss of redundancy condition for the safety systems actuated by ESAS.
| |
| B.1 and B.2 If the manual initiation channel cannot be restored to OPERABLE status within 72 hours, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and in MODE 5 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.
| |
| SURVEILLANCE SR 3.3.6.1 REQUIREMENTS SR 3.3.6.1 is a CHANNEL FUNCTIONAL TEST of the ESAS manual initiation. The SR verifies manual initiating circuitry is OPERABLE but does not actuate the end device (i.e., pump, valves, etc. ) . Proper operation of the Function is primarily monitored by ES logic matrix test 117 ts (located on the ES Actuation relay cabinets). The 24 month Frequency I is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance 1s performed with the reactor at power. This Frequency has been extended to 24 montns based on operating experience, I which shows these components usually pass the Surveillance when performed on the 18 month Frequency.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-59 Revision No. 7 j l
| |
| s ;
| |
| | |
| ESAS Manual lnitiation B 3.3.6 BASES (continued) g..
| |
| \r . ..
| |
| REFERENCES None.
| |
| (
| |
| (,_ .
| |
| Crystal River. Unit 3 8 3.3-60 Revision No. 7
| |
| | |
| ESAS Automatic Actuation Logic B 3.3.7 BASES ACTIONS A.1 and A.2 (continued)
| |
| With one or more automatic actuation logic matrices inoperable, the associated component (s) should be placed in the ES configuration. This manual Action essentially fulfills the safety function of the automatic actuation logic. In some circumstances, placing the component in its ES configuration would impose an undue operational restriction. In these cases, Required Action A.2 allows for the component status be left as-is, and the supported system component declared inoperable. Conditions which would potentially preclude placing of a component in its ES configuration include, but are not limited to, violation of system separation, activation of fluid systems that could lead to thermal shock, or isolation of fluid systems that are normally functioning. The I hour Completion Time is based on operating experience and reflects the urgency associated with the inoperability of a safety system component.
| |
| SURVEILLANCE SR 3.3.7.1 REQUIREMENTS SR 3.3.7.1 is the performance of a CHANNEL FUNCTIONAL TEST on a 31 day STAGGERED TEST BASIS. The CHANNEL FUNCTIONAL TEST of the Automatic Actuation Logic need only demonstrate one combination of the three two-out-of-three logic combinations that are required to be OPERABLE. A different combination is tested at each test interval, such that all three combinations will be confirmed to be OPERABLE by the time the third successive test is completed. The Frequency is based an operating experience that demonstrates the low likeli; R of more than one channel failing within the same 31 day ;erval.
| |
| (continued) .;
| |
| Crystal River Unit 3 8 3.3-63 Amendment No. 155
| |
| | |
| .. - . . . .. ~ . - . .- . . . - _ - . . -. _ . - . - . . - - - _ . - . _ . .
| |
| ESAS Automatic Actuation Logic l B 3.3.7 !
| |
| l
| |
| (:: ,'._\
| |
| BASES (continued) . . .
| |
| i REFERENCES 1. 10 CFR 50.46.
| |
| \
| |
| : 2. FSAR, Chapter 14. 1 i
| |
| d l
| |
| i i
| |
| 1
| |
| (, i I
| |
| l 1
| |
| ,a Crystal River Unit 3 B 3.3-64 Amendment No. 149
| |
| | |
| Source Range Neutron Flux B 3.3.9 h
| |
| ! B 3.3 INSTRUMENTATION 1
| |
| B 3.3.9 Source Range Neutron Flux 1
| |
| BASES
| |
| ! BACKGROUND The source range neutron flux channels provide the operator
| |
| ' with an indication of the approach to criticality at lower neutron power levels than can be monitored by the intermediate range neutron flux instrumentation. These channels also provide the operator indication of changes in i.
| |
| reactivity that may occur during other shutdown operations.
| |
| I The normally relied upon source range instrumentat ,n (NI-1 l and -2) consist of two redundant count rate channel,
| |
| ; originating in two high sensitivity proportional counters.
| |
| : The two detectors are externally located on opposite sides of the core 180' apart. These channels are used over a neutron count rate range of 0.1 cps to IE6 cps and are displayed on the main control board (MCB) in terms of log count rate. The channels also measure the rate of change of the neutron flux level, which is displayed on the MCB in terms of startup rate from -0.5 decades to +5 decades per minute. An interlock provides a control rod withdraw
| |
| " inhibit" on a high startup rate of +2 decades per minute in either channel. l l
| |
| The proportional counters of the source range channels are j BF3 chambers. High voltage will be turned off automatically j when the flux level on a start-up (count rate increasing) is ;
| |
| above IE-9 amp as seen by both intermediate range channels, I or 10% RTP in NI-5 or -6 and NI-7 or -8 power range ;
| |
| channels. Conversely, the high voltage is turned on automatically when the flux level returns to within 1 approximately one decade of the detectors' maximum useful range. l Although not normally relied upon to perform the source !
| |
| range neutron flux level monitoring function, the post-accident monitoring instrumentation wide range neutron flux !
| |
| (NI-14, -15) have been shown to be functionally equivalent to NI-1 and NI-2 and may be used to comply with this LCO.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-73 Revision No. 7
| |
| | |
| Source Range Neutron Flux B 3.3.9 BASES (continued) -"s .
| |
| l l
| |
| APPLICABLE The source range neutron flux channels are necessary to SAFETY ANALYSES monitor core reactivity changes. They are also the primary means for detecting and triggering operator actions to respond to reactivity transients initiated from conditions ;
| |
| i in which the Reactor Protection System (RPS) is not required to be OPERABLE. However, the monitors are not assumed as part of any accident analysis sequence, j LC0 Two source range neutron flux channels are required to be i OPERABLE during MODE 2 with each intermediate range channel l s SE-10 amps or NI-5 or NI-6, and NI-7 or NI-8 s 5% RTP; and '
| |
| MODES 3, 4 and 5 since they are the primary indication of core neutron power at low power levels.
| |
| i Above the neutron power level specified for MODE 2, the l source range instrumentation is not the primary neutron i power level indication and the high voltage to the detector l has been removed. The setpoints are based upon the power j levels where the instrumentation is re-energized on l decreasing flux levels. l 1
| |
| , l APPLICABILITY Two source range neutron flux channels are required in MODES 2, 3, 4 and 5. In MODE 2, OPERABILITY of the instrumentation ensures redundant indication during an approach to criticality. The intermediate range and power range instrumentation provide sufficient neutron flux level indication with the reactor critical; therefore, source i range instrumentation is not required in MODE 1 (the '
| |
| instrumentation is de-energized and cannot function anyway).
| |
| In MODES 3, 4, and 5, source range neutron flux instrumentation provide the operator with a means of l monitoring changes in CDM and provides an indication of reactivity changes.
| |
| The requirements for source range neutron flux instrumentation during MODE 6 are addressed in LC0 3.9.2,
| |
| " Nuclear Instrumentation."
| |
| (continued) _
| |
| Crystal River Unit 3 B 3.3-74 Revision No. 7
| |
| | |
| Source Range Neutron Flux B 3.3.9 BASES (continued)
| |
| ACTIONS A.1 With one channel of the source range neutron flux indication inoperable, any action to increase reactor power must be suspended until the channel is restored to OPERABLE status.
| |
| This Action restricts THERMAL POWER increases in a range of operation where the source range instrumentation are the primary means of neutron power level indication.
| |
| Furthermore, it ensures that power remains below the point where the intermediate range channels come en-scale until both source range channels are available to support the ,
| |
| overlap verification required by SR 3.3.9.3. This ensures a '
| |
| transition from one monitoring instrument to another of different range with the reactivity conditions on both sides of the core known.
| |
| B.l. B.2. B.3 and B.4 With both source range neutron flux channels inoperable, j action is required to preclude increases in neutron count l rate requiring source range monitoring capability. This is I accomplished by immediately suspending positive reactivity additions and initiating action to insert all CONTROL RODS, and opening the CONTROL R0D drive trip breakers within 1 hour. Periodic SOM verification (of 2: 1% Ak/k) is then required to provide a means for detecting any slow ,
| |
| reactivity changes that could be caused by mechanisms other I than CONTROL R00 withdrawal or positive reactivity insertions. Since the source range instrumentation provides the primary indication of power in this plant operating condition, the verification of SDM must continue every 12 hours until at least one channel of source range instrumentation is returned to OPERABLE status. The 1 hour Completion Time for Required Action B.3 and Required Action B.4 are based upon providing sufficient time to accomplish the actions. The 12 hour Frequency for performing the SDM verification is considered adequate to detect any reactivity changes which do occur before SDM limits are approached.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-75 Revision No. 7
| |
| | |
| Source Range Neutron Flux B 3.3.9 BASES (continued) ,.,
| |
| SURVEILLANCE SR 3.3.9.1 REQUIREMENTS Performance of the CHANNEL CHECK once every 12 hours ensures that a gross failure of instrumentation has not occurred.
| |
| The CHANNEL CHECK is a comparison of the parameter indicated on one channel to the other channel. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. .
| |
| Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious.
| |
| Acceptance criteria are determined by the plant staff and presented in the Surveillance Procedure, based on a combination of the channel instrument uncertainties.
| |
| The Frequency, about once every shift, is based on operating experience. When operating in Required Action A.1, CHANNEL CHECK is still required for the OPERABLE source range .
| |
| instrument. However, in this Condition, a redundant source range may not be available for comparison. In this case, CHANNEL CHECK may still be performed via comparison with other on-scale neutron flux level initiation, if available, and verification that the OPERABLE source range channel is energized and indicating a value consistent with current .,
| |
| plant status.
| |
| SR 3.3.9.2 CHANNEL CALIBRATION is a complete check and readjustment of the channels from the greamplifier input to the panel meters. The calibration verifies the channel responds to measured parameters within the necessary range and accuracy and leaves the channel adjusted to account for instrument drift. This ensures that the instrument channel remains operational between successive tests.
| |
| The SR is modified by a Note excluding neutron detectors from CHANNEL CALIERATION. It is not necessary to test the detectors because generating a meaningful test signal is difficult. The detectors are of simple construction, and (continued)
| |
| Crystal River Unit 3 B 3.3-76 Revision No. 7
| |
| | |
| l Source Range Neutron Flux j B 3.3.9 BASES
| |
| . SURVEILLANCE SR 3.3.9.2 (continued)
| |
| REQUIREMENTS
| |
| ] any failures in the detectors will be apparent as change'in
| |
| ; channel output. The 24 month Frequency is based on the
| |
| : . results of a review of instrument drift data conducted in
| |
| ] accordance with NRC Generic letter 91-04.
| |
| SR 3.3.9.3 SR 3.3.9.3 is the verification of one decade of overlap between source and intermediate range neutron flux instrumentation. The SR is required to be performed prior to source range count rate exceeding 10' cps if it has not been performed within 7 days prior to . actor startup.
| |
| Failure to verify one decade of overlap on one or more source range channels requires the plant to be maintained in subcritical condition until the verification can be made.
| |
| This ensures a continuous source of neutron power indication during the approach to criticality. The verification may be omitted if performed within the previous 7 days. The 7 day portion of the Frequency is based on operating experience, wnL!'. shows that source range and intermediate range instrument overlap does not change appreciably over this time interval.
| |
| REFERENCES None.
| |
| Cry.stal River Unit 3 B 3.3-77 Revision No. 7 l l
| |
| | |
| Intermediate Range Neutron Flux B 3.3.10 8 3.3 INSTRUMENTATION ,,
| |
| B 3.3.10 Intermediate Range Neutron Flux )
| |
| ?
| |
| l BASES BACKGROUND The intermediate range neutron flux channels provide the I operator with an indication of reactor power at power levels between the source range and power range instrumentation.
| |
| The intermediate range instrumentation has two log N channels which monitor neutron power levels by means of electrically identical gamma compensated ion chambers (CIC). The CIC are electrically adjustable with separate adjustable high voltage power supply and an adjustable compensating voltage supply. Each channel provides eight decades of flux level information in terms of the log of ion i chamber current from 1E-11 amp to IE-3 amp. The channels also measure the rate of change of the neutron flux level, i which is displayed for the operator in terms of startup rate l from -0.5 decades to +5 decades per minute. A startup rate ,
| |
| of +3 decades per minute in either channel will initiate a CONTROL R0D withdrawal inhibit.
| |
| APPLICABLE Intermediate range neutron flux channels are necessary to SAFETY ANALYSES monitor core reactivity changes during a reactor startup.
| |
| As such, they are the primary indication to trigger operator :
| |
| actions in the event of reactivity transients starting from low powe'r conditions. However, the monitors are not assumed as part of any accident analysis sequence.
| |
| l l
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-78 Revision No. 7 !
| |
| l I
| |
| j i
| |
| | |
| intermediate Range Neutron Flux I B 3.3.10 l l
| |
| l BASES (continued)
| |
| LCO Two intermediate range neutron flux instrumentation channels shall be OPERABLE to provide the operator with redundant ;
| |
| neutron flux indication. These enable operators to monitor l and control the increase in power and to detect neutron flux transients prior to the power range instrumentation coming on scale. Violation of this LCO would limit the ability to "see" reactivity conditions throughout the core and could prevent the operator from detecting and controlling neutron
| |
| . flux transients that could result in reactor trip during power escalation.
| |
| APPLICABILITY The intermediate range neutron flux channels shall be OPERABLE in MODE 2 and in MODES 3,.4 and 5 when any CONTROL R00 drive (CRD) trip breaker is in the closed position and the CRD Control System (CROCS) is capable of rod withdrawal.
| |
| The intermediate range instrumentation is designed to detect l power changes during initial criticality and power escalation when the power range and source range instrumentation cannot provide indication. Since an approach to criticality could exist in all of these MODES, the intermediate range instrumentation must be OPERABLE.
| |
| l ACTIONS A_d With one intermediate range channel inoperable, the plant is exposed to the potential for a single failure to disable all neutron monitoring instrumentation. To avoid this, the inoperable channel must be repaired prior to increasing THERMAL POWER > SY. RTP. This limits power increases in a range where the operators rely on the instrumentation for power level indication.
| |
| The Completion Time is based on engineering judgment.
| |
| 8.1 and 8.2 With two intermediate range neutron flux channels inoperable, the operators must place the reactor in the next lowest condition for which the intermediate range (continued)
| |
| Crystal River Unit 3 8 3.3-79 Revision No. 7
| |
| | |
| Intermediate Range Neutron Flux B 3.3.10 BASES
| |
| (
| |
| ACTIONS B.1 and B.2 (continued) instrumentation is not required. This involves immediately suspending operations involving positive reactivity changes and, within I hour, placing the reactor in the tripped condition with the CRD trip breakers open. The Completion Times are based on operating experience and allow sufficient time to manually insert the CONTROL RODS prior to opening the CRD breakers.
| |
| SURVEILLANCE SR 3.3.10.1 REQUIREMENTS The CHANNEL CHECK is a comparison of the parameter indicated on one channel to the other channel. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.
| |
| Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even mere serious.
| |
| When operating in Required Action A.1, CHANNEL CHECK is i still required for the OPERABLE intermediate range instrument. However, in this condition, a redundant intermediate range may not be available for comparison. In this case, CHANNEL CHECK may still be performed via comparison with other on-scale neutron flux level indication, if available, and verification that the OPERABLE intermediate range channel is energized and indicates a ,
| |
| value consistent with current plant status.
| |
| SR 3.3.10.2 For intermediate range neutron flux channels, CHANNEL CALIBRATION is a complete check and readjustment of the channels, from the preamplifier input to the panel meters.
| |
| The calibration verifies the channel responds to a measured parameter within the necessary range and accuracy and leaves the channel adjusted to account for instrument drift. This ensures that the instrument channel remains operational between successive tests.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-80 Revision No. 7
| |
| | |
| - . . . . . . . . - - . . . . - . . - . _ - . - ~ - - _ - . - - - . . . . _ . . - - . ,. -
| |
| 4 Intermediate Range Neutron Flux i B 3.3.10
| |
| * l l BASES
| |
| , SURVEILLANCE SR 3.3.10.2 (continued)
| |
| REQUIREMENTS The SR is modified by a Note excluding neutron detectors ;
| |
| ! from CHANNEL CALIBRATION. It is not necessary to test the detectors because generating a meaningful test signal is difficult. In addition, the detectors are of simple 2
| |
| construction, and any failures in the detectors will be apparent as a change in channel output. The 24 month Frequency is based on the results of a review of instrument
| |
| . drift data conducted in accordance with NRC Generic Letter J
| |
| 91-04.
| |
| i 1
| |
| ; SR 3.3.10.3
| |
| ! .SR 3.3.10.3 is the verification of one decade of overlap I between intermediate and power range neutron flux l instrumentation. The SR is required to be performed prior to intermediate range indication exceeding IE-5 amp if it has not been performed within 7 days prior to reactor l startup. Failure to verify one decade of overlap on one or
| |
| ! more channels requires the plant to remain in a condition
| |
| ! where the intermediate range channels provide adequate indication until the verification can be made. This ensures the power range nuclear instrumentation is functioning
| |
| ; properly prior to the transition to this range of
| |
| : indication.
| |
| 1 The test may be omitted if performed within the previous 7 days. The 7 day portion of the Frequency is based on operating experience, which shows that intermediate range
| |
| ; instrument overlap does not change appreciably over this time interval. ]
| |
| REFERENCES None.
| |
| 3 i
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| ? Crystal River Unit 3 B 3.3-81 Revision No. 7 i
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| EFIC Instrumentation B 3.3.11 B 3.3 INSTRUMENTATION , , _
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| f B 3.3.11 Emergency Feedwater Initiation and Control (EFIC) Instrumentation '
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| BASES BACKGROUND The EFIC System instrumentation is designed to provide safety grade means of controlling the secondary system as a l heat sink for core decay heat removal. To ensure the j secondary system remains a heat sink, EFIC initiates )
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| emergency feedwater (EFW) when the primary source of -
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| feedwater is lost. The system also isolates functional components following a high energy line break within the j secondary system. These actions ensure that a source of cooling water is available to a once through steam generator 1 (OTSG) that has a controlled steam pressure, thereby fixing '
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| the heat sink temperature at the saturation temperature of the secondary system. The EFIC Functions that are supported by the instrumentation and the parameters that are needed for each of these Functions are described next.
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| EFIC instrumentation consists of devices and circuitry to generate the following signals when monitored parameters reach pre-set levels.
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| : a. EFW Initiation;
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| : b. EFW Vector Valve Control;
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| : c. Main Steam Line Isolation; and
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| : d. Main Feedwater (MFW) Isolation. .
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| EFW is initiated to restore a source of cooling water to the secondary system when conditions indicate that the normal source of feedwater is insufficient to continue heat removal. The two indications used for ensuring EFW in this condition are the loss of both MFW pumps and a low level in the OTSG. EFW.is also initiated at the same time EFIC performs the MFW isolation function. This is done by initiating EFW when OTSG outlet pressure reaches the low OTSG pressure setpoint for isolation of main steam and MFW, and EFW vector valve control. EFW is initiated when the Reactor Coolant System experiences a total loss of forced (continued) l Crystal River Unit 3 8 3.3-82 Revision No. 7 l l
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| l
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| EFlc Instrumentation B 3.3.11 BASES BACKGROUND circulation. This initiation, utilizing the RPS signal for (continued) reactor coolant pump (RCP) status, ensures EFW is available to automatically raise OTSG levels to natural circulation cooling. Finally, EFIC initiates EFW when an actuation is received on HPI Channel A and B. This ensures EFW is
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| ; available under the worst-case, small break loss of coolant accident (LOCA) conditions when high OTSG water levels are necessary for primary to secondary heat transfer. If adequate subcooling margin is lost, the' operator must manually select the 95% setpoint since EFIC will not automatically raise levels to this point.
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| EFIC also isolates main steam and MFW to an OTSG that has lost pressure control. With the loss of pressure control, temperature control is also lost and the heat removal rate becomes excessive. Main steam and MFW are isolated to the affected 0TSG when steam pressure reaches a low setpoint, a condition which is well below the normal operating pressure of the secondary system.
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| EFIC also performs an EFW control function to avoid delivering EFW to a depressurized OTSG when the other OTSG remains pressurized. This feed-only-the-good-generator (F0GG) logic is consistent with the design goal of isolating functional components whose pressure cannot be controlled.
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| F0GG logic precludes delivery of emergency feedwater to a depressurized 0TSG, thereby preventing an uncontrolled ;
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| cooldown as long as the other OTSG remains pressurized.
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| When both OTSGs are depressurized, the EFIC logic provides EFW flow to both OTSGs until a significant pressure difference develops between the two, thereby ensuring that core cooling is maintained.
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| Each EFW actuation logic train actuates on a one-out-of-two l taken twice combination of trip signals from the i instrumentation channels. Each EFIC channel can issue an initiate command, but an EFIC actuation will take place only if at least two channels issue initiate commands. The one-out-of-two taken twice logic combinations are transposed between trains so that failure of two channels prevents actuation of, at most, one train of EFW.
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| More detailed descriptions of the EFIC instrumentation are provided next.
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| (continued)
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| Crystal River Unit 3 8 3.3-83 Revision No. 7
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| EFIC Instrumentation B 3.3.11 .
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| J BASES
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| . ," ~
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| $ i BACKGROUND 1. [FW Initiation
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| . (continued) i' Figure 7-26 of the FSAR, Chapter 7 (Ref. 4) illustrates one channel of the EFIC EFW Initiation channel. The individual instrumentation channels that 4
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| input to the EFIC EFW Initiation Function are 4
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| discussed next. The AMSAC and HPI-based EFW Initiation Functions are not described further in e these Bases since they are not addressed by Technical Specifications.
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| 4
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| : a. Loss of MFW Pumos (Control Oil Pressure)
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| I. Loss of both MFW Pumps is one of the parameters monitored by EFIC to. automatically initiate EFW.
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| l MFW pump status (and thus the indication of Loss j of MFW Pumps) is detected by MFW pump turbine j control oil pressure. The MFW pump status
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| .. instrumentation is a part of the nuclear instrument (NI)/ Reactor Protection System (RPS).
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| l Each RPS channel receives MFW Pump status
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| : information from pressure switches (four per pump). If both switches in a single channel 1
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| : trip, the associated RPS channel trips. Each RPS ,
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| : channel acts as the sensor for this EFIC Function . ,
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| ! by providing both MFW Pumps tripped signal i indication to the associated EFIC channel. The trip Function is bypassed when THERMAL POWER s 20% RTP and the RPS is placed in shutdown l i bypass. The bypass is automatically removed when l J THERMAL POWER increases above 20% RTP.
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| l l Loss of both MFW Pumps was chosen as an EFW i automatic initiating parameter because it is a
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| ! direct and immediate indicator of loss of MFW.
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| l l b. OTSG Level--Low Four dedicated low range level transmitters on i each OTSG are monitored to generate the signals ;
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| used for an OTSG Level-Low EFW actuation. The 1 output from each transmitter provides a signal to each of the four EFIC channels A, B, C, and D.
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| i i
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| (.
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| (continued)
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| Crystal River Unit 3 8 3.3-84 Revision No. 7
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| +
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| EFIC instrumentation B 3.3.11
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| ~
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| BASES BACKGROUND- b. OTSG Level-low (continued)
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| The signals are also used by EFIC after.EFW has <
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| been actuated to control 0TSG 1evel at the low level setpoint of 30 inches when one or more RCPs e are operational.
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| The lower and upper taps for the low range level transmitters are located at 6 inches and 277 inches, respectively, above the upper face of the OTSG's lower tube sheet. The string is calibrated such that only the first 150 inches of indication are used. OTSG Level-Low was chosen ;
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| as an EFW automatic initiation parameter because ;
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| it represents a condition where feedwater is !
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| insufficient to meet the primary heat removal requirements and additional cooling water is l necessary. l
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| : c. OTSG Pressure-Low Four transmitters associated with each OTSG i provide the EFIC System with channels A through D ,
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| of OTSG Pressure-Low. These same transmitters l provide ~ input signals to EFIC MFW and Main Steam Line Isolation Functions. When OTSG pressure drops below the bistable setpoint of 600 psig on '
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| a given channel, an EFW Initiation signal is sent to both trains of automatic actuation. logic. The low pressure Function may be manually bypassed when pressure in either OTSG is less than 750 psig. The EFIC channel bypass is automatically removed when both OTSGs outlet pressure increases above 750 psig. The low pressure operational bypass allows for normal cooldown without EFIC actuation.
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| OTSG Pressuro-Low is a primary indication and actuation signal for steam line breaks (SLBs) or feedwater line breaks. For small breaks, which do not depressurize the OTSG or take a long time to depressurize, automatic actuation is not required. The operator has time to diagnose the problem and 'ake the appropriate actions.
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| (continued)
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| Crystal River Unit 3 8 3.3-85 Revision No. 7
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| EFTC instrumentation B 3.3.11 !
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| l BASES
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| ,, s
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| (
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| BACKGROUND d. RCP Status (continued)
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| A loss of power to all four RCPs is an immediate indication of a pending loss of forced flow in the Reactor Coolant System. The RPS acts as the sensor for this EFIC Function by providing a loss of RCP indication for each pump to each EFIC channel.
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| When a minimum of two EFIC channels recognize the loss of all RCPs, EFIC will automatically actuate i EFW and control level to approximately 65% in the OTSG. This higher setpoint provides a thermal center in the 0.TSG at a higher elevation than that of the reactor to ensure natural circulation as long as adequate subcooling margin is maintained.
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| To allow RCS heatup and cooldown without actuation, a bypass permissive of 10% RTP is used. The 10% bypass permissive was chosen because it was an available, qualified Class 1E signal at the time the EFIC System was designed.
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| When the first RCP is started, the " loss of four ,
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| ~
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| RCPs" initiation signal may be manually reset.
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| * If the bypass is not manually reset, it will be ,
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| automatically reset at 10% RTP. During cooldown, the bypass may be inserted at any time THERMAL POWER has been reduced below 10%. However, for most operating conditions, it is recommended that this trip function remain active until after the !
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| Decay Heat Removal System.has been placed in operation and just prior to tripping the last RCP. This trip function must be bypassed prior to stopping the last RCP in order to avoid an EFW actuation.
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| (continued)
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| Crystal River Unit 3 B 3.3-86 Revision No. 7
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| . . e - -
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| )
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| EFIC Instrumentation B 3.3.11 J
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| BASES 8ACKGROUND 2. EFW Vector Valve Control ,
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| (continued) Figure 7-26 of the FSAR, Chapter 7 (Ref. 4) ,
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| i illustrates one channel of the EFIC EFW Vector Valve '
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| Control logic. The function of the EFW vector logic is to determine whether EFW should be fed to one or the other, or both, OTSG. This EFIC function prevents l' the continued addition of EFW to a depressurized OTSG and, thus, minimizes the overcooling effects (and subsequent positive reactivity addition) due to a high :
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| energy line break on the secondary side.
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| i Each set of vector logic receives OTSG pressure ;
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| information from bistables located in the input logic of the same EFIC channel. The pressure information received is: i
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| : a. OTSG A pressure less than 600 psig;
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| : b. OTSG B pressure less than 600 psig;
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| : c. OTSG A pressure 125 psid greater than OTSG B }
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| pressure; and ,
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| : d. OTSG B pressure 125 psid greater than OTSG A (
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| ''ssure. t l Eact ,ector logic also receives a vector / control ,
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| enable signal from both EFIC actuation channel _ A and channel B when EFW is initiated. .The vector logic i develops signals to open or to close OTSG A and B EFW -l valves. The vector logic outputs are in a neutral ,
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| state until enabled by the control / vector enable from -
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| the channel A or B actuation logics. When enabled, the vector logic can issue open or close commands to the EFW control and block valves per the selected channel assignments. These channel assignments are ,
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| discussed in FSAR Section 7.2.4.2. This discussion i relates the control and block valves to their .
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| associated EFIC channel. j Each vector logic may isolate EFW to one OTSG or the l other, never both. .
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| I (continued)
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| Crystal River Unit 3 8 3.3-87 Revision No. 7
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| EFIC Instrumentation B 3.3.11 j BASES
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| * 7.
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| 4 BACKGROUND 2. EFW Vectot Valve Control (continued)
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| The control and block valve open or close commands are !
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| developed based upon the relative values of 0TSG pressures as follows:
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| 1 VECTOR VALVES 3
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| PRESSURE STATUS "A" "B" If OTSG "A" & OTSG "B" Open Open
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| > 600 psig If OTSG "A" > 600 psig & Open Close OTSG "B" < 600 psig i If 0TSG "A" < 600 psig & Close Open !
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| OTSG "B" > 600 psig l
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| If OTSG "A" & OTSG "B" !
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| < 600 psig l
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| 8!iQ OTSG "A" & OTSG "B" within Open Open 125 psid {, ,
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| OTSG "A" 125 psid > OTSG "B" Open Close OTSG "B" 125 psid > OTSG "A" Close Open Bypasi I One of the four EFIC initiation channels can be put into ;
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| " maintenance bypass" at any time. Bypassing an initiation !'
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| channel blocks that channel's signal from affecting a trip of the functions fed from it but does not bypass the trip logic within the actuation channel. An interlock feature
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| . prevents bypassing more than one channel at a time. In i addition, since EFIC receives signals from NI/RPS, the maintenance bypass from the NI/RPS is interlocked with the EFIC System. If one channel of the NI/RPS is in maintenance '
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| bypass, only the corresponding channel.of the EFIC may be bypassed (e.g., channel A, NI/RPS, and channel A, EFIC).
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| This ensures that only the corresponding channels of the EFIC and NI/RPS are placed in maintenance bypass at the same time.
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| (continued)
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| Crystal River Unit 3 B 3.3-88 Revision No. 7
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| EFlc Instrumentation B 3.3.11 BASES
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| , BACKGROUND Bvoass (continued)
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| EFIC channel maintenance bypass does not bypass EFW '
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| Initiation from Engineered Safeguards Actuation System (ESAS) Channel A and Channel B high pressure injection (HPI) actuation. However, the EFIC initiation on HPI actuation is bypassed when ESAS is bypassed.
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| [ The operational bypass provisions were discussed as part of
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| : the individual Furrctions described earlier.
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| a 3, 4. Main Steam Line and MFW Isolation
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| : FSAR Figure 7-26, (Ref. 3) illustrates one channel of l the EFIC Main Steam Line and MFW Isolation logic. ,
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| 4 Four pressure transmitters per OTSG provide EFIC with
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| ! channels A through D of 0TSG pressure. The description of the channels was described earlier for EFW Initiation.
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| 4
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| ; Once isolated, manual action is required to defeat the i
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| ; isolation command if desired. The EFIC System is ,
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| i designed to perform its intended function with one
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| ! channel in maintenance bypass (in effect, inoperable) and a single failure in one of the remaining channels.
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| ; This design complies with IEEE-279-1971 (Ref. 4) due
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| , to the_ redundancy and independence in the EFIC design.
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| 4 l l APPLICABLE 1. EFW-Initiation i SAFETY ANALYSES The DBA which forms the basis for initiation of EFW is a loss of MFW transient. In the analysis of this transient, SG Level-Low is the parameter assumed to ,
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| automatically initiate EFW. Although loss of both MFW i pumps is a direct and immediate indicator of loss of l MFW, there are other scenarios (such as valve closure) that could potentially cause a loss of feedwater.
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| Therefore, the loss of MFW analysis conservatively assumed EFW actuation on low OTSG 1evel. This assumption yields the minimum OTSG-inventory available i for heat removal and is, therefore, conservative for !
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| (continued)
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| I Crystal River Unit 3 8 3.3-89 Revision No. 7
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| -W
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| EFIC Enstrumentation B 3.3.11 BASES go
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| (: .
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| APPLICABLE 1. EFW Initiation (continued)
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| SAFETY ANALYSES evaluation of this event. If the Icss of feedwater is a direct result of a loss of the U W pumps, EFW will j be actuated much earlier than assumed in the l analysis.This would increase OTSG heat transfer capability sooner in the event and would lessen the severity of the transient.
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| OT$G Pressure-Low is a p.rimary indication and provides ,
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| the actuation signal for* SLBs or MFW line breaks. '
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| Only one of the four SLB cases examined in the FSAR assumes normal automatic actuation of EFW. The other three cases assume manual initiation after 15 minutes.
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| For small breaks, which do not depressurize the OTSG or take a long time to depressurize, automatic actuation is not required. The operator has sufficient time to diagnose the problem and take the-appropriate actions.
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| Loss of four RCPs is a primary indicator of the need i for EFW in the safety analyses for loss of electric l power and loss of coolant flow. , 1
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| (
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| : 2. EFW Vector Valve Control Most of the FSAR SLB analyses were performed prior to !
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| the development of EFIC. Therefore, EFIC vector valve control was not credited in the original licensing basis for a main SLB analysis. Instead, operator action was credited with isolating emergency feedwater to the affected 0TSG. However, since isolating the affected 0TSG is a function automatically performed by EFIC, the FSAR analysis remains conservative relative to the inclusion of the vector valve control.
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| 3, 4. Main Steam Line and MFW Isolation The Chapter 14 FSAR analysis assumed Integrated Control System action for MFW and Main Steam Line Isolation. The analysis took credit for turbine stop valve closure and feedwater valve isolation on reactor (continued)
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| Crystal River Unit 3 B 3.3-90 Revision No. 7
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| EFIC Instrumentation B 3.3.11 i BASES APPLICABLE 3, 4. Main Steam Line and MFW Isolation (continued)
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| SAFETY ANALYSES trip and following EFIC installation considered the isolation functions occurring on OTSG pressure
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| < 600 psig as backup. Since these isolation functions would currently be provided by the safety grade EFIC System, use of the EFIC System in the original safety analysis would have been consistent with the licensing position allowing mitigative functions to be performed by safety grade systems in accident analysis. For these reasons, the SLB accident analysis remains conservative with the assumed Integrated Control System actions.
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| The EFIC System satisfies Criterion 3 of the NRC Policy Statement.
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| LCO All instrumentation performing an EFIC System Function listed in Table B 3.3.11-1 shall be OPERABLE. Four channels are required OPERABLE for all EFIC instrumentation channels to ensure that no single failure prevents actuation of a train. Each EFIC instrumentation channel is considered to include the sensors and measurement channels for each Function, the operational bypass switches, and permissives.
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| Failures that disable the capability to place a channel in operational bypass, but which do not disable the trip Function, do not render the protection channel inoperable.
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| ~
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| The Bases for the LC0 requirements of each specific EFIC Function are discussed next.
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| Loss of MFW Pumos Four EFIC channels shall be OPERABLE with MFW pump turbines A and B control oil low pressure actuation setpoints of > 55 psig. The 55 psig setpoint is about half of the normal operating control oil pressure. The 55 psig setpoint Allowable Value appears to have been arbitrarily chosen as a good indication of the Loss of MFW Pumps.
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| Analysis only assumes Loss of MFW Pumps and a specific value of MFW pump control oil pressure is not used in the analysis. Further, since the setpoint is so much less than (continued)
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| Crystal River Unit 3 B 3.3-91 Revision No. 7
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| EFIC Instrumentation B 3.3.11 BASES r"N 1
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| LCO loss of MFW Pumos (continued) operating control oil pressure, instrument error is not a consideration. The Loss of MFW Pumps Function includes a bypass enable and removal function utilizing the same bistable and auxiliary relay used in the NI/RPS bypass reactor trip on loss of both MFW pumps. However, the EFIC bypass is a logic requiring neutron flux to be < 20% RTP and the RPS to be in shutdown bypass. Practically speaking, the status of the bypass is strictly a function of the RPS shutdown bypass (i.e., required to be OPERABLE down into MODE 3).
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| OTSG Level--Low Four EFIC dedicated low range level transmitters per OTSG shall be OPERABLE with OTSG Level--Low actuation setpoints of 2 0 inches indicated (6 inches above the top of the bottom tube sheet), to generate the signals used for detection for low level conditions for EFW Initiation.
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| There is one transmitter for each of the four channels A, B, C, and D. The signals are also used after EFW is actuated -
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| to control at the low level setpoint of 30 inches when one i or more RCPs are in operation. In the determination of the low level setpoint, it is desired to place the setpoint as low as possible, considering instrument errors, to give the maximum operating margin between the ICS low load control setpoint and the EFW initiation setpoint. This minimizes spurious or unwanted initiation of EFW. To meet this criteria, a nominal setpoint of 6 inches indicated was selected, adjusted for potential instrument error, and shown to be conservative to the specified Allowable Value. Credit is only taken for low level actuation for those transients which do not involve a degraded environment. Therefore, normal environment errors only are used for determining the OTSG Level--Low Allowable Value.
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| OTSG Pressure--Low Four OTSG Pressure--Low EFIC channels per OTSG shall be OPERABLE with actuation setpoints of 2 600 psig. The actual plant setpoint is 2 625 psig to account for instrument error. The setpoint is chosen to avoid actuation under (continued)
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| Crystal' River Unit 3 8 3.3-92 Revision No. 7
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| EFlc Instrumentation B 3.3.11 BASES LC0 OTSG Pressure-Low (continued) transient conditions not requiring secondary system isolation, and has been shown to be an appropriate indicator of secondary side breaks for ensuring automatic EFW actuation. The OTSG Pressure-Low Function includes a bypass enable and removal function. The bypass removal Allowable Value is chosen to allow sufficient operating
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| . margin (time) for the operator to bypass the actuation during plant cooldown prior to reaching the actuation setpoint. The 750 psig setpoint allows at least a 10 minute window to perform the bypass assuming the maximum allowed cooldown rate and instrument error.
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| OTSG Differential Press' re-Hiah Four EFIC channels fo' 6TSG differential pressure shall be OPERABLE with setpoints of :s; 125 psid. The FOGG Verification Study (Ref. 5) assumed a differential pressure value of 150 psid including a 25 psi margin for instrument error. The setpoint ensures that automatic EFW isolation to a depressurized 0TSG occurs for the range of sizes of SLBs or feedwater line breaks that require rapid actuation early in the event. The setpoint has also been chosen to avoid spurious isolation of EFW during conditions due ta relatively small deviations in OTSG pressures that can be caused by primary system conditions. The OTSG Differential Pressure-High Function is bypassed when the OTSG Pressure-Low Function is bypassed.
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| RCP Status Four EFIC channels for RCP status are required to be OPERABLE to ensure that upon the loss of all four RCPs, EFW will be automatically initiated. Additionally, EFW will j automatically raise and control level to approximately 65%,
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| providing a higher driving head for establishing and maintaining natural circulation conditions when forced RCS flow is lost. No setpoint is specified since the status indication used by EFIC is binary in nature. The RCP Status Function includes a bypass enable and removal function from the RPS. The Allowable Value for the bypass removal is set high enough to avoid spurious actuations during low power operation.
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| (continued) l Crystal River Unit 3 8 3.3-93 Revision No. 7 l l
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| EFlc instrumentation j B 3.3.11 I
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| BASES (continued) ['
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| APPLICA31LITY EFIC instrumentation OPERABILITY requirements are applicable during the MODES and specified conditions listed in
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| : Table 3.3.11-1. Each Function has its own requirements d
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| based on the specific accidents and conditions for which it
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| ; is designed to provide protection.
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| The initiation of EFW on the Loss of MFW Pumps is applicable in MODE 1 and in MODES 2 and 3 when not in shutdown bypass.
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| i .
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| Below these plant conditions, EFW initiation on low OTSG level occurs fast enough to prevent primary system overheating.
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| EFW Initiation on low OTSG 1evel shall be OPERABLE at all times the OTSG is required for heat removal. These J
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| conditions include MODES 1, 2, and 3. To avoid automatic actuation of the EFW pumps during heatup and cooldown, the
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| , low OTSG pressure Function can be bypassed at or below a
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| , secondary pressure of 750 psig. This secondary-side ,
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| ; pressure occurs during MODE 3 operation.
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| EFW initiation on loss of all RCPs is required to be OPERABLE at 2: 10% RTP. This power level coincides with the bypass permissive signal provided by RPS. ,
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| 1 t
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| , The MFW, Main Steam Line Isolation, and EFW Vector Valve i Control Functions shall be OPERABLE in MODES 1, 2, and 3 with OTSG pressure at 750 psig because OTSG inventory can be high enough to contribute significantly to the peak pressure
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| : following a secondary side break. Both the normal feedwater
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| ! and the EFW must be isolatable on each OTSG to limit overcooling of the primary and mass and energy releases to the RB. Once OTSG pressures decrease below 750 psig, the
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| , Main Steam Line and MFW Isolation Functions can be bypassed 4
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| to prevent actuation during cooldown. The EFW Vector Valve Control logic will not perform any function when both OTSG pressures are low; thus, the logic is also bypassed at the same time the OTSG pressure low Functions is bypassed. In MODES 4, 5, and 6, primary and secondary side energy levels are reduced and the feedwater flow rate is low or nonexistent. Because of this, EFIC instrumentation is not required to be OPERABLE in these MODES.
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| a I
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| l (continued) . l Crystal River Unit 3 8 3.3-94 Revision No. 7 i
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| ~. -
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| EFIC Instrumentation B 3.3.11 BASES (continued)
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| ACTIONS A Note has been.added to the ACTIONS indicating that a separate Condition entry is allowed for each. Function.
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| A.1 and A.2 Condition A applies to failures of a single EFW Initiation, Main Steam Line Isolation, or MFW Isolation instrumentation channel. This includes failure of a common instrumentation
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| . channel in any combination of the Functions.
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| With one channel inoperable in one or more EFW Initiation, Main Steam Line Isolation, or MFW Isolation Functions listed in Table 3.3.11-1, the channel (s) must be placed in bypass or trip within 1 hour. This Condition applies to failures that occur in a single channel, e.g., channel A, which when bypassed will remove initiate Functions within the channel from service. Since the RPS and EFIC channels are interlocked, only the corresponding channel in each system may be bypassed at any time. This feature is ensured by an electrical interlock. The Completion Time of I hour is adequate to perform Required Action A.I.
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| Required Action A.2 provides a limit on the period of time an EFIC instrumentation channel is allowed to remain in bypass. While this Condition appears to satisfy system single failure considerations, it was not analyzed as part of the plant's original licensing basis and it is possible this configuration would not satisfy all aspects of IEEE 279 single failure criteria. As a result, the 72 hour Completion Time was added to impose a limit on the period of time the plant is allowed to operate in this Condition. As such, the Completion Time is based on engineering judgment and the IEEE 279 recommendations.
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| B.1. B.2. and B.3 Condition B applies to situations where two instrumentation channels for EFW Initiation, Main Steam Line Isolation, or i MFW Isolation Functions are inoperable. For example, l Condition B applies if channel A and B of the EFW Initiation ,
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| Function (say, on low OTSG pressure) are inoperable. )
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| Condition B does not apply if one channel of different j Functions is inoperable in the same protection channel. l That condition is addressed by Condition A. (
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| i (continued) l Crystal River Unit 3 8 3.3-95 Revision No. 7
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| EFlC Znstrumentation B 3.3.11
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| ^
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| BASES
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| (
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| ACTIONS B.1, B.2. and B.3 (continued)
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| With two EFW Initiation, Main Steam Line Isolation, or MFW Isolation protection channels inoperable, or.a channel must be placed in bypass (Required Action B.1). Bypassing another channel. is not possible due to system interlocks.
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| Therefore, the second channel must be tripped (Required Action B.2) to prevent a single failure from causing loss of the EFIC Function. The 1 hour Completion Time is adequate to perform.the Required Actions and minimizes the period of time the plant is at risk due to this condition.
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| Required Action B.3 provides a limit on the period of time an EFIC instrumentation channel is allowed to remain in bypass. While this Condition appears to satisfy system single failure considerations, it was not analyzed.as part of the plant's original licensing basis and it is possible
| |
| . this configuration would not satisfy all aspects of IEEE 279 single failure criteria. As a result, the 72 hour Completion Time was added to impose a limit on the period of time the plant is allowed to operate in this Condition. As such, the Completion Time is based on engineering judgment and the IEEE 279 recommendations.
| |
| Ll The EFW Vector Valve Control Function is required to meet the single-failure criterion for both the function of providing EFW on demand and isolating an OTSG when required.
| |
| These conflicting requirements result in the necessity for two valves in series, in parallel with two valves in series, and a four channel valve command system. Refer to LC0 3.3.14, " Emergency Feedwater Initiation and Control (EFIC) Emergency Feedwater (EFW)-Vector Vaive Logic" for a discussion of the logic of the system. i With one EFW Vector Valve Control channel inoperable, the system cannot meet the single-failure criterion and still ;
| |
| meet the dual functional criteria described above. This !
| |
| Condition is analogous to having one EFW train inoperable. i Therefore, when one vector valve control channel is inoperable, the channel must be restored to OPERABLE status within 72 hours. This Condition'and Completion Time combination is consistent with the Completion Time associated with the loss of one train of EFW.
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-96 Revision No. 7
| |
| | |
| .,J.s4s -. 4 J.. -i_=.SJ+4-_A. --..,A l.34a a-- J--waL-A-*J em 2AM ,. M 4.4 --4 +- -he-d- - --+ - .A am- -4 - ,E-*- -
| |
| 4--- m. , - . +
| |
| i~
| |
| EFIC Instrumentation B 3.3.11 l
| |
| BASES i ACTIONS D.l. D.2.1. 0.2.2. E.1 and F.1 (continued)
| |
| If the Required Actions cannot be met within the associated Completion Time, the plant must be placed in a MODE or condition in which the requirement for the particular Function does not apply. This requires the operator to open the CRD trip breakers for Function 1.a, MODE 4 for .
| |
| Function 1.b, reduce power to less than 10% RTP for
| |
| > Function 1.d, and reduce OTSG pressure to less than 750 psig for all other Functions. The allowed Completion Times are
| |
| , reasonable, based on operating experience, to reach the specified conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| i SURVEILLANCE A Note indicates that the SRs for each EFIC instrumentation REQUIREMENTS Function are identified in the SRs column of Table 3.3.11-1.
| |
| All Functions are subject to CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION. The SG-Low Level
| |
| : Function is the only EFW initiation Function modeled in transient analysis, and thus is the only one subject to
| |
| ! response time testing. Response time testing is also required for Main Steam Line and MFW Isolation. Individual EFIC subgroup relays must also be tested, one at a time, to verify the individual EFIC components will actuate when required. Some components cannot be tested at power since their actuation might lead to reactor trip or equipment damage. These are specifically identified and must be
| |
| ; tested when shut down. The various SRs account for i
| |
| - individual functional differences and for test freotencies i applicable specifically to the Functions listed in Table 3.3.11-1. The operational bypasses associated with each EFIC instrumentation channel are also subject to these SRs to ensure OPERABILITY of the EFIC instrumentation channel when required.
| |
| SR 3.3.11.1 Performance of the CHANNEL CHECK once every 12 hours ensures 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. It is based on the assumption that instrument channels (continued)
| |
| Crystal River Unit 3 B 3.3-97 Revision No. 7 1 -
| |
| | |
| - - - - - - - - . - .. . - ~ _
| |
| I EF1C Instrumentation B 3.3.11 i BASES
| |
| ("
| |
| SURVEILLANCE SR 3.3.11.1 (continued)
| |
| REQUIREMENTS
| |
| . 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 of scmething even more serious.
| |
| Acceptance criteria are determined by plant staff and are presented in the Surveillance Pro:edure. The criteria are ,
| |
| based on a combination of the channel instrument uncertainties.
| |
| The Frequency, about once every shift, is based on operating experience that demonstrates channel failure is unlikely.
| |
| Thus, performance of the CHANNEL CHECK ensures that undetected overt channel failure is limited to time intervals between subsequent performances of the SR.
| |
| SR 3.3.11.2 A CHANNEL FUNCTIONAL TEST verifies the function of the required trip, interlock, and alarm functions of the t channel. The Frequency of 31 days is based on operating '
| |
| experience and industry accepted practice.
| |
| SR 3.3.11.3 CHANNEL CALIBRATION is a complete check of the instrument channel including the sensor. The test verifies the channel responds to a measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channels adjusted to account for instrument drift to ensure that the instrument channel remains operational between successive tests. The 24 month Frequency is based on the results of a review of instrument drift data conducted in accordance with NRC Generic Letter 91-04.
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-98 Revision No. 7
| |
| | |
| EFIC Instrumentatibn B 3.3.11 BASES
| |
| (
| |
| V SURVEILLANCE SR 3.3.11.4 REQUIREMENTS (continued) This SR verifies individual channel response times are less than or equal to the maximum value assumed in the accident analysis. Individual component response times are not modeled in the analysis. The analysis models the overall or total elapsed ~ time, from the point at which the parameter exceeds the actuation setpoint value at the sensor, to the point at which the end device is actuated.
| |
| EFIC RESPONSE TIME tests are conducted on an 24 month STAGGERED TEST BASIS. Testing of the final actuation devices, which make up the bulk of the EFIC RESPONSE TIME, is included in the testing of each channel. Therefore, staggered testing results in response time verification of these devices every 24 months. The 24 month test Frequency is based on operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel fai!vre, are infrequent occurrences. EFIC RESPONSE TIMES cinrat be determined at power since equipment operation, which would induce undesired plant transients, is required.
| |
| The SR is modified by a Note indicating the SR is not required to be performed prior to entry into MODE 2. This is due to the fact that secondary side (Main Steam) supply pressure for the turbine driven pump is not sufficient to perform the test until after entering MODE 3. The SR 3.0.4 type allowance is also applicable to the MFW and Main Steam Line isolation Functions, consistent with the allowances provided for the end devices in'their respective Specifications (Specifications 3.7.2 and 3.7.3).
| |
| REFERENCES 1. FSAR, Section 14.1.
| |
| : 2. 10 CFR 50.49.
| |
| : 3. FSAR, Chapter 7.
| |
| : 4. IEEE-279-1971.
| |
| : 5. B&W Document 51-1123786-01, "F0GG Verification Study",
| |
| May 4, 1981.
| |
| Crystal River Unit 3 B 3.3-99 Revision No. 7
| |
| | |
| EFIC Manual Initiation B 3.3.12 B 3.3 INSTRUMENTATION "
| |
| B 3.3.12 Emergency Feedwater Initiation and Control (EFIC) Manual Initiation BASES BACKGROUND Th.e EFIC manual initiation capability provides the operator with the capability to actuate certain EFIC Functions in the absence of an automatic initiation condition. Functions with the capability to be manually actuated include Main Feedwater (MFW) Isolation for Once Through Steam Generator (OTSG) A, MFW Isolation for OTSG B, Main Steam Line Isolation for OTSG A, Main Steam Line Isolation for OTSG B, and Emergency Feedwater (EFW) Actuation.
| |
| The EFIC manual initiation circuitry satisfies the manual initiation and single-failure criterion requirements of IEEE-279-1971 (Ref. 1).
| |
| Although not part of this LCO, the EFIC Functions listed above can also be remotely manually initiated from the EFIC cabinets.
| |
| APPLICABLE EFIC Functions credited in the safety analysis are SAFETY ANALYSES automatic. However, EFIC manual initiation Functions are required by design as backups to the automatic trip Functions. This allows the operator to actuate EFW, Main Steam Line Isolation, or MFW Isolation whenever conditions dictate and one has not already automatically occurred. As such, they are backup Functions to those performed automatically by EFIC.
| |
| LCO Two manual initiation switches per actuation channel (A and B) of each Function (OTSG t. and 8 MFW Isolation, OTSG A ,
| |
| and B Main Steam Line Isolation, and EFW Actuation) are required to be OPERABLE whenever the OTSGs are relied on to remove heat from the primary. Each Function (MFW Isolation, Main Steam Line Isolation, und EFW Initiation) has two actuation or " trip" channels, channels A and B. Within each channel A actuation logic there are two manual trip switches. When one manual switch is depressed, a half trip (continued)
| |
| Crystal River Unit 3 8 3.3-I00 Amendment No. 149
| |
| | |
| l )
| |
| I i
| |
| Control Room Isolation--High Radiation
| |
| ! B 3.3.16 i
| |
| BASES SURVEILLANCE SR 3.3.16.3 REQUIREMENTS (continued) This SR requires the performance of a CHANNEL CALIBRATION with a setpoint Allowable Value of less than or equal to two times the background count rate. l l
| |
| CHANNEL CALIBRATION is a complete check of the instrument l string including and the sensor. The test verifies that the channel responds to a ueasured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations to ensure that the channel remains OPERABLE between successive tests.
| |
| The 18 month Frequency is based on engineering judgment and industry-accepted practice.
| |
| 1 I
| |
| l
| |
| ! REFERENCES 1. 10 CFR 50, G0C 19.
| |
| l
| |
| : 2. NUREG-1366, December 1992.
| |
| l l
| |
| I l
| |
| l l
| |
| l 4
| |
| f B 3.3-123 Amendment No. 149 l Crystal River Unit 3 l
| |
| l
| |
| | |
| PAM Instrumentation B 3.3.17 i B 3.3 INSTRUMENTATION t
| |
| B 3.3.17 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND The function of PAM instrumentation is to display plant process variables that provide information for the operator '
| |
| to take the manual actions assumed for Design Basis Accident (DBA) mitigation. In addition, certain PAM instrumentation #
| |
| also.provides information to assess the performance and status of selected plant systems following a DBA. These essential instruments, identified in FSAR, Table 7-12, '
| |
| (Ref.1) address the recommendations of Regulatory Guide 1.97 (Ref. 2) as required by Supplement I to NUREG 0737 (Ref. 3). i The instrument channels required to be OPERABLE by this LC0 i are those parameters identified during the CR-3 specific !
| |
| implementation of Regulatory Guide 1.97 as Type A variables and non-Type A, Category 1 variables. Type A variables are included in this LC0 because they provide the crimary '
| |
| information that permits the control room operator to take specific manually controlled actions that are required when no automatic control is provided and that are required-for safety systems to accomplish their safety functions for DBAs, (Ref. 2). Primary information is that required for 4 the direct accomplishment of the specified safety function; l it does not include those variables associated with contingency actions. Category 1 variables are the key l variables deemed risk significant for CR-3.
| |
| I APPLICABLE The PAM instrumentation ensures the information is SAFETY ANALYSES available to the control room operating staff:
| |
| : a. Perform the diagnosis specified in the emergency I operating procedures. These variables are restricted to pre-planned actions for the primary success path of I DBAs (e.g., loss of coolant accident (LOCA)); )
| |
| : b. Take the specified, preplanned, manually controlled actions, for which no automatic control is provided, which are required for safety systems to accomplish their safety functions; (continued)
| |
| Crystal River Unit 3 8 3.3-124 Revision No. 11
| |
| | |
| ._ . . .. _ _ _ _ _ _ _ _ . _ _ ~ - _ _ __ m . _ -
| |
| PAM Instrumentation B 3.3.17 1
| |
| (
| |
| BASES ;
| |
| P APPLICABLE c. Determine whether systems important to safety are SAFETY ANALYSES performing their intended functions; (continued)
| |
| : d. Determine the potential for a gross breach of the barriers to radioactivity release;
| |
| : e. Determine if a gross breach of a barrier has occurred; and
| |
| : f. Initiate action necessary to protect the public and estimate the magnitude of any impending threat.
| |
| PAM instrumentation that is determined to display a Regulatory Guide 1.97. Type A variable, satisfies Criterion 3 of the NRC Policy Statement. Category 1, non-Type A, instrumentation does not meet any of the criterion in the NRC Policy Statement. However, it is retained in Technical Specifications because it is considered important to reducing risk to the public.
| |
| LC0 LC0 3.3.17 requires redundant channels be OPERABLE to ensure t no single failure prevents the operators from being :
| |
| presented with the information necessary to determine the ,
| |
| status of the unit and to bring the unit to, and maintain it i in, a safe condition following that accident. The provision of two channels also allov.s for relative comparison of the channels (a. CHANNEL CHECK type of qualitative assessment) during the post accident phase to confirm the validity of ,
| |
| displayed information. ,
| |
| The exception to the two channel requirement is containment isolation valve position. In this case, the important information is the status of the containment penetration.
| |
| The LC0 requires one position indicator for each automatic containment isolation valve. This is sufficient to redundantly verify the isolation status of each isolable penetration either via indicated status of the automatic valve and prior knowledge of the passive valve or via system boundary status. If a normally active containment isolation valve is known to be closed and deactivated, position indication is not needed to determine status. Therefore, the positinn indication for valves in this state is not required to be OPERABLE.
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-125 Revision No. 11 I
| |
| | |
| PAM Instrumentation B 3.3.17 BASES ~
| |
| LCO The following list is a discussion of the specified (continued) instrument Functions listed in Table 3.3.17-1.
| |
| : 1. Wide Ranae Neutron Flux Two wide-range neutron flux monitors are provided for post-accident reactivity monitoring over the entire '
| |
| range of expected conditions. Each monitor provides indication over the range of 10' to 100% log rated power covering the source, intermediate, and power ranges. Each monitor utilizes a fission chamber neutron detector to provide redundant main control board indication. A single channel provides recorded
| |
| * information in the control room. The control room indication of neutron flux is considered one of the primary indications used by the operator following an accident. Following an event the neutron flux is monitored for reactivity control. The operator ensures that the reactor trips as necessary and that emergency boration is initiated if required. Since the operator relies upon this indication in order to take specified manual action, the variable is included i
| |
| in this LCO. Therefore, the LCO deals specifically with this portion of the string. l
| |
| : 2. Reactor Coolant System (RCS) Hot Leo Temoerature l
| |
| Two wide range resistance temperature detectors (RID's), one per loop, provide indication of reactor 1 l
| |
| coolant system hot leg temperature (T,) over the range i of 120' to 920'F. Each Tu measurement provides an input to a control room indicator. Channel B is also recorded in the control room. Since the operator 1 relies on the control room indication following an I accident, the LCO deals specifically with this portion of the string.
| |
| T, is a Type A variable on which the operator bases manual actions required for event mitigation for which no automatic controls are provided. This temperature measurement provides input to the inadequate core cooling instrumentation which is used to verify the (continued)
| |
| Crystal River Unit 3 8 3.3-126 Revision No. 11
| |
| | |
| PAM Instrumentation B 3.3.17 BASES LC0 2. Reactor Coolant System (RCS) Hot Lea Temperature (continued) existence of, or to take actions to ensure the restoration of subcooling margin. Specifically, a
| |
| . loss of adequate subcooling margin during a small break LOCA requires the operator to trip the reactor coolant pumps (RCP's), ensure high or low pressure injection, and raise the steam generator levels to the ECC level. Once subcooling margin is restored, the operator is instructed to restart at least one RCP and throttle injection flow to maintain a specified degree of subcooling. Another manual action based on Tn follows a steam generator tube rupture. The affected steam generator is to be isolated only after Tu falls below the saturation temperature corresponding to the pressure setpoint of the main steam safety valves.
| |
| For event monitoring once the RCP's are tripped, Tu is used along with the core exit temperatures and RCS cold leg temperature to measure the temperature rise across the core for verification of core cooling.
| |
| : 3. RCS Pressure (Wide Ranae) l RCS pressure is measured by pressure transmitters with a span of 0-3000 psig. Redundant monitoring ;
| |
| capability is provided by two trains of instrumentation. Control room and remote shutdown panel indications are provided. The subcooling margin monitor can also display reactor coolant pressure upon demand. The control room indications are the primary indications used by the operator during an accident.
| |
| Therefore, the LCO deals specifically with this portion of the instrument string.
| |
| RCS pressure is a Type A variable because the operator uses this indication to adjust parameters such as steam generator (OTSG) level or pressure in order to monitor and maintain a controlled cooldown of the RCS following a steam generator tube rupture or sinall break LOCA. In addition, HPI flow is throttled based (continued)
| |
| Crystal River Unit 3 B 3.3-127 Revision No. 11
| |
| | |
| r PAM Instrumentation B 3.3.17
| |
| ~,
| |
| BASES LC0 3. RCS Pressure (Wide Ranae) (continued) on RCS pressure. Finally, HPI flow is required for some small break LOCAs, where LPI may actuate with system pressure stabilizing above the shutoff head of the LPI pumps. If this condition exists, the operator is instructed to verify HPI flow and then stop the LPI pumps in order to preclude extended operation against a deadhead pressure.
| |
| : 4. Reactor Coolant Inventory Reactor Vessel Water Level instrumentation is provided for verification and long term surveillance of core cooling. The reactor vessel level monitoring system provides a direct measurement of the collapsed liquid level above the fuel alignment plate. The collapsed level represents the amount of liquid mass that is in the reactor vessel above the core. Measurement of the collapsed water level is selected because it is a direct indication of the water inventory. ;
| |
| The collapsed level is obtained over the same temperature and pressure range as the saturation measurements, thereby encompassing all operating and accident conditions where it must function. Also, it functions during the recovery interval. Therefore, it is designed to survive the high steam temperature that may occur during the preceding core recovery interval.
| |
| The level range extends from the top of the vessel l down to the top of the fuel alignment plate. The
| |
| ! response time is short enough to track the level during small break LOCA events. The resolution is sufficient to show the initial level drop, the key locations near the hot leg elevation, and the lowest l levels just above the alignment plate. This provides l the operator with adequate indication to track the l
| |
| progression of the accident and to detect the I
| |
| consequences of its mitigating actions or the functionality of automatic equipment.
| |
| (continued) l Crystal River Unit 3 B 3.3-128 Revision No. 11
| |
| | |
| i 2 PAM Instrumentation B 3.3.17
| |
| ; . BASES i
| |
| i LCO 5. Borated Water Storaae Tank (BWST) level i j (continued) l BWST inventory is monitored by level instrumentation
| |
| ~
| |
| with a span of 0 to 50 feet. Redundant monitoring capability is provided by three independent level. ;
| |
| measurements. Two level transmitters provide input to L
| |
| 3 control room indicators, and one of these channels is j recorded in the control room. The control room j indications are the primary indications used by the
| |
| ; operator. Therefore, the LC0 deals specifically with 3
| |
| this portion of the instrument string. ;
| |
| 4 q
| |
| i During a design basis LOCA, the Reactor Building
| |
| ; Spray, Low Pressure Injection (LPI) and High Pressure j Injection (HPI) Systems are automatically aligned to obtain suction from the BWST. As the BWST inventory is pumped into the RCS and containment, coolant will be lost through the break and will accumulate in the reactor building sump. The operator is required to i
| |
| switch LPI and RB Spray suction to the reactor building emergency sump from the BWST when the BWST ,
| |
| j level reaches a specified level setpoint. At this i
| |
| same time if the RCS pressure is greater than the LPI
| |
| ; pump shutoff head, it will also be necessary to switch the suction of the HPl pumps to the discharge of the
| |
| ; LPI pumps to ensure the capability to inject flow to the RCS since the HPI pumps do not have the capability of drawing coolant from the sump. BWST levei is a
| |
| ! Type A variable because it is the primary indication used by the operator to determine when to initiate the switch-over to sump recirculation. This operator action is necessary to satisfy.the long-term core
| |
| ; cooling requirements specified in 10 CFR 50.46.
| |
| i 6. HPI Flow (Low Ranae) i
| |
| - HPI flow is determined from differential pressure ,
| |
| transmitters. Two channels in each of the four i injection lines, for a total of eight low range j indicators, provides this indication. One transmitter !
| |
| is calibrated to a range of 0-200 gpm. Each differential pressure measurement provides an input to a control room indicator. Since the. operator relies on the control room indication following an accident, the LC0 deals with this portion of the instrument string.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-129 Revision No. 11
| |
| | |
| PAM Instrumentation 8 3.3.17 1
| |
| , g.
| |
| BASES I l LCO 6. HPI Flow (Low Ranae) (continued) l I !
| |
| Although 4 high range flow indicators (0-500 gpm) i readout on the main control board, they are not used 1 to accomplish any safety functions. Two HPI pump J operation can not achieve runout regardless of their !
| |
| suction source. However, single HPI pump operation, .
| |
| while in a piggy-back configuration, can achieve !
| |
| runout. Operators throttle HPI flow to prevent runout i using the low range instruments.
| |
| In addition to monitoring for and preventing HPI pump runout, as described above, the low range flow rate l instruments provide indication of the required accuracy over the flow rates of interest to determine <
| |
| if HPI line isolation criteria have been met. Certain HPI line breaks (double ended rupture and the larger i pinch breaks) require isolation of the faulted HPI i line to assure adequate HPI flow is injected into the reactor coolant system.
| |
| I
| |
| : 7. Containment Sumo Water Level (Flood level) '
| |
| Containment sump water level (Flood) is monitored by two channels of level indication, both of which are displayed in the control room on edgewise level indicators. Channel A and B sump flood level indication are recorded in the associated 'A' and 'B' EFIC Rooms. Each instrument encompasses a range of l 0-10 feet above the sump and provides information to l the operator related to gross leakage in the Reactor l Building. This leakage may be indication of {
| |
| degradation in the reactor coolant pressure boundary 1 (RCPB) which would require further investigation and ;
| |
| action. These instruments are not assumed to provide 1 information required by the operator to take a I mitigation action specified in the accident analysis.
| |
| As such, they are not Type A variables. However, the ,
| |
| monitors are deemed risk significant (Category 1) and l are included within the LC0 based upon this 1 consideration. I i
| |
| (continued) l Crystal River Unit 3 8 3.3-130 Revision No. 11
| |
| | |
| 4 PAM Instrunientation 2 B 3 3.17 l i
| |
| . - BASES i LC0 I
| |
| ; 8,9. Containment Pressure (Narrow Ranae and Wide Rance)
| |
| The containment pressure variable is monitored by two ranges of prossure indication. Narrow range (-10 to 60 psig) and wide range (0 to 200 psig) pressure
| |
| : indication each provide two channels of pressure
| |
| ! indication. Channel A and B wide range containment pressure are recorded in the associated 'A' and 'B'
| |
| : EFIC Rooms. The low range is required in order to ensure instrumentation of the necessary accuracy is i available to monitor conditions in the RB during DBAs.
| |
| j The wide range instrument was required by Regulatory
| |
| ! Guide 1.97 to be capable of monitoring pressures over
| |
| ; the range of atmospheric to three times containment i design pressure (approximately 165 psig). Thus, it I was intended to monitor the RB in the event of an accident not bounded by the plant safety analysis (i.e., a Severe Accident).
| |
| These instruments are not assumed to provide information required by the operator to take a mitigation action specified in the accident analysis.
| |
| As such, they are not Type A variables. However, the l monitors are deemed risk significant (Category 1) and l are included within the LC0 based upon this l consideration.
| |
| l 1
| |
| 1 (continued)
| |
| Crystal River Unit 3 8 3.3-131 Revision No. 11
| |
| | |
| l PAM Instrumentation J B 3.3.17 ,
| |
| ;m :
| |
| BASES $ \ ;
| |
| LCO . !
| |
| Containment Isolation Valve Position
| |
| : 10. !
| |
| Containment. Isolation Valve (CIV) position indication instrumentation is provided in order for the operator. 1 to verify that RB penetrations are isolated, as.
| |
| required, following an accident or transient. In this t way, the Containment is verified to be functioning as analyzed and as tested (10 CFR 50, Appendix J). The CIV indication consists of open/ closed matrix lights located on the ES Section of the main control board, j CR-3 does not provide ~ position indication for manual CIVs or CIVs utilizing a passive design (check l valves). In the case of manual valves, these valve types are acceptable alternatives to automatic valves for the purposes of providing containment isolation and require no position indication since they are administratively maintained in.the isolated position, i Position indication for check valves is specifically '
| |
| excluded by Table 3 of Regulatory Guide 1.97.
| |
| -t The LCO requires ~two position. indications per J penetration rather than two indications per valve (for i those penetrations provided with indication and the' i applicable valve configuration). In other words, the LCO requires one position indicator for each of two active CIVs with control room indication. Strictly '
| |
| speaking, this is an exception from Category I redundancy requirements. However, this is considered acceptable since redundancy is provided on a per-penetration basis. For penetrations having only one CIV having control room indication, only that one indication is required by this LCO.
| |
| A Note has been added to indicate that position .;
| |
| indication is not required for isolation valves whose !
| |
| associated penetration is isolated by at least one closed and deactivated automatic valve, closed manual valve, blind' flange, or check valve with flow through the valve secured. This allowance is consistent with !
| |
| the previous discussion on why position indication was l excluded for manual valves.
| |
| (continued)
| |
| -Crystal River Unit 3 B 3.3-132 Revision No. 11 q i.
| |
| _m -
| |
| | |
| 4 PAM instrument 2 ton a B 3.3.17
| |
| (
| |
| BASES LCO 10. Containment Isolation Valve Position (continued) 4 These instruments are not assumed to provide information required by the operator to take a j mitigation action specified in the safety analysis.
| |
| As such, they are not Type A variables. However, the monitors are deemed risk significant (Category 1) and
| |
| ; are included within the LC0 based upon this consideration.
| |
| ]
| |
| : 11. Containment Area Radiation (Hiah Ranae)
| |
| Containment Area Radiation (High Range)
| |
| ? instrumentation is provided to monitor the potential i for significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans.
| |
| : Two channels of indication, each having a range of I
| |
| ; to IE8 Rad /hr. are provided in the control room with 3
| |
| one channel recorded. These instruments are not assumed to provide information required by the ,
| |
| operator to take a mitigation action specified in the i accident analysis. As such, they are not Type A j variables. However, the monitors are deemed risk j significant (Category 1) and are included within the
| |
| : LC0 based upon this consideration.
| |
| : 12. Containment Hydroaen Concentration ,
| |
| Containment Hydrogen Concentration instrumentation is j provided to detect high hydrogen concentration conditions that represent a potential for containcent i
| |
| breach. The operator is expected to initiate hydrogen i
| |
| control actions based upon indication provided by this instrument. These include hydrogen purge or recombiner initiation when hydrogen concentration reaches or exceeds the 4.1 volume percent flammability limit for hydrogen. This variable is also important 4
| |
| in verifying the adequacy of mitigating actions since
| |
| ; hydrogen concentration is not expected to approach i- flammability limits for any Design Basis Accident.
| |
| I (continued)
| |
| Crystal River Unit 3 B 3.3-133 Revision No. 11 1
| |
| | |
| - . -. - - - .- -.~_- . . - . - -
| |
| PAM Instrumentation
| |
| ; 8 3.3.17 8
| |
| BASES LC0 12. Containment Hydrooen Concentration (continued)
| |
| Two channels of indication, each covering a range of 0
| |
| 'to 10% hydrogen concentration are provided in the EFIC Room. Both channels are recorded in the EFIC room as i well. These channels are not normally energized and j thus are not subject to the CHANNEL CHECK requirement
| |
| ; of SR 3.3.17.1.
| |
| J i These instruments are not assumed to provide information required by the operator to take a mitigation action specified in the accident analysis.
| |
| As such, they are not Type A variables. The basis for
| |
| ; this statement is that in order to generate bulk 1 b:frogen concentrations which meet or exceed the i flammability limit, core damage in excess of that allowed by 10 CFR 50.46 must occur. However, this is
| |
| .' precluded by all other accident analysis. Thus, although the plant is designed to be capable of performing this function, it is not a requirement of the accident analysis. Be that as it may, the monitors are deemed risk significant (Category 1) and are included within the LC0 based upon this I consideration.
| |
| : 13. Pressurizer level Pressurizer level is indicated to provide information on proper operation of the pressurizer for a variety e of anticipated transients. These include decreasing i feedwater temperature, excessive main feedwater flow, decreasing steam flow, small steam leaks, loss-of-offsite power (and subsequent natural circulation 4
| |
| ensured by pressurizer heater operation), loss of condenser vacuum, as well as several others. For
| |
| ; these events, pressurizer level is expected to remain on-scale for the installed indication.
| |
| For severe transients or accidents such as a steam line break, steam generator tube rupture, and many I
| |
| 1 4
| |
| (continued) 4 Crystal River Unit 3 B 3.3-134 Revision No. 11 l
| |
| | |
| I 1
| |
| i PAM Instrumentation 8 3.3.17 l 1
| |
| l BASES l
| |
| LC0 13. Pressurizer level (continued) I small break LOCAs, the pressurizer will void. For the ,
| |
| case of a loss of main feedwater, the pressurizer could potentially be made water-solid. This is undesirable in that RCS pressure control is degraded
| |
| ~
| |
| and the potential for passing liquid through the pressurizer safety valves is increased. Studies have shown the safeties have a higher potential to fail to re-seat (creating an unisolable LOCA) if this condition were to occur. l Two channels of pressurizer level, each covering a range of 0 to 320 inches, are indicated and recorded in the control room. These instruments are not i assumed to provide information required by the operator to take a mitigation action specified in the l safety analysis. As such, they are not Type A 1 variables. However, the monitors are deemed risk significant (Category 1) and are included within the LC0 based upon this consideration.
| |
| 14,15. Steam Generator Water level (Start-up Ranae and 00eratino Ranqe The CR-3 Type A/ Category 1 indication of steam generator level is the startup range and operating range EFIC level instrumentation. The combined instrument ranges cover a span of 6 to 394 inches above the lower tubesheet. The rueasured low range differential pressure is displayed in inches of water. ;
| |
| The low range indicates a range of 0 to 150 inches, l where 0 inches indicates an actual level of 6 inches above the lower tubesheet. The high range steam generator level instrumentation indicates a span of 0 to 100%, where 0% corresponds to a 102 inch actual level above the lower tubesheet. Redundant monitoring capability is provided by two channels of each range of instrumentation per OTSG.
| |
| The level signals are displayed on control room indicators. The steam generator level signals are calculated from differential pressure signals which are pressure compensated by a module in the EFIC (continued) 8 3.3-135 Revision No. 11 Crystal River Unit 3
| |
| | |
| .7 PAM Instrumentation B 3.3.17 BASES f.
| |
| LCO 14,15. Steam Generator Water Level (Start-un Ranae and Doeratina Ranae (continued)
| |
| System cabinets. Compensation is based on the densities of the water and steam assuming the OTSGs are normally operating at saturation. Each operating range level transmitter also inputs to a recorder in i the contra' room. Since operator action is based on '
| |
| the control room indication, the LC0 deals specifically with this portion of the instrument ,
| |
| string.
| |
| : 16. Steam Generator Pressure Steam generator pressure is measured at the inlet of each steam line in each OTSG. Redundant monitoring capability is provided by two pressure transmitters !
| |
| per OT!G. Each pressure transmitter provides an input signal to pressure indicators and a recorder in the l control room. The operator selects one of the two _
| |
| pressure signals as input to the Integrated Controls (
| |
| System (ICS). The control room indication of 0TSG pressure is one of the primary indications used by the ~
| |
| operator during an accident. Therefore, the LC0 deals i specifically with the control room indication portion :
| |
| of the OTSG pressure instrument string. The range of '
| |
| the indication is 0 to 1200 psig.
| |
| OTSG pressure decreases rapidly during a design basis steam line break accident. This rapid decrease in pressure is a positive indication of a breach in the secondary system pressure boundary. In order to minimize the primary system coo'idown caused by the decreasing secondary system pressure, feedwater flow to the affected 0TSG must be terminated. OTSG pressure is considered a Type A variable because it is the primary indication used by the operator to identify and isolate the affected OTSG. In addition, OTSG pressure is a key parameter c:ed by the operator to evaluate primary-to-secondary heat transfer. For example, the operator may use this indication to control the primary system cooldown following a steam generator tube rupture or a small break loss of coolant accident (LOCA).
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-136 Revision No. 11
| |
| | |
| - . _ . . . . . . -~ _- . -. . .. .- .- - . -
| |
| l t
| |
| PAM Instrumentation B 3.3.17 i BASES LCO 17. Emeraency Feedwater Tank _Lgvg].
| |
| (continued)
| |
| The dedicated emergency feedwater (EFW) tank provides i the assured, safety grade water supply for the 4 Emergency Feedwater System. The EFW tank inventory is
| |
| ; monitored and displayed by 0 to 38 feet control room level indications. The control room indicators and alarms are considered the primary indication used by the operator,. Therefore, the LC0 deals specifically i with this portion of the instrument string.
| |
| q The design basis accidents which require emergency feedwater are those in which the main feedwater supply and/or the electrical supply to the vital feedwater auxiliaries has been lost, e.g., a feedwater line break or a loss of offsite power. In the event of such a loss of feedwater, the EFW tank is the initial source of water for the EFW System. As the EFW tank is depleted, manual operator action is necessary to replenish the EFW tank or to realign the suction to the EFW pumps. Since tank level is required by the operator for manual actions following an event, it has been included in this LCO.
| |
| : 18. Core Exit Temoerature (Backuo)
| |
| The core exit thermocouples (CETs) provide an indication of the reactor coolant temperature as it exits the active region of the core. The accident monitoring instrumentation provides a display of core exit temperature over a range of 0 to 2500*F. The display consists of 16 separate temperature measurements from 16 CETs, four from each quadrant.
| |
| Each of these 16 core exit temperature measurements is continuously recorded in the control room on three separate recorders. Since the control room display l is the primary indication used by the operator, this LC0 deals specifically with this portion of the instrument string.
| |
| The CETs are considered the primary indication of the reactor coolant temperature. Core exit temperature is included in this LCO because the operator uses this indication to monitor the cooldown of the RCS (continued)
| |
| Crystal River Unit 3 B 3.3-137 Revision No. 11
| |
| | |
| ,I PAM Instrumentation
| |
| , B 3.3.17 4
| |
| r' BASES t LCO 18. Core Exit Temperature (Backuol (continued) f, following a steam generator tube rupture or small i
| |
| break LOCA. Operator actions to maintain a controlled ,
| |
| cooldown, such as adjusting OTSG 1evel or pressure, would be prompted by this indication. In addition, the core exit thermocouples provide input to the _
| |
| ; subcooling margin monitor, which is a Type A variable.
| |
| 3 -
| |
| The subcooling margin monitor takes the average of the five highest CETs for each of the ICCM trains. Two
| |
| ; channels ensure that a single failure will not disable the ability to determine the representative core exit l temperature.
| |
| i
| |
| : 19. Emeraency Feedwater Flow :
| |
| EFW Flow instrumentation is provided to monitor
| |
| ; operation of decay heat removal via the OTSGs. The EFW injection flow to each OTSG (2 channels per OTSG, one associated with each EFW injection line) is determined from a differential pressure measurement (
| |
| calibrated to a span of 0 gpm to 1000 gpm. Each l differential pressure transmitter provides an input to a control room indicator and the plant computer.
| |
| i EFW Flow is used by the operator to determine the need i to throttle flow during accident or transient i conditions to prevent the EFW pumps from operating in l runout' conditions or from causing excessive RCS
| |
| ! cooldown rates when low decay heat levels are present.
| |
| l- EFW Flow is also used by the operator to verify that
| |
| ; the EFW System is delivering the correct flow to each OTSG. However, the primary indication of this
| |
| : function is provided by OTSG level.
| |
| ! l These instruments are not assumed to provide information required by the operator to take a mitigation action specified in the safety analysis.
| |
| i As such, they are not Type A variables. However, the i
| |
| monitors are deemed risk significant (Category 1) and are included within the 1.C0 based upon this consideration.
| |
| I J
| |
| t i (continued)
| |
| Crystal River Unit 3 8 3.3-138 Revision No. 11 i
| |
| I
| |
| | |
| -. .- - . - - - . . - .. . - . . _ - = - .- . . - ..
| |
| l l
| |
| PAM Instrumentation B 3.3.17 l
| |
| BASES (continued) i l
| |
| APPLICABILITY The PAM instrumentation requirements are applicable in i MODES 1, 2, and 3. These variables are related to the I diagnosis and pre-planned actions required to mitigate l DBAs. The applicable DBAs are assumed to occur in MODES 1, 2, and 3. In MODES 4, 5, and 6, plant operating conditions are such that the likelihood of an event occurring that would require PAM instrumentation is low; therefore, PAM instrumentation is not required to be OPERABLE in these MODES.
| |
| ACTIONS The ACTIONS are modified by two Notes. Note 1 was added to I indicate the restrictions of LCO 3.0.4 are not applicable.
| |
| This exception allows entry into an applicable MODE while ;
| |
| relying on the ACTIONS even though the ACTIONS would i eventually require a shutdown. This exception is l acceptable due to the passive function of the instruments, the operator's ability to respond to an accident utilizing alternate instruments and methods, and the low probability of an event requiring these instruments.
| |
| Note Two was added to clarify the application of Completion Time rules to this Specification. The Conditions of this Specification are entered independently for each Function listed in Table 3.3.17-1. The Completion Time (s) of the inoperable channels of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.
| |
| Ad When one or more Functions have one required channel inoperable, the inoperable channel must be restored to OPERABLE status within 30 days. The 30 day Completion Tire is based on engineering judgment and a variety of considerations. These considerations include availability of the remaining OPERABLE channel, the passive nature cf the instrument (no critical automatio action is assumed to occur from these instruments), and t- low probability of an event requiring PAM instrumentation during this interval.
| |
| (continued) .
| |
| q I
| |
| Crystal River Unit 3 B 3.3-139 Revision No. 11 I
| |
| l
| |
| | |
| . - _ _ . _ . . . _ . - . . ~ _ . _ . _ _ _ _. _ _ _ _ _ _ . _ _ _ _
| |
| i i
| |
| PAM Instrumentation B 3.3.17 i
| |
| BASES !
| |
| l i l
| |
| ACTIONS Ad: (continued) 1 For penetrations having only one CIV having control room indication, Required Action A.1 is the applicable ACTION to enter when the single indication is determined to be inoperable. This practice is consistent with the philosophy used in the isolation design for these types of penetrations.
| |
| fL1 When a PAM instrumentation channel cannot be restored to OPERABLE status within 30 days, Required Action B.1 ,
| |
| specifies the action described in Specification 5.7.2.a be '
| |
| initiated immediately. This action requires a written report be submitted to the NRC. This report discusses the 4 results of the root cause evaluation of the inoperability I and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement since 1 alternative actions are identified and implemented before i loss of functional capability occurs. The immediate - 1 Completion Time ensures the requirements of I Specification S.7.2.a are initiated without delay, i
| |
| C .1 i
| |
| When one or more Functions have two required channels j inoperable (i.e., two channels inoperable in the same i Function), one channel in the Function must be restored to l OPERABLE status within 7 days. The Completion Time of 1 7 days is based on the low probability of an event requiring operator action from the PAM instrumentation and the availability of alternative means for obtaining the required information. Continuous operation with two required channels inoperable in a Function is not i acceptable because alternate diverse monitoring indications may not fully satisfy Regulatory Guide 1.97 qualification requirements applicable to the Category 1 instrumentation.
| |
| Therefore, requiring restoration of one channel of the Function to OPERABLE status minimizes the possibility that ,
| |
| the PAM Function will be in a degraded condition should an accident occur.
| |
| 1 (continued)
| |
| Crystal River Unit 3 8 3.3-140 Revision No. 11
| |
| | |
| PAM Instrumentation !
| |
| B 3.3.17 i
| |
| r BASES _
| |
| ACTIONS Q21 (continued) Required Action D.1 directs entry into the appropriate Condition referenced in Table 3.3.17-1. The applicable Condition referenced in the Table is function dependent.
| |
| Each time an inoperable channel has not met any Required Action and associated Completion Time of Condition C, Condition D is entered for that Function and the operator is directed to the appropriate subsequent Condition.
| |
| f.d if the Required Action and associated Completion Time of Conditions C is not met and Table 3.3.17-1 directs entry into Condition E, the plant must be placed in a MODE in which the requirements of this LC0 do not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and in MODE 4 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.1 Alternative means of monitoring containment area radiation and reactor vessel level are available and may be relied upon if the normal PAM channels cannot be restored to OPERABLE status within the associated Completion Time.
| |
| Based upon this capability, it is inappropriate to require plant shutdown in this condition. Rather, in conjunction with the alternate monitoring means, the Required Action specifies action be immediately initiated in accordance with Specification 5.7.2.a, "Special Reports," in the Administrative Controls section of the Technical Specifications. The report provided to the NRC should discuss the alternate means of monitoring, describe the degree to which the alternative 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 to OPERABLE status.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.3-141 Revision No. 11
| |
| | |
| PAM Instrumentation B 3.3.17 !
| |
| i ;
| |
| ; ' BASES ( (' , t ACTIONS LJ (continued)
| |
| In the case of reactor vessel level, Reference 4 ,
| |
| demonstrated that from a risk perspective, the appropriate :
| |
| Required Action was not to mandate a plant shutdown, but !
| |
| rather to follow the actions of Specification 5.7.2.a.
| |
| i SURVEILLANCE .t i As noted at the beginning of the SRs, the SRs apply REQUIREMENTS to each PAM instrumentation Function in Table 3.3.17-1, '!t except as noted SR 3.3.17.1 '
| |
| i Performance of the CHANNEL CHECK once every 31 days for each required instrumentation channel that is normally energized ensures that a gross failure of the 3 instrumentation has not occurred. A CHANNEL CHECK is a i comparison of the parameter-indicated on one channel with a i similar parameter on'other. channels. It is based on the ,
| |
| assumption that instrument channels monitoring the same -
| |
| parameter should read approximately the same value. {' i Significant. deviations between.the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious.
| |
| Acceptance criteria are determined by the plant staff, and are presented in the Surveillance Procedures. The criterir. >
| |
| may consider, but is not limited to, channel instrument ,,
| |
| uncertainties,-including indication and readability. If a ;
| |
| channel is outside the acceptance criteria, it may be an indication that the sensor or the signal processing equipment has excessively drifted. If the channels are within the acceptance criteria, it is an indication that the channels are OPERABLE. If the channels are normally off-scale when the Surveillance is performed, the CHANNEL CHECK will only verify that they are off-scale in the same direction. Off-scale low current loop channels are verified to be reading at the bottom of the range and not failed downscale.
| |
| The Frequency is based on operating experience that demonstrates channel failure is an uncommon event.
| |
| (continued) '_
| |
| Crystal' River Unit 3 B 3.3-142 Revision No. 11
| |
| | |
| i PAM Instrumentation B 3.3.17 l
| |
| BASES i
| |
| l l
| |
| l SURVEILLANCE SR 3.3.17.1 (continued) ;
| |
| REQUIREMENTS l A note to the Surveillance excludes the performance of a CHANNEL CHECK on Function 4. FPC requested, and was granted, exception from performing a CHANNEL CHECK on this instrumentation as part of Amendment 124, dated October 17, 1989. The basis for not performing this SR is based on the ;
| |
| design of the system. The system utilizes differential l pressure (dp) measurements across vertical elevations of l the hot leg and the reactor vessel when the RCPs are tripped. Performance of the SR with the RCPs in operation provides no meaningful information, such that a CHANNEL CHECK of this Function is not required.
| |
| SR 3.3.17.2 CHANNEL CALIBRATION is a complete check of the instrument channel, including the sensor, to verify the channel responds to the measured parameter (s) within the necessary range and accuracy.
| |
| 1 For the Containment Area Radiation instrumentation, a l CHANNEL CALIBRATION consists of an electronic calibration l of the channel, not including the detector, for range j decades above 10 R/hr. The calibration also provides a one '
| |
| point check of the detector below 10 R/hr using a gamma test source (Reference NUREG 0737, Table II.F.1-3).
| |
| The 24 month Frequency is based on the results of a review of instrument drift data conducted in accordance with NRC Generic Letter 91-04. The Frequency for the hydrogen monitors is 18 months based on operating experience and was l originally selected to be consistent with the typical !
| |
| industry fuel cycle. I A Note clarifies that the neutron detectors are not required to be tested as part of the CHANNEL CALIBRATION.
| |
| Adjustment of the detectors is unnecessary because they are passive devices and operating experience has shown them to exhibit minimal drift. Furthermore, there is no adjustment that can be made to the detectors.
| |
| (continued)
| |
| Crystal River Unit 3 8 3.3-143 Revision No. 11
| |
| | |
| PAM fnstrumentation B 3.3.17 BASES (continued)- hl ,
| |
| REFERENCES 1. FSAR, Table 7-12.
| |
| : 2. Regulatory Guide 1.91, Revision 3.
| |
| 3 NUREG-0737, 1979. ;
| |
| : 4. 32-1177256-00, " Technical Basis for Reactor Vessel Level Indication System (RVLIS) Action Statement,"
| |
| April 10, 1990.
| |
| i
| |
| )
| |
| 1
| |
| -)
| |
| 'lj l
| |
| ~
| |
| Crystal River Unit 3 8 3.3-144 Revision No. 11
| |
| | |
| Remote Shutdown System B 3.3.18 ,
| |
| l B 3.3 INSTRUMENTATION ,
| |
| 8 3.3.18 Remote Shutdown System BASES J BACKGROUND The Remote Shutdown System provides the control room operator with sufficient instrumentation to place and maintain the plant in a safe shutd'wn o condition from outside the control room. This capability is necessary to protect against the possibility that the control room becomes inaccessible. A safo shutdown' condition is defined as MODE 3. With the plant in MODE 3, the Emergency Feedwater (EFW) System and the main steam safety valves or the atmospheric dump valves can be used to remove core docay heat and meet all safety requirements. The long term supply
| |
| - of EFW allows extended operation in MODE 3. .
| |
| In the event that the control room becomes inaccessible, the operators can establish control at the remote shutdown panel and place and maintain the plant in MODE 3. Not all controls and necessary transfer switches are located at the
| |
| ' remote shutdown panel. Some controls and transfer switches will have to be operated locally at the switchgear, motor control panels, or other local stations.
| |
| The OPERABILITY of the Remote Shutdown System control and instrumentation Functions ensures that there is sufficient information available on selected plant parameters to place and maintain the plant in MODE 3 should the control room become inaccessible.
| |
| APPLICABLE The Remote Shutdown System is required to provide SAFETY ANALYSES equipment at appropriate locations outside the control room with a capability to promptly shut down and maintain the unit in a safe condition in MODE 3.
| |
| The design basis for the CR-3 Remote Shutdown System is 10 CFR 50, Appendix A, GDC 19 and 10 CFR 50, Appendix R, Section L, (Ref. 1 and 2). However, the licensing basis for -
| |
| this LC0 is limited to the manner with which FPC meets the intent of GDC 19 (i.e., FSAR Section 1.4, Criterion 11).
| |
| I l
| |
| (continued) l l
| |
| Crystal River Unit 3 8 3.3-145 Revision No. 7 '
| |
| l l
| |
| | |
| i Remote Shutdown System B 3.3.18 BASES q
| |
| APPLICABLE The Remote Shutdown System was determined by the NRC to be SAFETY ANALYSES a risk significant item re (continued) Technical Specifications. quired to be retained in the I
| |
| 1 LCO The Remote Shutdown System LCO provides the requirements for the OPERABILITY of the' indication instrumentation necessary to place and maintain the plant in MODE 3 from a location other than the control room. The instrumentation required are listed in Table 3.3.18-1 in the accompanying LCO.
| |
| The instrumentation are those required for:
| |
| Core Reactivity Control; RCS Pressure Control; I RCS Temperature Control (Decay Heat Removal);
| |
| RCS' Inventory Control; and Support systems for the above Functions.
| |
| a A Function of a Remote Shutdown System is OPERABLE if all instrument channels needed to support the Function are OPERABLE. Functionality of the control functions supported by the instrumentation included in this Specification is addressed outside Technical Specifications.
| |
| The Remote Shutdown System instruments covered by this LC0 do not need to be energized to be. considered OPERABLE. This LCO is intended to ensure the Remote Shutdown System instruments will be OPERABLE if plant conditions require that the Remote Shutdown System be placed in operation.
| |
| APPLICABILITY The Remote Shutdown System LC0 is applicable in MODES 1, 2, j
| |
| and 3 so that the plant can be placed and maintained in MODE 3 for an extended period of time from a location other than the control room.
| |
| This LC0 is not applicable in MODE 4, 5, or 5. In these
| |
| . MODES, the plant is initially subcritical and in a condition
| |
| { of reduced RCS energy. Under these conditions, considerable (continued) 4 Crystal River Unit 3 B 3.3-146 Revision No. 7 1
| |
| | |
| Remote Shutdown System B 3.3.18 BASES APPLICABILITY time is available to restore necessary instrument (continued) Functions if it'becomes necessary to abandon the control room.
| |
| ACTIONS The ACTIONS are modified by two Notes. Note 1 was added to indicate the restrictions of LC0 3.0.4 are not applicable.
| |
| This exception allows entry into an applicable MODE while relying on the ACTIONS, even though the ACTIONS may eventually require a unit shutdown. This exception is
| |
| ; acceptable due to the low probability of an event requiring these instruments.
| |
| Note 2 was added to clarify the application of Completion Time rules to this Specification. The conditions of the Specification may be entered independently'for each Function listed in Table 3.3.18-1. The Completion Time (s) of the inoperable channel (s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.
| |
| , A1 Condition A addresses the situation where one or more r.equired Functions listed in Table 3.3.18-1 of the Remote Shutdown System are inoperable. .
| |
| With one or more Remote Shutdown System instrumentation Functions inoperable, the Function must be restored to OPERABLE status within 30 days. The Completion Time is based on operating experience and takes into account other indication available to provide the required information, and the low probability of an event that would require evacuation of the control room.
| |
| B.1 and B.2 If Required Action A.1 cannot be met within the associated Completion Time, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and in MODE 4 within 12 hours. The allowed Completion Times are (continued)
| |
| Crystal River Unit 3 B 3.3-147 Revision No. 7
| |
| | |
| _ . . . . - -- - . -. _~ . .. _ - -
| |
| Remote Shutdown System B 3.3.18 i
| |
| BASES
| |
| -i ACTIONS B.1 and 8.2 (continued)
| |
| ) reasonable, based on operating-experience, to reach the '
| |
| required plant conditions from full power conditions in an orderly manner and without challenging plant systems. !
| |
| SURVEILLANCE SR 3.3.18.1 REQUIREMENTS Performance of the CHANNEL CHECK once every 31 day's for each required instruinentation channel that is normally energized ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is a comparison of the indicated i parameter to a similar parameter on other channels. It is j 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 of something even more serious. Acceptance .
| |
| criteria are determined by the plant staff and are presented in the Surveillance Procedure. The criteria may consider, __
| |
| but is not limited to, channel instrument uncertainties, .
| |
| including indication and readability. If the channel is outside the acceptance criteria, it may be an indication that the sensor or the signal processing equipment has excessively drifted. If the channels are within the 4
| |
| acceptance criteria, it is an indication that the channels I are OPERABLE. As specified in the Surveillance, a CHANNEL 4 CHECK is only required for th'se o channels that are normally i energized. If the channels are normally off-scale when the ;
| |
| Surveillance is performed, the CHANNEL CHECK will only verify that they are off-scale in the same direction.
| |
| , Off-scale low current loop channels are verified to be
| |
| , reading at the bottom of the range and not failed downscale.
| |
| I The Frequency is based on plant operating experience, which demonstrates that channel failure is an uncommon event.
| |
| 1 .
| |
| S 4
| |
| (continued) _
| |
| Crystal River Unit 3 8 3.3-148 Revision No. 7
| |
| | |
| Remote Shutdown System B 3.3.18 BASES SURVEILLANCE SR 3.3.18.2 REQUIREMENTS (continued) CHANNEL CALIBRATION is a complete check of the instrument loop and sensor. The SR verifies that the channel responds to the measured parameters within the necessary range and accuracy.
| |
| A Note clarifies that Function 1.a., " Reactor Trip Breaker (RTB) Position" is not required to have a CHANNEL CALIBRATION. This indication is mechanical in nature, and thus, not subject to a calibration.
| |
| The 24 month Frequency is based on the results of a review of instrument drift data conducted in accordance with NRC Generic Letter 91-04 and is justified by the assumption of a 30 month calibration interval in the determination of the magnitude of equipment drift.
| |
| REFERENCES 1. 10 CFR 50, Appendix A, GDC 19.
| |
| : 2. 10 CFR 50, Appendix R, Section L.
| |
| l l
| |
| i 1
| |
| i I
| |
| Crystal River Unit 3 B 3.3-149 Revision No. 7
| |
| | |
| RCS Operational LEAKAGE B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)
| |
| B 3.4.12 RCS Operational LEAKAGE BASES BACKGROUND During the life of the plant, the joint and valve interfaces contained in the RCS can produce varying amounts of reactor co.olant LEAKAGE, through either normal operational wear or
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| . mechanical det:erioration. The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do ;
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| not compromise safety. This LC0 specifies the types and ;
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| i amounts of LEAKAGE. l l
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| 10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting and,.to the extent practical, identifying the source of reactor coolant LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable methods for selecting leakage 4
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| detection systems. OPERABILITY of the leakage detection systems is addressed in LCO 3.4.14, "RCS Leakage Detection Instrumentation." j The safety significance of RCS LEAKAGE varies widely depending on its sour ~ce, rate, and duration. Therefore, detecting, monitoring, and quantifying reactor coolant LEAKAGE is critical. Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur.
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| A limited amount of leakage inside containment is expected
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| * 4 from auxiliary systems that cannot be made 100% leaktight. !
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| Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.
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| APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses SAFETY ANALYSES do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for a LOCA in that the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes 1 gpm primary to secondary LEAKAGE as the initial condition.
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| (continued)
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| Crystal River Unit 3 B 3.4-53 Revis;on No. 10
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| RCS Operational LEAKAGE B 3.4.12 BASES '"
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| APPLICABLE The FSAR (Ref. 3) analysis for (SGTR) assumes the SAFETY ANALYSES contaminated secondary fluid i: only briefly released via (continued) safety valves and the majority is steamed to the condenser.
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| The I gpm primary to secondary LEAKAGE is relatively inconsequential in terms of offsite dose.
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| The FSAR steam line break (SLB) analysis (Ref. 4) is more
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| , :. limiting for site radiation releases. The safety analysis for the SLB accident assumes 1 gpm primary to secondary LEAKAGE *in one generator as an initial condition. The dose .
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| consequences resulting from the SLB accident meet the acceptance criteria defined in 10 CFR 100.
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| RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement.
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| LC0 RCS operational LEAKAGE shall be limited to:
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| : a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this i type is unacceptable as the leak itself could cause '
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| further deterioration, resulting in higher LEAKAGE.
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| Violation of this LC0 could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.
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| : b. Unidentified LEAKAGE .._
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| One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment atmosphere and sump level monitoring equipment can detect within a reasonable time period.
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| Violation of this LC0 could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary. ,
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| : c. Identified LEAKAGE ,
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| . Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the detection of unidentified (continued)
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| Crystal River Unit 3 B 3.4-54 Revision No. 10 i
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| j
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| RCS Operational LEAKAGE {
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| B 3.4.12
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| , BASES l
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| ;- LCO c. Identified LEAKAGE (continued)
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| LEAKAGE and is well within the capability of the RCS .
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| l makeup' system. Identified LEAKAGE includes LEAKAGE to ,
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| the containment from specifically known and located i sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE).
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| Violation of this LC0 could result in continued :
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| degradat{onofacomponentorsystem.
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| : d. Primary to Secondary LEAKAGE throuah All Steam Generators (OTSGs)
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| This LEAXAGE limit complements the statistical analysis performed as the basis for the disposition strategy for first span intergranular Attack (IGA) i eddy current indications. The statistical analysis '
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| demonstrates low probability of LEAKAGE from first span IGA indications during the operating cycle. This reduced LEAKAGE limit is intended to provide additional assurance that if primary to secondary LEAKAGE were to occur, it will be detected, and the plant shutdown in a timely manner. Primary to secondary LEAKAGE must be included in the total * '
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| allowable limit for identified LEAKAGE.
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| Two OTSGs are also required to be '
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| KABLE. This j requirement is met by satisfying tne augmented i inservice inspection requirements of the Steam l Generator Tube Surveillance Program (Specification 5.6.2.10).
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| . 1 (continued)
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| Crystal River Unit 3 B 3.4-55 Revision No. 10 i
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| RCS Operational LEAKAGE B 3.4.12 BASES f I l
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| l APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE or an event that challenges OTSG tube integrity is greatest ;
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| since the RCS is pressurized. In MODES 5 and 6, LEAKAGE '
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| limits and 0TSG OPERABILITY are not required because the !
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| reactor coolant pressure is far lower, resulting in lower I stresses and reduced potentials for LEAKAGE or failure. j LQ0 3.4.13, "RCS Pressure Isolation Valve (PIV) Leakage,"
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| me:sures leakage through .each individual PIV and can impact th^is LCO. Of the two PIVs in series in each line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leaktight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the determination of allowable identified LEAKAGE. .
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| O e
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| G 1 l
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| (continued)
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| Crystal River Unit 3 B 3.4-55A Revision No. 10 1
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| RCS Operational LEAKAGE B,3.4.12 BASES l
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| l I
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| )
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| THIS PAGE INTENTIONALLY LEFT BLANK l l
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| 1 (continued)
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| Crystal River Unit 3 8 3.4-558 Revision No. 10 t
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| 1 RCS Operational LEAKAGE B 3.4.12 BASES ACTIONS A_d If unidentified LEAKAGE, identified LEAKAGE, or primary to secondary LEAKAGE are in excess of the LC0 limits, the .
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| LEAKAGE must be reduced to within limits within 4 hours.
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| This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to -
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| within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the .
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| RCPB. -
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| B.1 and B.2 If any pressure boundary LEAKAGE exists or if unidentified, identified, or primary to secondary LEAKAGE cannot be reduced to within limits within 4 hours, the reactor must be placed in a lower pressure condition to reduce the severity of the LEAKAGE and its potential consequences. The reactor .
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| must be placed in MODE 3 within 6 hours and MODE 5 with.in 36 hours. This action reduces the LEAKAGE and also reduces the stresses that tend to degrade the pressure boundary. q The Completion Times allowed are reasonable, based .on operating experience, to reach the required conditions from '
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| full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses l acting on the RCPB are much lower and further deterioration is much less likely.
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| l SURVEILLANCE SR 3.4.12.1 l REQUIREMENTS Verifying RCS LEAKAGE within the LC0 limits ensures that the
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| , integrity of the RCPB~is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.
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| Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. Primary to secondary LEAKAGE is also measured by performance of an RCS water inventory balance in conjunction with effluent monitoring within the secondary steam and condensate systems.
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| (continued)
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| Crystal River Unit 3 B 3.4-56 Revision No. 10
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| RCS Operational LEAKAGE
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| , B 3.4.12 BASES ACTIONS AJ l
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| If unidentified LEAKAGE, identified LEAKAGE, or primary to secondary LEAKAGE are in excess of the LCO limits, the i
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| LEAKAGE must be reduced to within limits within 4 hours.
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| This Completion Time allows time to verify leakage rates and i either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB. -
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| B.1 and 8.2 ,
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| If any pressure boundary LEAKAGE exists or if unidentified, identified, or primary to secondary LEAKAGE cannot be '
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| reduced to within limits within 4 hours, the reactor must be placed in a lower pressure condition to reduce the severity of the LEAKAGE and its potential consequences. The reactor .
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| must be placed in MODE 3 within 6 hours and MODE 5 with.in 36 hours. This action reduces the LEAKAGE and also reduces the strasses that tend to degrade the pressure boundary. ;
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| The Completion Times allowed are reasonable, based .on operating experience, to reach the required conditions from full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower and further deterioration is much.less likely.
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| SURVEILLANCE SR 3.4.12.1 REQUIREMENTS Verifying RCS LEAKAGE within the LCO limits ensures that the
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| . integrity of the RCPB'is maintained. Pressure boundary - i LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.
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| Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. Primary to secondary LEAKAGE is also measured by performance of an RCS water inventory balance in conjunction with effluent i monitoring within the secondary steam and condensate systems.
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| (continued)
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| Crystal River Unit 3 B 3.4-56 Revision No. 10
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| RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1 (continued)
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| REQUIREMENTS The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating temperature and pressure. The test must be performed prior to entry into MODE 2 if it has not been performed within the past 72 hours. This surveillance is not required to be per. formed for entry into MODE 4 or MODE 3 or for non-steady state conditions in MODE 3, but must be performed in MODE 3 if 12 hours of steady state operation are achieved. If the test is not performed prior to all other requirements for entry into MODE 2 being satisfied, entry into MODE 2 must be delayed until steady state .
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| operation is established and the requirements of SR 3.0.4 are satisfied.
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| Steady state operation is required to perform a meaningful water inventory balance; calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP pump seal injection and return flows. -
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| The 72 hour Frequency is reasonable to trend LEAKAGE and I recognizes the importance of early leakage detection in the prevention of accidents.
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| SR 3.4.12.2
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| ~
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| This SR provides the means necessary to determine OTSG OPERABILITY in an operational MODE. The requirement to demonstrate OTSG tube integrity in accordance with the Steam Generator Tube Surveillance Program emphasizes the importance of 0TSG tube integrity, even though this Surveillance cannot be performed at normal operating conditions.
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| REFERENCES ,1. 10 CFR 50, Appendix A, GDC 30.
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| : 2. Regulatory Guide 1.45, May 1973.
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| : 3. FSAR, Section 14.2.2.2.
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| . 4. FSAR, Section 14.2.2.1.
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| I Crystal River Unit 3 8 3.4-57 Revision No. 10 ,
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| l
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| ECCS-Operating B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)
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| B 3.5.2 ECCS-Operating BASES BACKGROUND The function of the ECCS is to provide core cooling to ensure that the reactor core is protected after any of the ,
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| following accidents:
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| : 1. Loss of coolant accident (LOCA); i l
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| : 2. Steam generator tube rupture (SGTR); and
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| : 3. Steam line break (SLB).
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| There are two modes of ECCS operation: injection and ,
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| recirculation. In the injection phase, all injection is '
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| initially added to the Reactor Coolant System (RCS) from the borated water storage tank (BWST). This injection flow is added via the RCS cold legs and core flood nozzles to the reactor vessel. After the BWST has been depleted to s 15 feet but > 7 feet, the ECCS recirculation phase is entered as the ECCS suction is manually transferred to the reactor building emergency sump. l Two redundant, 100% capacity trains are provided. Each train consists of high pressure injection (HPI) and low pressure injection (LPI) subsystems. In MODES 1, 2, and 3, both trains must be OPERABLE. This ensures that 100% of the l core cooling requirements can be provided even in the event ,
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| of a single active failure.
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| A suction header supplies water from the BWST or the reactor building emergency sump to the ECCS pumps. Separate piping supplies each train. Each HPI subsystem discharges into each of the four RCS cold legs between the reactor coolant pump and the reactor vessel. Each LPI subsystem discharges into its associated core flood nozzle on the reactor vessel and discharges into the vessel downcomer area. Control valves are set to balance the HPI flow to the RCS. This i flow balance directs sufficient flow to the core to meet the l analysis assumptions following a small break LOCA in one of ;
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| the RCS cold legs near an HPI nozzle. I The HPI pumps are capable of discharging to the RCS at an RCS pressure above the opening setpoint of the pressurizer (continued)
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| Crystal River Unit 3 B 3.5-9 Revision No. 6
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| - - ~ - - - - - - - _ . - - - - - . _ _ - - _ _ - - -
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| ECCS-Operating 8 3.5.2 4
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| BASES 4
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| : BACKGROUND safety valves. The LPI pumps are capable of discharging to (continued) the RCS at an RCS pressure of approximately 200 psia. When the BWST has been nearly emptied, the suction for the LPI pumps is manually transferred to the reactor building emergency sump. The HPI pumps cannot take suction directly from the sump. If HPI is still needed, a cross connect fro-the discharge side of the LPI pump to the suction of the HPI pumps would be opened. This is known as " piggy backing" HPI to LPI, and enables continued HPI to the RCS, if needed, after the BWST is emptied to the switchover point. l In the long term cooling period, flow paths in the LPI System can be established to preclude the possibility of boric acid in the core region reaching an unacceptably high concentration. One flow path is from the hot leg through the decay heat suction line and then in a reverse direction through the reactor building emergency sump suction line into the sump. The other flow path uses the gaps between the hot leg nozzles and the reactor vessel. These gaps provide a flow path between the outlet annulus and the inlet nozzle /downcomer region of the reactor vessel. Either flow path is capable of providing the required flow rates to ensure boron precipitation is not a concern.
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| HPI also functions to supply borated water to the reactor core following increased heat removal events, such as large SLBs.
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| During low temperature conditions in the RCS, limitations I are placed on the maximum number of HPI/ Makeup pumps that l are capable of injecting into the RCS. These limitations are part of the plants Low Temperature Overpressure Protection (LTOP) administrative controls. 1 During a large break LOCA, RCS pressure will decrease to
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| < 200 psia in < 20 seconds. The ECCS is. actuated upon-receipt of an Engineered Safeguards Actuation System (ESAS) signal. The actuation of safeguard loads is accomplished in a programmed time sequence. If offsite power is available, the safeguard loads start immediately (in the programmed sequence). If offsite power is not available, the engineered safety feature (ESF) buses shed normal operating loads and are connected to the diesel generators. Safeguard loads are then actuated in the programmed time sequence.
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| The time delay associated with diesel starting, sequenced loading, ard p starting determines the time required (continued)
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| Crystal River Unit-3 8 3.5-10 Revision No. 6
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| ! ECCS-Operating l
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| B 3.5.2 BASES-l BACKGROUND before pumped flow is available to the core following a (continued) LOCA. j The active ECCS components, along with the passive core flood tanks (CFTs) and the BWST covered in LC0 3.5.1, " Core :
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| Flood Tanks (CFTs)," and LCO 3.5.4. " Borated Water Storage j Tank (BWST)," provide the cooling water necessary to meet i 10 CFR 50.46 (Ref. 1).
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| l 1
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| ! 'PPLICABLE The LCO helps to ensure that the following acceptance SAFETY ANALYSES criteria for the ECCS, established by 10 CFR 50.46 (Ref. 1),
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| will be met following a LOCA:
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| : a. Maximum fuel element cladding temperature is s 2200*F; l
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| : b. Maximum cladding oxidation is s 0.17 times the total cladding thickness before oxidation; .
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| : c. Maximum hydrogen generation from a zirconium water reaction is s 0.01 times the hypothetical amount generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding i surrounding the plenum volume, were to react;
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| : d. Core is maintained in a coolable geometry; and
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| : e. Adequate long term core cooling capability is maintained.
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| I Both HPI and LPI subsystems are assumed to be OPERABLE in the large break LOCA analysis at full power (Ref. 2). This analysis establishes a minimum required flow for the HPI and LPl pumps, as well as the minimum required response time for their actuation. The HPI pump is credited in the small break LOCA analysis. This analysis establishes the flow and discharge head requirements at the design point for the HPI pump, The SGTR and SLB analyses also credit the HPI pump but are not limiting in their design.
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| The large break LOCA event with a coincident (with reactor trip) loss of offsite power and a single failure (disabling one ECCS train) establishes the majority of OPERABILITY requirements for the ECCS. During the blowdown phase of a l
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| (continued) i Crystal River Unit 3 8 3.5-11 Revision No. 6
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| ECCS-Operating B 3.5.2 BASES APPLICABLE LOCA, the RCS depressurizes as primary coolant is ejected SAFETY ANALYSIS through the break into the containment. The nuclear (continued) reaction is terminated either by moderator voiding during large breaks or CONTROL R00 assembly insertion for small breaks. Following depressurization, emergency cooling water is injected into the reactor vessel core flood nozzles, then flows into the downcomer, fills the lower plenum, and refloods the core.
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| The LC0 ensures that an ECCS train will deliver sufficient water to match decay heat boiloff rates soon enough to minimize core uncovery for a large break LOCA. It also ensures that the HPI pump will deliver sufficient water for a small break LOCA and provide sufficient boron to maintain the core subcritical following the small break LOCA or an SLB.
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| In the LOCA analyses, HPI and LPI are not credited until 35 seconds after actuation of the ESAS signal. This is based on a loss of offsite power and the associated time delays in startup and loading of the emergency diesel generator (EDG). Further, LPI flow is not credited until RCS pressure drops below the pump's shutoff head. For a large break LOCA, HPI is not credited at all. -
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| The ECCS trains satisfy Criterion 3 of the NRC Policy Statement.
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| LC0 In MODES I, 2, and 3, two independent (and redundant) ECCS trains are required to ensure that at least one is available, assuming a single active failure in the other train. For example, the design of the HPI injection valves (MUV-23, MUV-24, MUV-25, and MUV-26) allows power to the motor operators to be selected between a. normal or backup power supply. Powering one set of HPI valves from the alternate power supply eliminates the independence and aligns both trains of HPI valves to receive power from the same ES bus. In this condition, the system is still capable of mitigating an event, providing a concurrent single failure does not occur. Hence, the 72 hour ACTION addressing a loss of redundancy is appropriate.
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| (continued)
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| Crystal River Unit 3 8 3.5-12 Revision No. 6
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| ECCS-Operating 8 3.5.2 BASES LC0 Conversely, not all portions of the HPI System satisfy tne (continued) independence criteria discussed above. Specifically, the HPI System downstream of the HPI/ Makeup pumps is not separable into two distinct trains, and is therefore, not independent. This conclusion is based upon analysis which shows injection flow is required through a minimum of three (3) injection legs in the event of a postulated break in the HPI injection piping. When considering the impact of inoperabilities in this portion of the system, the same concept of maintaining single active failure protection must be applied. When components become inoperable, an assessment of the HPI systems ability to perform its safety function must be performed. If the system can continue to perform its safety function, without assuming a single active failure, then the 72 hour loss of redundancy ACTION is appropriate. If the inoperability renders the system, as 4
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| is, incapable of performing its safety function, without postulating a single active failure, then the plant is in a condition outside the safety analysis and must enter LC0 3.0.3 immediately.
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| In MODES 1, 2, and 3, an ECCS train consists of an HPI subsystem and an LPI subsystem. Each train includes the piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the BWST upon an ESAS signal and manually transferring suction to the reactor building emergency sump.
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| During an event requiring ECCS actuation, a flow path is provided to ensure an abundant supply of water from the EWST to the RCS via the HPI and LPI pumps and their respective discharge flow paths to each of the four cold leg injection nozzles and the reactor vessel. In the long term, this flow path may be manually transferred to take its supply from the reactor building emergency sump and to supply its flow to the RCS via two paths, as described in the Background section.
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| The flow path for each traia must maintain its designed degree of indepr.dence tc ensure that no single active failure can disable both ECCS trains.
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| l l
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| l (continued)
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| Crystal River Unit 3 8 3.5-13 Revision No. 6
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| ECCS-Operating B 3.5.2 BASES (continued)
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| , 1 APPLICABILITY In MODES 1, 2, and 3, the ECCS train OPERABILITY requirements for the limiting Design Basis Accident, a large break LOCA, are based on full power operation.
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| Although reduced power would not require the same level of performance, the accident analysis does not provide for reduced cooling requirements in the lower MODES. The HPI pump performance is based on the small break LOCA, which establishes the pump performance curve and is less dependent on power. MODES 2 and 3 requirements are bounded by'the MODE 1 analysis.
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| In MODES 5 and 6, plant conditions are such that the i probability of an event requiring ECCS injection is j extremely low. Core cooling requirements in MODE 5 are addressed by LC0 3.4.6, "RCS Loops-MODE 5, Loops Filled,"
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| and LC0 3.4.7, "RCS Loops-MODE 5, Loops Not Filled."
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| MODE 6 core cooling requirements are addressed by LCO 3.9.4,.
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| )
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| " Decay Heat Removal and Coolant Circulation-High Water Level," and LC0 3.9.5, " Decay Heat Removal and Coolant Circulation-Low Water Level."
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| l t
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| l i
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| (continued)
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| Crystal River Unit 3 8 3.5 14 Revision No. 6
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| ECCS-Operating 8 3.5.2 BASES (continued)
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| ACTIONS A_d With one or more ECCS trains inoperable and at least 100% of
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| .the flow equivalent to a single OPERABLE ECCS train available, the inoperable components must be returned to OPERABLE status within 72 hours. The 72 hour Completion Time is based on NRC recommendations -(Ref. 3) that are based on a risk evaluation and is a reasonable time for many repairs.
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| An ECCS train is inoperable if it is not capable of delivering the design flow to the RCS.
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| The LC0' requires the OPERABILITY of a number of independent subsystems. Due to the redundancy of trains and the q diversity of subsystems, the inoperability of one component in a train does not render the ECCS incapable of performing ,
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| 1 its function. Neither does the inoperability of two different components, each in a different train, necessarily result in a loss of function for the ECCS. The intent of l
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| this Condition is to maintain a combination of equipment i l such that the safety injection (SI) flow equivalent to 100% l i
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| of a single train remains available. This allows increased i flexibility in plant operations under circumstances when J i
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| components in opposite trains are inoperable.
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| An event accompanied by a loss of offsite power and the failure of an EDG can disable one ECCS train until power is restored. A reliability analysis (Ref. 3) has shown the l risk of having one full ECCS train inoperable to be sufficiently low to justify continued operation for <
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| 72 hours.
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| 4 With one or more components inoperable such that the flow equivalent to a single OPERABLE ECCS train is not available, the facility is in a condition outside the accident '
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| analyses. Therefore, LCO 3.0.3 must be immediately entered.
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| j This Condition does not apply to HPI subsystem components which are deactivated for the purposes of complying with Low Temperature Overpressure Protection (LT0P) administrative '
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| control commitments. With these components deactivated, the HPI subsystem is still considered OPERABLE based upon guidance in NRC Generic Letter 91-18. This guidance allows I
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| substitution of manual operator action for otherwise (continued)
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| Crystal River Unit 3 8 3.5-15 Revision No. 6 l
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| I l
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| ECCS-Operating-B 3.5.2 BASES a
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| ACTIONS automatic functions for the purposes of determining (continued) OPERABILITY. . The substitutions are limited and must be evaluated against the assumptions in'the accident analysis.
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| In the case of deactivating HPI for LTOP at RCS temperature 1 283*F, the components are available for injection following manual operator action to restore the system to OPERABLE status and this action can be accomplished within the time frame required to respond to the
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| -transient / accident.
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| B.1 and B.2 If the inoperable components cannot be-returned to OPERABLE status within the associated Completion Times, the plant must be placed in a MODE in which the LC0 does not apply.
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| To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and at least MODE 4 within 12 hours.
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| 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.
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| SURVEILLANCE SR 3.5.2.1 .
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| REQUIREMENTS 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. These valves include valves in the main flow paths and the first normally closed valve-in a branch line. There are several exceptions for valve position verification due to t,he low potential for these types of _ valves to be mispositioned. _ The valve types which are not verified as part of this SR include vent or drain valves (both inside and outside the RB), relief valves outside the RB, instrumentation valves (both inside and outside the RB), check valves (both inside and outside the RB), and sample line valves (inside and outside the RB). A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve will automatically reposition within the proper stroke time. This Surveillance does not require any testing or valve manipulation; rather, (continued)
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| Crystal River Unit 3 8 3.5-16 Revision No. 6 J
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| EG.S --Ope rat i ng
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| ? ?.5.2 BASES 4
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| SURVEllt.ANCE SR 3.5.LL (continued)
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| REQUIREMENTS it involves verification that those valves capable of being mispositioned are in the correct position. The 31 day Frequency is appropriate because the valves are operated under administrative control, and an inoperable valve position would only affect a single train. This Frequency has been shown to be acceptable through operating experience.
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| SR 3.5.2.2 Periodic surveillance testing of ECCS pumps to detect gross
| |
| : degradation caused by impeller structural damage or other hydraulic component problems is required by Section XI of the American Society of Mechanical Engineers (ASME) Code (Ref. 4). This type of testing may be accomplished by measuring the pump's developed head at only one point of the pump's characteristic curve and this point may be anywhere on the curve. This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance j assumed in the plant accident analysis. SRs are specified in the Inservice Testing Program, which encompasses
| |
| , Section XI of the ASME Code. Section XI of the ASME Code i provides the activities and Frequencies necessary to satisfy the req 0irements.
| |
| SR 3.5.2.3 and SR 3.5.2.4 a
| |
| - These SRs demonstrate that each automatic EC'CS valve that is I not locked, sealed, or otherwise secured in position, actuates to its required position on an actual or simulated ;
| |
| ESAS signal and that each ECCS pump starts on receipt of an actual or simulated ESAS signal. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The 24 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of j the equipment. The actuation logic is tested as part of the :
| |
| 4 ESAS testing, and equipment performance is monitored as part of the Inservice Testing Program.
| |
| i (continued)
| |
| . Crystal River Unit 3 8 3.5-17 Revision No. 6 4
| |
| | |
| 4 ECCS-Operating i
| |
| 8 3.5.2 BASES .
| |
| f l
| |
| SURVEILLANCE SR 3.5.2.5 REQUIREMENTS (continued) This Surveillance ensures that these valves are in the
| |
| ; proper position to prevent the HPI pump from exceeding its runout limit. This 24 month Frequency is acceptable based on consideration of the design reliability (and :onfirming operating experience) of the equipment.
| |
| SR 3.5.2.6 This Surveillance ensures that the flow controllers for the LPI throttle valves will automatically control the LPI train -
| |
| flow rate in the desired range and prevent LPI pump runout as RCS pressure decreases after a LOCA. The 24 month Frequency is acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.
| |
| L SR 3.5.2.7 Periodic inspections of the reactor building emergency sump suction inlet ensure that it is unrestricted and stays in proper operating condition. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and to preserve '
| |
| access to the location. This Frequency has been found to be sufficient to detect abnormal degradation and has been confirmed by operating experience.
| |
| . REFERENCES 1. 10 CFR 50.46.
| |
| I
| |
| : 2. FSAR, Section 6.1. !
| |
| l
| |
| : 3. NRC Memorandum to V. Stello, Jr., from R.L. Baer,
| |
| " Recommended Interim Revisions to LCOs for ECCS Components," December 1,1975.
| |
| : 4. American Society of Mechanical Engineers, Boiler and Pressure Vessel Code, Section XI, Inservice i Inspection, Article IWP-3000.
| |
| l Crystal River Unit 3 B 3.5-18 Revision No. 6
| |
| | |
| ECCS-Operating B 3.5.2 BASES I
| |
| l THIS PAGE INTENTIONALLY LEFT BLANK B 3.5-19 Revision No. 6 Crystal River Unit 3
| |
| | |
| Containment B 3.6.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1 Containment BASES BACKGROUND .The containment consists of the concrete reactor building !
| |
| (RB),._its steel liner, and the penetrations through this-structure. The structure is designed to.contain water and steam, as well as radioactive material that may be released from the reactor core following a-Design Basis Accident :
| |
| (DBA). Additionally, this structure provides shielding from I the fission products that may be.present in the containment atmosphere following accident conditions. ,
| |
| i The containment is a reinforced concrete structure with a cylindrical wall, a flat foundation mat, and a shallow dome roof. The cylinder wall is prestressed with a post '
| |
| tensioning system in the vertical and horizontal directions, l and the dome roof is prestressed using a three way post tensioning system. The inside surface of the containment has a carbon steel liner to ensure a high degree of leak-tightness during operating and accident conditions.
| |
| The concrete RB is required for- structural integrity of the containment under DBA conditions. The steel liner and its l penetrations establish the leakage limiting boundary of the containment. Maintaining the containment OPERABLE limits ,
| |
| the leskase of fission product radioactivity from the containment to the environment. SR 3.6.1.1 leakage rate i
| |
| requirements comply with 10 CFR 50, Appendix J (Ref.1), as I modified by approved exemptions.
| |
| The isolation devices for the penetrations in the containment boundary are a part of the containment leak tight barrier. To maintain this leak tight barrier:
| |
| : a. All penetrations _ required to be closed during accident conditions are either:
| |
| : 1. capable of being closed by an OPERABLE automatic containment isolation system, or I
| |
| : 2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their closed positions, except as provided in LC0 3.6.3, " Containment Isolation Valves";
| |
| (continued) 8 3.6 1 Revision No. I
| |
| : Crystal River Unit 3 s
| |
| i
| |
| | |
| 1 Containment B 3.6.1 BASES BACKGROUND b. Each air lock is OPERABLE, except as provided in (continued) LC0 3.6.2, ' Containment Air Locks". )
| |
| APPLICABLE The safety design basis for the containment is that the SAFETY ANALYSES containment must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.
| |
| l
| |
| < The DBAs that result in a challenge to containment from high pressures and temperatures are a loss of coolant accident (LOCA), a steam line break, and a rod ejection accident (REA) (Ref. 2). In addition, release of significant fission product radioactivity within containment can occur from a LOCA or REA. In the analyses of DBAs involving release of fission product radioactivity, it is assumed that the containment is OPERABLE so that the release to the i environment is controlled by the rate of containment '
| |
| leakage. The containment was designed with an allowable leakage rate of 0.25% of containment air weight per day (Ref. 3). This leakage rate, used in the evaluation of i offsite doses resulting from accidents, is defined in '
| |
| 10 CFR 50, Appendix J (Ref.1), as L,: the maximum -
| |
| allowable leakage rate at the calculated maximum peak ;
| |
| containment pressure (P.) resulting from the limiting DBA.
| |
| The allowable it.5ge rate represented by L, forms the basis for the acceptance criteria imposed on all containment leakage rate testing. L, is assumed to be 0.25% of containment air weight per day in the safety analysis at P, - 54.2 psig (Ref. 3). l The acceptance criteria applied to accidental. releases of radioactive material to the environment are given in terms of total radiation dose received by a hypothetical member of the general public who is assumed to remain at the exclusion area boundary for two hours following onset of the postulated fission product release. The limits established in 10 CFR 100 (Ref. 5) are a whole body dose of 25 Rem or a 300 Rem dose to the thyroid from iodine exposure.
| |
| The containment satisfies Criterion 3 of the NRC Policy Statement.
| |
| J (continued)
| |
| Crystal River Unit 3 6 3.6-2 Revision No. 1
| |
| | |
| Containment 8 3.6.1 BASES (continued)
| |
| Containment OPERABILITY f s maintained by limiting leakage to LC0 less than the acceptance criteria of 10 CFR 50, Appendix J (Ref. 1). Compliance with this LC0 will ensure a containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those I leakage rates assumed in the safety analysis.
| |
| Individual leakage rates specified for the containment air lock (LCO 3.6.2) and purge valves with resilient seals (LC0 3.6.3) are not specifically partleakage Therefore, of the acceptance rates exceeding criteria of SR 3.6.1.1.
| |
| these individual limits only result in the containment being inoperable when the total leakage exceeds the acceptance criteria of Appendix J.
| |
| In MODES 1, 2, 3, and 4, a DBA could cause a release of In MODES 5 and 6, APPLICABILITY radioactive material into containment.
| |
| the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.
| |
| Therefore, containment is not required to be The requirements for containment during OPERABLE in MODE 5.
| |
| MODE 6 are addressed in LCO 3.9.3, " Containment Penetrations."
| |
| ACTIONS A_d In the event containment is inoperable, containment must be The 1 hour restored to OPERABLE status within I hour.
| |
| Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining This time period containment during MODES 1, 2, 3, and 4.
| |
| also ensures the probability of an accident (requiring containment OPERABILITY) occurring during periods when containment is inoperable is minimal.
| |
| B.1 and 8.2 If containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this (continued) 8 3.6-3 Revision No. 1 Crystal River Unit 3
| |
| | |
| Containment 8 3.6.1 l BASES
| |
| _ +
| |
| ACTIONS B.1 and B.2 (continued) 6 hours and in MODE 5 within 36 hours. status, the The allowed Completion Times are reasonable, based on operating experience, to reach the required plant power conditions in an orderly manner an.d conditionswithout from full challenging plant systems.
| |
| SURVEILLANCE SR 3. 6.1. l_
| |
| REQUIREMENTS p Maintaining the containment OPERABLE requires compliance i with the visual examinations and leakage rate test
| |
| ; requirements by of 10 CFR 50, Appendix J (Ref.1), as modified approved exemptions.
| |
| Failure to meet air lock and purge i valve with resilient seal leakage limits for SR 3.6.2.1 and '
| |
| i 3.6.3.6 does not constitute a failure of this Surveillance unless the contribution from these penetrations causes i
| |
| : overall Type are Frequencies A, B, asand re C leakage to exceed limits. - SR approved exemptions. quired by Appendix J, as modified by
| |
| {
| |
| extensions) does not apply. Thus, SR 3.0.2 (which allows Frequency These periodic testing requirements verify that the containment leakage rate does i l4- ' '
| |
| not exceed the leakage rate assumed in the' safety analysis.
| |
| I l SR 3.6.1.2 i
| |
| ! This SR ensures that the structural integrity of the containment will be maintained in accordance with the provisions of the Containment Tendon Surveillance Program.
| |
| Testing and Frequency are consistent with the recommendations of NRC Regulatory Guide 1.35, Revision 3.
| |
| The' guidance in Regulatory Guide 1.35 should be followed in the event abnormal degradation of the containment tendons is detected. This includes testing additional tendons and submitting a Special Report to the NRC (Refer to- ;
| |
| Specification 5.7.2.b)'. The impact of large-scale tendon degradation should also be evaluated with respect to Containment OPERABILITY. In this context, containment i structural integrity is analogous to containment OPERABILITY.
| |
| I i
| |
| (continued)
| |
| Crystal River Unit 3 8 3.6 4 Revision No. 1
| |
| | |
| Containment B 3.6.1 BASES (continued)
| |
| REFERENCES 1. 10 CFR 50, Appendix J.
| |
| : 2. FSAR, Sections 14.2.2.
| |
| : 3. FSAR, Table 14-57.
| |
| : 4. Regulatory Guide 1.35, Rev.3,1990.
| |
| : 5. 10 CFR 100.
| |
| l l
| |
| l l
| |
| l l
| |
| B 3.6-5 Revision No. 1 Crystal River Unit 3
| |
| | |
| Containm'ent Air Locks B 3.6.2 i
| |
| B 3.6 CONTAINMENT SYSTEMS 8 3.6.2 Containment Air Locks ,
| |
| BASES BACKGROUND Containment air locks form part of the containment pressure boundary and provide a means for personnel access during all MODES of operation.
| |
| Each air lock is nominally a right circular cylinder,10 ft ,
| |
| in diameter, with a door at each end. The doors are interlocked to prevent simultaneous opening. During periods when containment is not required to be OPERABLE, the door interlock mechanism may be disabled, allowing both doors of :
| |
| an air lock to remain open for extended periods when frequent containment entry is necessary. Each air lock door has been designed and is tested to verify its ability to withstand a pressure in excess of the maximum expected pressure following a Design Basis Accident (DBA) in i containment. Therefore, closure of a single door supports ,
| |
| containment OPERABILITY. Each of the doors contain two gasketed seals and local leakage rate testing capability to '
| |
| ensure pressure integrity. To effect a leak tight seal, the air lock design uses pressure seated doors (i.e., an increase in containment internal pressure results in increased sealing force on each door).
| |
| Each personnel air lock door is provided with limit switches that provide control room indication of door position.
| |
| Additionally, control room indication is provided to alert the operator whenever an air lock door interlock mechanism is defeated.
| |
| The containment air locks form part of the containment pressure boundary. Their integrity and leak tightness is essential for maintaining the containment leakage rate within limit 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.
| |
| All leakage rate requirements are ir conformance with 10 CFR 50, Appendix J (Ref.1), as modified by approved exemptions.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.6-6 Revision No. I
| |
| | |
| Containment Air Locks B 3.6.2 BASES Montinued)'
| |
| APPLICAB The DBAs that result in a release of radioactive material within containment are a loss of coolant accident (LOCA), In a SAFETY ANALYSES steam line break, and a rod ejection accident (Ref. 2).
| |
| the analysis of each of these accidents, it is assumed that containment is OPERABLE so that release of fission products to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.25% of containment air weight per day This leakage rate is defined in 10 CFR 50, (Ref. 3). the maximum allowable Appendix J (Ref. 1), as L,:
| |
| containment leakage rate at the calculated maximum peak containment pressure (P,) following a DBA. This allowable leakage rate forms the basis for the acceptance criteria L, is imposed on the SRs associated with the air lock.
| |
| 0.25% of containment air weight per day and P, is 54.2 psig, l resulting from the limiting design basis LOCA.
| |
| The acceptance criteria applied to DBA releases of radioactive material to the environment are given in terms of total radiation dose received by a member of the general public who remains at the exclusion area boundary for two hours.following onset of the postulated fission product release. The limits established in 10 CFR 100 (Ref. 4) are a whole body dose of 25 Rem or a 300 Rem dose to the thyroid from iod'ne exposure.
| |
| The containment air locks satisfy Criterion 3 of the NRC Policy Statement.
| |
| l l
| |
| Each containment air lock forms part of the containment LCO pressure boundary. As a part of containment, the air lock '
| |
| safety function is related to control Thus, of the each containment air lock's leakage rate resulting from a DBA.
| |
| structural integrity and leak tightness are essential to the successful mitigation of such an event.
| |
| (continued) 8 3.6-7 Revision No. I Crystal River Unit 3
| |
| | |
| l Containment Air Locks B 3.6.2 l BASES [ ;
| |
| LCO Each air lock is required to be OPERABLE. For the air lock l (continued) to be considered OPERABLE, the air lock interlock mechanism l
| |
| must be OPERABLE, the air lock must be in compliance with '
| |
| l the Type B air lock leakage test, and both air lock doors !
| |
| must be OPERABLE. The interlock allows only one air lock door of an air lock to be opened at one time. This !
| |
| l provision ensures that a gross breach of containment does not exist when containment is required to be OPERABLE. j Closure of a single door in each air lock is sufficient to '
| |
| provide a leak tight barrier following postulated events.
| |
| Nevertheless, both doors are kept closed when the air lock )
| |
| is not being used for normal entry into and exit from 1
| |
| I containment.
| |
| l APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of !
| |
| radioactive material to containment. In MODES 5 and 6, the '
| |
| probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. l Therefore, the containment air locks are not required in MODE 5 to prevent leakage of radioactive material from .
| |
| containment. The requirements for the containment air locks
| |
| {
| |
| during MODE 6 are addressed in LC0 3.9.3, " Containment Penetrations." !
| |
| ACTIONS The ACTIONS are modified by a Note that allows entry and exit to perform repairs on the affected air lock component i or for emergencies involving personnel safety. If the ouhr 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). In this context, repairs include follow-up actions to an initial failure of the air lock door seal SR in order to determine which air lock door (s) is faulty. There a '
| |
| circumstances where an at-power containment entry woult' y required during the period of time that one air lock wo inoperable. In this case, entry would be made through 1,;e OPERABLE air lock if ALARA conditions permit. However, the 1
| |
| i (continued)
| |
| Crystal River Unit 3 8 3.6-8 Revision No. I
| |
| | |
| - ~ ~ - _
| |
| Containment Air Locks 8 3.6.2 BASES ACTIONS containment is a harsh environment with bulk averag l (continued) breathing apparatus may be required with the reactor at power.
| |
| In the event something was to happen to the individual who had entered containment, plant personnel would proceed through the most expeditious rescue path in order to get that individual out and provide medical care.
| |
| Thus, the Note allows entry and exit The through the the person happens to be through the inoperable d containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the containment during the Aftershort each time entry in which If the OPERABLE door is expected to be open.and exit the ALARA conditions permit, entry and exit should be via an OPERABLE air lock.
| |
| A second Note has been added to provide clarification that, for this LCO, separate Condition entry is allowed for each air lock.
| |
| In the event the air lock leakage results in exceeding the overall containment leakage rate, Note 3 direc
| |
| " Cont ainment. "
| |
| A.1. A.2 and A.3_
| |
| With one air lock door inoperable in one or more containment air locks, the OPERABLE door must be verified closed (Required Action A.1) in each affected containment air lock.
| |
| This ensures that a leak tight ' containment barrier is This maintained by the use of an OPERABLE air lock door.This specified time action must be completed within I hour.
| |
| period is consistent with the ACTIONS of LC 1 hour.
| |
| (continued)
| |
| Revision No. 1 B 3.6-9 Crystal River Unit 3 i
| |
| a ___
| |
| | |
| j.
| |
| Containment Air Locks B 3.6.2 BASES $
| |
| ACTIONS A.I. A.2 and A.3 (continued)
| |
| In addition, the affected air lock penetration must be isolated by locking closed the remaining OPERABLE air lock l door within the 24 hour Completion Time.
| |
| ! The 24 hour
| |
| ' Completion Time is considered reasonable for locking the OPERABLE air lock door, considering the OPERABLE door of the affected air lock is being maintained closed.
| |
| Required Action A.3 verifies that an air lock with an inoperable door has been isolated by the use of a locked and closed OPERABLE air lock docr. This ensures that an acceptable 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.
| |
| The Required Actions have been modified by two Notes.
| |
| Note 1 clarifies that only the Required Actions and associated Completion Times of Condition C are required if
| |
| ! both doors in the same air lock are ino With both doors in the same air lock inoperable, perable.
| |
| an OPERABLE door is i not available to be closed. Required Actions C.1 and C.2 i
| |
| l are the appropriate remedial actions. Note 2 allows use of i l
| |
| the air lock for entry and exit for 7 days under j administrative controls. Containment entry may be required to perform Technical Specifications '
| |
| )
| |
| Required Actions, as well as other ac(TS) Surveillances tivities and on equipment inside containment that are required by TS or activities on equipment that support TS-required equipment. This Note is not intended to preclude performing other activities (i.e., ,
| |
| non-TS-required activities) if the containment was entered, using the inoperable air lock, to perform an allowed activity listed above. This allowance is acceptable due to :
| |
| the low probability of an event that could pressurize the i '
| |
| containment during the short time that the OPERABLE door is expected to be open.
| |
| l l
| |
| l l
| |
| l (continued) i Crystal River Unit 3 B 3.6-10 Revision No. I
| |
| | |
| .- .== ._ . - - .- _ .. - - _- -- - .
| |
| Containment Air Locks
| |
| - B 3.6.2
| |
| ! BASES 1
| |
| ACTIONS B.1. B.2 and B.3, (continued)
| |
| With an air lock interlock mechanism inoperable in one or .
| |
| i more air locks, the Required Actions and associated Completion Times are consistent with those specified for Condition A.
| |
| ! The Required Actions have been modified by two Notes.
| |
| l Note 1 clarifies that only the Required Actions and ,
| |
| 4 associated Completion Times of Condition C are required if both doors in the same ai- lock are inoperable. With both doors in the same air lock inoperable, an OPERABLE door is ,
| |
| not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. Note 2 allows entry into and exit from the containment under the control of a i dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual I performs the function of the interlock).
| |
| C.I. C.2. and C.3 With one or more air locks inoperable for reasons other than those described in Condition A or B. Required Action C.1 >
| |
| requires action to be immediately initiated to evaluate previous combined leakage rates using current air lock test results. An evaluation is acceptable since it is overly conservative to immediately declare the containment inoperable if both doors in an air lock have failed a seal .
| |
| test or if the overall air lock leakage is not within i limits. In many instances (e.g., only one seal per door has failed), containment remains OPERABLE, yet only I hour (per LC0 3.6.1) would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In '
| |
| addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits.
| |
| This condition is entered whenever the air lock fails to meet either leakage rate acceptance criteria specified in SR 3.6.2.1 (the individual air lock door or the overall). The reason this condition is initially applicable to the failed >
| |
| air lock door SR is due to the design of the CR-3 air lock door leakage test configuration. Common piping is used to simultaneously leak rate test both air lock doors. When there is excessive leakage indicated during performance of i (continued)
| |
| Crystal River Unit 3 8 3.6-11 Revision No. 1
| |
| | |
| Containment Air Locks B 3.6.2 BASES ACTIONS C.I. C.2. and C.3 (continued) the SR, it is not initially possible to identify which door (or both) is leaking in excess of the allowable limit.
| |
| Therefore, the conservative action is to consider both doors inoperable and enter Condition C until the air lock, or at a minimum one door, can be determined to be OPERABLE. Once this has been done, Condition C may be exited and plant operation continue in accordance with the LC0 or the :
| |
| Required Actions of Condition A, as applicable. Completion Times for Condition A begin when the determination has been made that Condition A can be entered.
| |
| Required Action C.2 requires that one door in the affected containment air lock must be verified to be closed. This
| |
| * action must be completed within the I hour Completion Time.
| |
| This specified time period is consistent with the ACTIONS of LCO 3.6.1, which requires that containment be restored to OPERABLE status within I hour.
| |
| Additionally, the affected air lock (s) must be restored to OPERABLE status within the 24 hour Completion Time. The ;
| |
| specified time period is considered reasonable for restoring an inoperable air lock to OPERABLE status assuming that at least one door is maintained closed in each affected air lock.
| |
| The Required Actions have been modified by a note indicating .
| |
| performance of an overall air lock leakage test may be used to satisfy Required Actions C.1 and C.3 when Condition C is ;
| |
| entered as a result of failure of the individual door seal ,
| |
| test. The overall leakage test is performed at a test pressure of P., allowing direct evaluation of air lock leakage results against the overall containment leakage rate .
| |
| limit. Direct application of individual door seal leakage results to the overall limit is not technically justified -
| |
| since the individual test is performed at significantly less than P, and the results cannot be extrapolated.
| |
| Additionally, the test pressure applied to the outer door is in the non-accident direction.
| |
| Reliance on a successful performance of the overall leakage rate test for the purposes of declaring the air lock OPERABLE, even with one door not meeting its acceptance (continued)
| |
| Crystal River Unit 3 B 3.6-12 Revision No. 1 .
| |
| I
| |
| | |
| Containment Air Locks B 3.6.2 BASES ACTIONS C.1. C.2. and C.3 (continued) criteria, is acceptable when considering the historical intent of the overall/ individual door seal, air lock leakage rate tests. The overall test has historically been the true measure of an air lock's ability to perform its DBA function. The individual door test was subsequently added to 10 CFR 50, Appendix J as an acceptable means of complying with the 72 hour post-entry requirement of Appendix J. This was done to balance ALARA and resource concerns associated with the test with operating history that demonstrated the SR was typically met. Thus, a successful performance of the overall containment air lock leakage rate test ensures the air lock has the capability to perform its DBA function, and is therefore OPERABLE.
| |
| D.1 and 0.2 If the inoperable containment air lock cannot be restored to OPERABLE status within the required Completion Time, the <
| |
| plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and in MODE 5 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.
| |
| t SURVEILLANCE SR 3.6.2.1 REQUIREMENTS Maintaining containment air locks OPERABLE requires compliance with the leakage rate test requirements of 10 CFR 50, Appendix J (Ref.1), as modified by approved exemptions. This SR reflects the leakage rate testing t requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were established during initial air lock and containment testing. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall containment leakage rate. The Frequency is required by Appendix J, as modified by approved exemptions. Thus, SR 3.0.2 (which l
| |
| l allows Frequency extensions) don not apply.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.6-13 Revision No. 1 i .
| |
| | |
| .- ._.. - -. . .. . - - - . . ~ . . . . . . - . . - - . _ .
| |
| Containment Air Locks '
| |
| B 3.6.2~
| |
| BASES SURVEILLANCE SR 3.6.2.1 (continued)
| |
| REQUIREMENTS 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 DBA. Note ?. has been added to this SR requiring the i results to be evaluated against the acceptance criteria of SR 3.6.1.1. This ensures that air lock leakage is properly ,
| |
| accounted for in determining the overall containment leakage !
| |
| rate.
| |
| SR 3.6.2.2 The air lock interlock is' designed to prevent simultaneous opening of both doors in a single air lock. Since the inner and outer doors of an air lock are both designed to withstand the maximum expected post accident containment pressure, closure of either door will support containment OPERABILITY. Thus, the door interlock feature supports 4
| |
| containment OPERABILITY while the air lock is being used for i personnel transit in and out of the containment. Periodic
| |
| . ' i testing of this interlock demonstrates that the interlock will function as designed and that simultaneous opening of ;
| |
| the inner and outer doors will not inadvertently occur. Due '
| |
| to the purely mechanical nature of this interlock, and given
| |
| ~
| |
| that the interlock mechanism is only challenged when containment is entered, this test is only required to be ;
| |
| performed upon entering containment but is not required more ;
| |
| frequently than every 184 days. The 184 day Frequency is based on engineering judgment and is considered adequate in view of other indications of door and interlock mechanism status available to operations personnel. I REFERENCES 1. 10 CFR 50, Appendix J.
| |
| : 2. FSAR, Sections 14.2.2.
| |
| : 3. FSAR, Table 14-57.
| |
| : 4. 10 CFR 100. !
| |
| : 5. FSAR Section 5.2.5.2.3.1.
| |
| I
| |
| (
| |
| Crystal River nit 3 8 3.6-14 Revision No. 1
| |
| | |
| Containment Isolation Valves 8 3.6.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.3 Containment Isolation Valves BASES The general design basis governing isolation valve BACKGROUND requirements is leakage through fluid penetrations by a double barrier so that no single, credible failure or malfunction of an active component can result in loss of The installed double isolation or intolerable leakage.
| |
| barriers take the form of closed piping systems, both inside and outside the reactor building, and various types of isolation valves (Ref.1).
| |
| Containment isolation occurs upon receipt of a high containment signal.
| |
| pressure or diverse containment isolation containment isolation valves in fluid penetrations not required for operation of engineered safeguard systems toUpon actu prevent leakage of radioactive material.high pressure ~
| |
| isolate systems not required for containment or Reactor Other penetrations are Coolant System (RCS) heat removal.
| |
| isolated by the use of valves in the closed position or blind flanges. As a result, the containment isolation valves (and blind flanges) help ensure that the containment atmosphere will be isolated in the event of a re following a Design Basis Accident (DBA).
| |
| OPERABILITY of the containment isolation valves (and flanges) supports containment OPERABILITY during accident conditions.
| |
| The OPERABILITY requirements for Therefore, the containmen time limits assumed in the safety analysis.
| |
| OPERABILITY requirements provide assurance that containment leakage rates assumed in the safety analysis will not be exceeded.
| |
| The Reactor Building Purge System is part of the ReactorThe P Building Ventilation System.for intermittent operation, providing (continued) l
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| )
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| Revision No. 11 8 3.6-15 Crystal River Unit 3 4
| |
| | |
| i Containment Isolation Valves B 3.6.3 I BASES BACKGROUND airborne radioactivity caused by minor leakage from the RCS (continued) prior to personnel entry into containment. The Containment Purge System consists of one 48 inch line for exhaust and one 48 inch line fca supply, with supply and exhaust fans capable of purging ti e containment atmosphere at a rate of approximately 50,000 ft / min. The containment purge supply and exhaust lines each contain two isolation valves that receive an isolation signal on a unit vent high radiation condition. Each of the purge lines is provided with two 48 inch diameter butterfly valves, one inside and one outside of containment. The valves inside containment are electric motor operated, designed to close within five seconds, while the outboard isolation valves are pneumatically opened-spring closed, designed to close within two seconds of demand (Ref. 5). Each of these valves was intended to be capable of closing against a differential pressure of 55 psig (the containment design pressure), such that closure would be assured in the event a loss of coolant accident (LOCA) occurred while containment purging was in progress.
| |
| Failure of the purge valves to close following a design basis event would cause a significant increase in the radioactive release because of the large containment leakage path introduced by these 48 inch purge lines. Failure of l the purge valves to close would result in leakage considerably in excess of the containment design leakage
| |
| {
| |
| rate of 0.25% of containment air weight per day (L.)
| |
| (Ref. 2). Because of their large size, the 48 inch purge I valves are not qualified for automatic closure from their open position under DBA conditions. Therefore, the 48 inch purge valves are maintained sealed closed (SR 3.6.3.1) in !
| |
| MODES 1, 2, 3, and 4.
| |
| The 6 inch containment minipurge valves operate to:
| |
| : a. Reduce the concentration of noble gases within containment prior to and during personnel access; and
| |
| : b. Equalize internal and external pressures.
| |
| Since the minipurge valves are designed to meet the requirements for automatic containment isolation valves, these valves may be opened as needed in MODES 1, 2, 3, and 4.
| |
| l (continued)
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| Crystal River Unit 3 8 3.6-16 Revision No. 11
| |
| | |
| 1 Containment Isolation Valves B 3.6.3 BASES (continued)
| |
| APPLICABLE The containment isolation valve LC0 was derived from the SAFETY ANALYSES requirements related to the control of leakage from containment during major accidents. This LC0 is intended to ensure the containment leakage rates do not exceed the values assumed in the safety analysis. As part of the containment boundary, containment isolation valve OPERABILITY supports leak tightness of the containment.
| |
| Therefore, the safety analysis of any event requiring containment isolation is applicable to this LCO.
| |
| The DBAs that result in a release of radioactive material
| |
| ' within containment are a loss of coolant accident (LOCA), a main steam line break, and a rod ejection accident (Ref. 3).
| |
| In the analysis for each of these accidents, it is assumed that containment isolation valves are either closed or function to close within the required isolation time following event initiation. This ensures that potential leakage paths to the environment through containment isolation valves (including containment purge valves) are minimized.
| |
| The acceptance criteria applied to accidental releases of radioactive material to the environment are given in terms of total radiation dose received by a member of the general public who remains at the exclusion area boundary for two hours following the onset of the postulated fission product release. The limits established in 10 CFR 100 (Ref. 8) are a whole body dose of 25 Rem or a 300 Rem dose to the thyroid from iodine exposure.
| |
| The DBA analysis assumes that, within 60 seconds after the accident, isolation of the containment is complete and leakage terminated except for the design leakage rate, L,.
| |
| The containment isolation total response time of 60 seconds includes signal delay, diesel generator startup (for loss of offsite power), and containment isolation valve stroke times. SR 3.3.5.4 addresses the response time testing requirements.
| |
| The single-failure criterion required in the safety analyses was considered in the original design of the containment purge valves. Two valves in a series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred. The l
| |
| (continued)
| |
| Crystal River Unit 3 B 3.6-17 Revision No. 11
| |
| | |
| ~
| |
| Containment Isolation Values B 3.6.3 BASES s-APPLICABLE SAFETY ANALYSES inboard and outboard isolation valves on each line are provided with diverse power sources, motor operated and (continued) pneumatically operated spring closed, respectively. This arrangement was designed to preclude common mode failures from disabling both valves on a purge line.
| |
| The purge valves may be unable to close in the environment following a LOCA. Therefore, each of the purge valves is required to remain sealed closed during MODES 1, 2, 3, and 4. In this case, the single-failure criterion remains applicable to the containment purge valves because of failure in the control circuit associated with each valve.
| |
| Again, the purge system valve design prevents a single failure from compromisir.g containment OPERABILITY as long as the system is operated in accordance with the subject LCO.
| |
| The containment isolation valves satisfy criterion 3 of the NRC Policy Statement.
| |
| LCO Containment isolation valves form a part of the containment boundary. The containment isolation valve safety function is related to control of containment leakage rates during a DBA.
| |
| The automatic power operated isolation valves are required to have isolation times within limits and to actuate on an automatic isolation signal. The 48 inch purge valves must be maintained sealed closed in MODES 1, 2, 3 and 4. The valves covered by this LC0 are listed along with their .
| |
| associated stroke times in the FSAR (Ref. 4).
| |
| The normally closed isolation valves are considered OPERABLE when manual valves are closed, check valves have flow through the valve secured, blind flanges are in place, and closed systems are intact.
| |
| Purge valves with resilient seals must meet additional leakage rate requirements addressed as part of this Specification. All other containment isolation valve leakage rate testing is addressed by LCO 3.6.1,
| |
| " Containment," as part of Type C testing.
| |
| l l
| |
| l (continued) l Crystal River Unit 3 B 3.6-18 Revision No. 11
| |
| | |
| 1 2
| |
| Containment Isolation Valves B 3.6.3 J
| |
| . BASES LCO This LC0 provides assurance that the containment isolation (continued) valves and purge valves will perform their designated safety functions to control leakage from the containment during accidents.
| |
| APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. j Therefore, the containment isolation valves are not required to be OPERABLE in MODE 5. The requirements for containment isolation valves during MODE 6 are addressed ia LC0 3.9.3,
| |
| " Containment Penetrations."
| |
| ACTIONS The following terms are defined for the purpose of l implementing this Specification: 1
| |
| - penetration flowpath: The piping which passes through ):
| |
| the RB liner such that a portion of the system inside the RB can communicate with the portion outside the RB. A penetration passes through the imaginary plane established by the R3 liner.
| |
| - unisolated: The state nf a penetration flowpath whereby the operating fluid (liquid or gas) of the system is capable of passing freely through the imaginary plane established by the RB liner.
| |
| The ACTIONS are modified by a Note allowing penetration flow paths, except for 48 inch purge valve penetration flow paths, to be unisolated intermittently under administrative control s. These administrative controls consist of stationing a dedicated operator at the valve controls, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for containment isolation is indicated. Due to the size of the containment purge line penetration and the fact that those penetrations exhaust directly from the containment atmosphere to the environment, the penetration flow paths containing these valves may not be opened under (continued)
| |
| Crystal River Unit 3 B 3.6-19 Revision No. 11 i
| |
| | |
| Containment Isolation Values B 3.6.3 l
| |
| BASES -
| |
| l ACTIONS administrative controls. A single purge valve in a l
| |
| (continued) penetration flow path may be opened to effect repairs to an )
| |
| inoperable valve, as allowed by SR 3.6.3.1.
| |
| A second Note has been added to provide clarification that, for this LCO, separate Condition entry is allowed for each penetration flow path.
| |
| The ACTIONS are further modified by a third Note, which ensures apprcariate remedial actions are taken, if i necessary, if the affected systems ara rendered inoperable by an inoperable containment isolation valve. ;
| |
| In the event purge valve leakage results in exceeding the l overall containment leakage rate, Note 4 directs entry into the applicable Conditions and Required Actions of LC0 3.6.1. '
| |
| A.1 and A.2
| |
| ]
| |
| In the event one containment isolation valve in one or more ;
| |
| penetration flow paths is inoperable (except for purge valve i leakage not within limit), the affected penetration flow !
| |
| path must be isolated. The method of isolation must include t 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 containment isolation valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For a penetration isolated ~in accordance with Required Action A.1, the valve used to i isolate the penetration should be the closest available one to containment. Required Action A.1 must be completed within the 4 hour Completion Time. The specified time period is reasonable, considering the time required to isolate the penetration and the relative importance of supporting containment OPERABILITY during MODES 1, 2, 3, and 4.
| |
| For affected penetration flow paths that cannot be restored to OPERABLE status within the 4 hour Completion Time and that have been isolated in accordance with Required Action A.1, the affected penetration flow paths must be verified to be isolated on a periodic basis. This periodic (continued)
| |
| Crystal River Unit 3 B 3.6-20 Revision No. 11
| |
| | |
| Containment Isolation Valves B 3.6.3 BASES ACTIONS A.1 and A,2 (continued) >
| |
| verification is necessary to ensure that 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 valve ,
| |
| manipulation. Rather, it involves verification, through a system walkdown, that those isolation devi;es capable of being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside containment" is appropriate considering the fact that the valves are operated under administrative controls and the probability of their misalignment is low. For the isolation devices inside containment, the time period specified as " prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the isolation devices and other ,
| |
| administrative controls that will ensure that isolation device misalignment is an unlikely possibility.
| |
| Condition A has been modified by a Note indicating this Condition is only applicable to those penetration flow paths with two containment isolation valves. For penetration flow paths with only one containment isolation valve and a closed system, Condition C provides appropriate actions.
| |
| Required Action A.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and allows the devices to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable since access to these areas is .
| |
| typically restricted. Therefore, the probability of misalignment of these devices, once they have been verified to be in the proper position, is small. ;
| |
| 1 B.1 and 8.2 With all containment isolation valves in one or more penetration flow paths inoperable (except for purge valve ,
| |
| leakage not within limit), the affected penetration flow path must be isolated within I hour. The method of isolation must include the use of at least one isolation (continued)
| |
| Crystal- River Unit 3 B 3.6-21 Revision No. 11 !
| |
| | |
| Containment Isolation Values B 3.6.3 BASES -
| |
| ACTIONS 8.1 and 8.2 (continued) barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are i 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 LC0 3.6.1. In the event the affected penetration is isolated in accordance with Required Action B.1, the affected penetration must be verified to be isolated on a periodic basis per Required Action B.2. This periodic verification is necessary to assure leak tightness of conta1 ment and that penetrations requiring isolation following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration flow path is isolated is appropriate considering the fact that the valves are operated under administrative controls and the probability of their misalignment is low. I Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two containment isolation valves or those with one containment isolation valve and no closed system. Condition A of this l Specification addresses the condition of one containment isolation valve inoperable in a penetration flow path with two containment isolation valves.
| |
| Required Action B.2 is modified by a Note that applies to i valves and blind flanges located in high radiation areas and allows the devices to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable since access to these areas is typically restricted. Therefore, the probability of misalignment of these devices, once they have been verified to be in the proper position, is small.
| |
| C.1 and C.2 With one or more penetration flow paths with one containment isolation valve inoperable or the closed system breached, 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 (continued)
| |
| Crystal River Unit 3 6 3.6-22 Revision No. 11
| |
| | |
| Containment Isolation Valves 8 3.6.3 BASES ACTIONS C.1 and C.2 (continued) 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,may a
| |
| closed manual valve, and a blind flange. A check valve not be used to isolate the affected penetration. Required Action C.1 must be completed within the 4 hour Completion Time. The specified time period is reasonable, consioering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting containment OPERABILITY during MODES 1, 2, 3, and 4. In the event the affected penetration is isolated in accordance with Required Action C.1, the affected penetration flow path must be verified to be isolated on a periodic basis. This periodic verification is necessary to assure leak tightness of containment and that containment penetrations requiring isolation following an accident are isolated. The Completion Time of once per 31 days for verifying that each affected penetration flow path is isolated is appropriate considering the fact that the valves are operated under administrative controls and the probability of their misalignment is low. .
| |
| Condition C is modified by a Note indicating that this
| |
| ! Condition is only applicable to those penetration flow paths with only one containment isolation valve and a closed system. This Note is necessary since this Condition is written to specifically address those penetration flow paths utilizing a closed system.
| |
| Required Action C.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and allows these devices to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable since access to these areas is typically restricted. Therefore, the probability of misalignment of these devices, once verified to be in the proper position, is small.
| |
| (continued) l
| |
| [
| |
| 8 3.6-23 Revision No. 11 Crystal River Unit 3 i
| |
| | |
| Containment Isolation Valees B 3.6.3 i BASES ACTIONS (LI.
| |
| (continued)
| |
| In the event one or more containment purge valves in one or more penetration flow paths are not within the purge valve leakage limits, purge valve leakage must be restored to within limits within 24 hours. The specified time is a reasonable period for restoring the valve leakage to within limits, provided overall containment leakage rate remains within limits. With the purge valve seal degraded such that leakage exceeds the limits, there is an increased potential for the same mechanism that caused the initial degradation to cause further degradation. If left unchecked, this could result in a loss of containment OPERABILITY. Thus, the 24 hour Completion Time is necessary to limit the length of time the plant can operate in this condition.
| |
| E.1 and E.2 If the Required Actions and associated Completion Times are s not met, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and in MODE 5 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.
| |
| SURVEILLANCE SR 3.6.3.1 REQUIREMENTS Each 48 inch containment purge valve is required to be verified sealed closed at 31 day intervals. This Surveillance is designed to ensure that a gross breach of containment is not caused by an inadvertent or spurious opening of a containment purge valve. Detailed analysis of the purge valves failed to conclusively demonstrate their ability to close during a LOCA in time to maintain offsite doses to within licensing basis limits. Therefore, these valves are required to be in the sealed closed position during MODES 1, 2, 3, and 4. A containment purge valve that is sealed closed must have motive power to the valve operator removed. This can be accomplished by de-energizing (continued)
| |
| Crystal River Unit 3 8 3.6-24 Revision No. 11
| |
| | |
| Containment Isolation Values B 3.6.3 BASES SURVEILLANCE SR 3.6.3.1 (continued)
| |
| REQUIREMENTS l
| |
| I the source of electric power or by removing the air supply to the valve operator. In this application, the term l
| |
| " sealed" has no connotation of leak tightness. The Frequency is a result of an NRC initiative, Generic Issue B-24 (Ref. 6), related to containment purge valve use during unit operations. In the event purge valve leakage requires entry into Condition D, the Surveillance permits opening one purge valve in a penetration flow path to perform repairs.
| |
| SR 3.6.3.2 This SR ensures that the minipurge valves are closed as required or, if open, open for an allowable reason. The SR is not required to be met when the minipurge valves are open for pressure control, ALARA or air quality considerations for personnel entry, or for Surveillances that require the valves to be open. The minipurge valves are capable of closing in the environment followir.g a LOCA. Therefore, these valves are allowed to be open i9: limited periods of time. The 31 day Frequency for verifying valve position is consistent with other containment isolation valve -
| |
| requirements discussed in SR 3.6.3.3.
| |
| SR 3.6.3.3 This SR requires verification that each containment isolation manual valve and blind flange located outside containment and 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 containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown, that those valves outside containment and capable cf being ,
| |
| mispositioned are in the correct position. Since verification of valve position for valves outside containment is relatively easy, a 31 day frequency, based on engineering judgment was chosen to provide added assurance (continued)
| |
| Crystal River Unit 3 8 3.6-25 Revision No. 11 :
| |
| | |
| Containment Isolation Valves B 3.6.3
| |
| ..~
| |
| BASES ,
| |
| SURVEILLANCE SR 3.6.3.3 (continued)
| |
| REQUIREMENTS of the correct positions. The SR specifies that valves open under administrative controls are not required to meet the SR during the time the valves are open.
| |
| A Note modifies this SR and applies to valves and blind flanges located in high radiation areas allowing these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, 3, and 4 for ALARA reasons. Therefore, the probability of misalignment of these valves, once they have been verified to be in the proper position, is low.
| |
| SR 3.6.3.4 This SR requires verification that each containment isolation manual valve and blind flange that is located inside containment and 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 containment boundary is within design limits. For valves inside containment, the Frequency of " prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is appropriate, since these valves and flanges are typically inaccessible. during reactor operation, are operated under administrative controls and the probability of their misalignment is low. The SR specifies that valves open under administrative controls are not. required to meet the SR during the time they are open.
| |
| The Note allows valves and blind flanges located in high radiation areas to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the access to these areas is typically restricted during MODES 1, 2, 3, and 4 for ALARA reasons. Therefore, the probability of misalignment of these valves, once they have been verified to be in their proper position, is small.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.6-26 Revision No. 11 i
| |
| | |
| Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE SR 3.6.3.5 REQUIREMENTS Verifying that the isolation time of each power operated and (continued) automatic containment isolation valve that is not locked, sealed, or otherwise secured in the isolation position The is within limits is required to demonstrate OPERABILITY.
| |
| isolation time test ensures the valve will isolate in a time period less than or equal to that assumed in the safety analyses. The isolation time and Frequency of this SR are in accordance with the Inservice Testing Program.
| |
| SR 3.6.3.6 For 48 inch containment purge valves, additional leakage rate testing beyond the test requirements of 10 CFR 50, Operating Appendix J, is required to ensure OPERABILITY.
| |
| experience has demonstrated that this type of valve seal has the potential to degrade in a shorter time period than do other seal types. Based on this observation and the importance of maintaining this penetration leak tight (due to the direct path between containment and the environment),
| |
| additional purge valve testing was established as part of the NRC resolution of Generic Issue B-20, " Containment leakage Due to Seal Deterioration" (Ref. 7).
| |
| The specified Frequencies are based on plant-specific The as-found/as-left leakage rate data for these valves.
| |
| data indicates the CR-3 purge valve resilient seals do not degrade during the operating cycle with the valves in the sealed closed position. The 92 day Frequency after opening the valves recognizes the seals are prone to excessive leakage following use and is consistent with the NRC resolution of B-20.
| |
| A Note to this SR requires the results to be evaluated This ensures against the acceptance criteria of SR 3.6.1.1.
| |
| that excessive containment purge valve leakage is properly accounted for in determining the overall containment leakage rate to verify containment OPERABILITY.
| |
| (continued) 8 3.6-27 Revision No. 11 l Crystal River Unit 3 i
| |
| | |
| Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE SR 3.6.3.7 REQUIREMENTS (continued)
| |
| Automatic containment isolation valves close on a containment isolation signal to prevent leakage of radioactive material from containment following a DBA. This SR ensures each automatic containment isolation valve that is not locked, sealed, or otherwise secured in the isolation position, will actuate to its isolation position on an actual or simulated actuation signal. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass this Surveillance when performed at the 24 month Frequency.
| |
| Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| The SR is modified by a note indicating the SR is not applicable in the identified MODE. This is necessary in order to make the requirements for automatic system response consistent with those for the actuation instrumentation.
| |
| REFERENCES 1. FSAR, Section 5.3.1.
| |
| : 2. FSAR, Section 5.2.5.P.2.
| |
| : 3. FSAR, Sections 14.2.2.
| |
| : 4. FSAR, Table 5-9.
| |
| l
| |
| : 5. FSAR, Section 5.3.3.2.
| |
| : 6. Generic Issue B-24.
| |
| : 7. Generic Issue B-20.
| |
| : 8. 10 CFR 100.
| |
| Crystal River Unit 3 8 3.6-28 Revision No. 11
| |
| | |
| Containment Pressure B 3.6.4 B'6 CONTAINMENT SYSTEMS B 3.6.4 Containment Pressure BASES The containment pressure is limited during normal operation BACKGROUND to preserve the initial conditions assumed in the accident analyses for a loss of coolant accident (LOCA) or steam line These limits also prevent the containment break (SLB).
| |
| pressure from exceeding the containment design negative pressure differential with respect to the outside atmosphere in the event of inadvertent actuation of the Reactor Building Spray System.
| |
| Containment pressure is a process variable that is monitored The containment pressure limits are derived and controlled.
| |
| from the input conditions used in the containment functional ,
| |
| analyses and the containment structure external pressure
| |
| * analysis. Should operation occur outside these limits coincident with a Design Basis Accident (DBA), post accident pressures could exceed calculated values.
| |
| Containment internal pressure is an initial condition used APPLICABLE in the DBA analyses to establish the maximum peak SAFETY ANALYSES The 1.imiting DBAs containment internal pressure.
| |
| considered, relative to containment pressure, are the LOCA The worst-case LOCA generates larger mass and and SLB. Thus, the LOCA energy release than the worst-case SLB.
| |
| event bounds the SLB event from the containment peak pressure standpoint (Ref. 1).
| |
| The initial pressure condition used in the containment analysis was 17.7 psia (3.0 psig). This resultedThe in a LC0 l maximum peak pressure from a LOCA of S4.2 psig.
| |
| limit of 3.0 psig ensures that, in the event of an accident, the design pressure of 55 psig for containment is not exceeded.
| |
| In addition, the building was designed for an internal pressure equal to 3 psig above external pressure during a tornado. The containment was also designed for an internal pressure equal to 2.5 psig below external pressure, to withstand the resultant pressure drop from an accidental actuation of the Reactor Building Spray System.
| |
| (continued)
| |
| Revision No. 1 l B 3.6-29 Crystal River Unit 3 I _
| |
| | |
| 1 Containment Pressure B 3.6.4 BASES -
| |
| J APPLICABLE SAFETY ANALYSES Other accident analyses, in particular the cooling i
| |
| effectiveness of the Emergency Core Cooling Systems during i
| |
| (continued) the core reflood phase of a LOCA, also utilize the negative pressure limit as an input.
| |
| i Containment pressure satisfies Criterion 2 of the NRC Policy Statement.
| |
| t LC0 Maintaining containment pressure less than or equal to the LC0 upper pressure limit ensures that, in the ever.t of a DBA, the resultant peak containment accident pressure will remain below the containment design pressure. Maintaining containment pressure greater than or equal to the LC0 lower pressure limit ensures that the containment will not exceed the design negative differential pressure following an inadvertent actuation of the Reactor Building Spray System initiated from typical operating conditions. !
| |
| The numerical limits in the LC0 have not been adjusted to account for instrument error.
| |
| (
| |
| APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of '
| |
| ; radioactive material to containment. Since maintaining containment pressure within design basis limits is essential t
| |
| to ensure initdal conditions assumed in the accident analysis are maintained, the LCO is applicable in MODES 1, 2, 3, and 4.
| |
| In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining containment pressure within the limits of the LC0 is not required in MODE 5 or 6.
| |
| l f
| |
| (continued)
| |
| Crystal River Unit 3 8 3.6-30 Revision No. 1 l
| |
| | |
| Containment Pressure B 3.6.4 BASES (continued)
| |
| ACTIONS A.J When containment pressure is not within the limits of the LCO, containment pressure must be restored to within these limits within 1 hour. The Required Action is necessary to return operation to within the bounds of the containment analysis. The 1 hour Completion Time is consistent with the ACTIONS of LCO 3.6.1, " Containment," which requires that containment be restored to OPERABLE status within I hour.
| |
| B.1 and B.2
| |
| 'If containment pressure cannot be restored within limits within the required Completion Time, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and in dODE 5 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.
| |
| SURVEILLANCE SR 3.6.4.1 REQUIREMENTS Verifying that containment pressure is within limits ensures that operation remains within the limits assumed in the containment analysis. The 12 hour Frequency of this SR was developed after taking into consideration operating experience related to trending of containment pressure variations during the applicable MODES. Furthermore, the 12 hour Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator'to an abnormal containment pressure condition.
| |
| REFERENCES 1. FSAR, Section 14.2.2.5.9.
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| Crystal River Unit 3 8 3.6-31 Revision No. 1
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| | |
| Containment Air Temperature B 3.6.5 B 3.6 CONTAINMENT: SYSTEMS (~
| |
| B 3.6.5 Containment Air Temperature BASES BACKGROUND The containment structure serves to contain radioactive material, which may be released from the reactor core following a Design Basis Accident (DBA). The containment arithmetic average air temperature is limited during normal operation to preserve the initial conditions assumed in the accident analyses for a loss of coolant accident (LOCA) or steam line break (SLB).
| |
| The containment average air temperature limit is derived from the input conditions used in the containment functional analyses and the containment structure external pressure analysis. This LC0 ensures that initial conditions assumed in the analysis of a DBA are not violated during unit operations. The total amount of energy to be removed from the Containment Cooling System during post accident conditions is dependent upon the energy released to the containment due to the event as well as the initial containment temperature and pressure. The higher the .~
| |
| initial temperature, the higher the resultant peak !
| |
| containment pressure and temperature. Exceeding containment design pressure may result in leakage greater than that assumed in the accident analysis. Operation with containment temperature in excess of the LC0 limit violates an initial condition assumed in the accident analysis.
| |
| APPLICABLE Containment average air temperature is an initial condition SAFETY ANALYSES used in the DBA analyses. Average air temperature is also used to establish the containment environmental qualification operating envelope. The limit for containment average air temperature ensures that operation is maintained within the assumptions used in the DBA analysis for containment.
| |
| Several accidents (primarily LOCA and SLB) result in a marked increase in containment temperature and pressure due to energy release within the containment. Of these, the LOCA results in the greatest sustained increase in containment temperature. By maintaining containment air i temperature at less than the initial temperature assumed in (continued) <
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| l Crystal River Unit 3 B 3.6-32 Amendment No. 149 l
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| ! I
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| | |
| Reactor Building Spray and Containment Cooling Systems B 3.6.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.6 Reactor Building Spray and Containment Cooling Systems BASES ,
| |
| 4 BACKGROUND The Reactor Building (RB) Spray and Containment Cooling Systems are Engineered Safeguards (ES) systems. They provide containment atmosphere cooling to limit post accident pressure and temperature in containment to less than the design values. Reduction of containment pressure and the iodine removal capability of the spray reduces the release of fission product radioactivity from containment to the environment, in the event of a Design Basis Accident (DBA), to within limits. The Reactor Building Spray and Containment Cooling Systems were designed considering the applicable proposed 10 CFR 50.34, Appendix A, " General Design Criteria for Nuclear Power Plant Construction .
| |
| Permits", (Ref. 1) criteria. Refer to FSAR Section 1.4 for a more detailed description of these design criteria.
| |
| Reactor Buildino (RB) Sorav System The RB Spray System consists of two separate trains of equal capacity, each capable of meeting the design bases. Each train includes an RB spray pump, spray headers, nozzles, valves, and piping. Each train is powered from a separate ES bus. The borated water storage tank (BWST) supplies ,
| |
| borated water to the RB Spray System during the ECCS injection mode of operation. In the recirculation mode of operation, RB Spray System pump suction is manually '
| |
| transferred from the BWST to the containment sump.
| |
| During the injection mode of ECCS operation, the RB Spray i System provides a spray of relatively cold borated water into the upper regions of containment to reduce the containment pressure and temperature and to reduce the concentration of fission products in the containment atmosphere. Each header contains nozzles which are arranged ,
| |
| to provide maximum " washing" of the RB atmosphere. The headers are located in the RB dome, more than 96 feet above ,
| |
| any floor level. Spray nozzles are spaced in.the header to give uniform spray coverage of the RB volume above the operating floor with one or both spray header systems in operation. CR-3 iodine removal effectiveness analysis (continued) l l
| |
| Crystal River Unit 3 8 3.6-35 Revision No. 2
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| | |
| Reactor Building Spray and Containment Cooling Systems '
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| B 3.6.6 ,
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| , BASES , , - ,
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| BACKGROUND Reactor Buildina Sorav System (continued) 4 quotes a value of 65.2% for RB volume covered by the spray, based on the location of the uppermost spray ring to the operating floor at elevation 160 feet. In the recirculation -
| |
| i mode of operation, water in the reactor building emergency ;
| |
| sump is mixed with trisodium phosphate dodecahydrate (TSP-C) i in order to raise the pH of the sump water to at least 7.0.
| |
| Heat is removed from the containment sump water by the decay
| |
| ; heat removal (DHR/LPI) coolers. Each train of the RB Spray System provides adequate . spray coverage to meet the system ;
| |
| design requirements for containment heat removal.
| |
| 4 The RB Spray System is actuated automatically by a High-High
| |
| . reactor building pressure signal (30 psig) coincident with a !
| |
| ! high pressure injection start permit actuation signal. An !
| |
| i automatic actuation opens the RB Spray System pump discharge valves to correspond to a pre-set flowrate and starts the 1
| |
| two RB Spray System pumps.
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| i Containment Coolina System i
| |
| i The Containment Cooling System consists of three containment '
| |
| cooling units (AHF-1A, IB, IC) connected to a common duct suction header with four vertical return air ducts. Each ;
| |
| ' cooling train is equipped with demisters, cooling coils, and 4
| |
| an axial flow fan driven by a two speed water cooled electric motor. Each unit connection (two per unit) to the j common header is provided with a backpressure damper for isolation purposes. i i
| |
| During normal operation, two containment cooling units are
| |
| ' required to operate to maintain containment average air ,
| |
| temperature less than 130 F (Ref. 3.6.5). With two units
| |
| ' operating, the plant has recorded temperatures as high as 129 F. The third unit (or swing unit) is on standby and
| |
| ; isolated from the operating units by means of the backpressure dampers. The swing unit is equipped with a transfer switch which allows it to be manually placed to either the "A" or "B" power train to operate in case one of the operating units fails. For normal operation, cooling water to the operating coils is provided by the industrial coolers (CI System).
| |
| 4 (continued)
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| Crystal River Unit 3 B 3.6-35 Revision No. 2
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| | |
| Reactor Building Spray and Containment Cooling Systems B 3.6.6 l
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| BASES J
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| BACKGROUND Containment Coolina System (continued)
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| [
| |
| Upon receipt of a high reactor building pressure ES signal (4 psig), the two operating cooling fans running at high speed will automatically stop. The two cooling unit fans connected to the E3 buses will automatically restart and run at low speed, provided normal or emergency power is '
| |
| available. In post accident operation following an actuation signal, the Containment Cooling System fans are designed to start automatically in slow speed if they are not already running. The fans are operated at the lower speed during accident conditions to prevent motor overload ,
| |
| from the higher density atmosphere. The automatic changeover valves operate to provide Nuclear Service Closed Cycle Cooling (SW) System flow to the operating units and f
| |
| isolate the CI System flow. ,
| |
| APPLICABLE The RB Spray System and Containment Cooling System limit the SAFETY ANALYSES temperature and pressure that could be experienced following ,
| |
| a DBA. The limiting DBAs considered are the loss of coolant accident (LOCA) and the steam line break. The postulated DBAs are analyzed, with regard to containment ES systems, assuming the loss of one ES bus. This is the worst-case !
| |
| single active failure, resulting in one train of the RB !
| |
| Spray System and one train of'the Containment Cooling System being inoperable.
| |
| The analysis and evaluation show that, under the worst-case scenario, the highest peak containment pressure is 54.2 psig (experienced duiing a LOCA)~. The analysis shows that the l peak containment temperature is 278.4*F (experienced during a LOCA). Both results are less than the design values. ,
| |
| (See the Bases for LC0 3.6.4, " Containment Pressure," and LC0 3.6.5, " Containment Air Temperature," for a detailed discussion.) The analyses and evaluations assume a power level of 2568 MWt, one RB spray train and one RB cooling train operating, and initial (pre-accident) conditions of ,
| |
| l 130*F and 17.7 psia. The analyses also assume a response j time delayed initiation to provide conservative peak i calculated containment pressure and temperature responses.
| |
| (continued) 1 :
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| 1 l l Crystal River Unit 3 B 3.6-37 Revision No. 2
| |
| | |
| Reactor Building Spray and Containment Cooling Systems B 3.6.6 i BASES i
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| (.
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| APPLICABLE SAFETY ANALYSIS The effect been of an inadvertent R8 spray actuation has also analyzed.
| |
| (continued) An inadvertent spray actuation results in a 2.5 psig containment pressure drop and is associated with !
| |
| the sudden cooling effect in the interior of the leak tight containment. !
| |
| for LCO 3.6.4. Additional discussion is provided in the Bases i I
| |
| The modeled RB Spray System actuation from the containment analyses is based on a response time associated with exceeding the RB pressure High-High setpoint coincident with a high pressure injection start permit actuation signal to achieve full flow through the containment spray nozzles.
| |
| The Containment Spray System total response time of 90 seconds includes emergency diesel generator (CDG) startup (for loss of offsite power), block loading of equipment, spray pump startup, and spray line filling (Ref. 2).
| |
| Containment cooling train performance for post accident l conditions is given in Reference 3. The result of the analysis is that each train can provide at least 33% of the required peak cooling capacity during the post accident !
| |
| condition. The train post accident cooling capacity under j varying containment ambient conditions, required to perform ~
| |
| 1 j
| |
| the accident analyses,.is also shown in Reference 4. '
| |
| The modeled Containment Cooling System actuation from the containment analysis is based on a response time associated ;
| |
| with exceeding the containment pressure high setpoint to- l achieve full Containment Cooling System air and safety grade '
| |
| cool.ing water flow. The Containment Cooling System total response time of 25 seconds includes signal delay, EDG startup (for loss of offsite power), and service water pump '
| |
| startup times (Ref. 3). 2 The Reactor Building Spray System and the Containment Cooling System satisfy Criterion 3 of the NRC Policy Statement.
| |
| LCO During a DBA, a minimum of one containment cooling train and one RB spray train are required to maintain the containment peak pressure and temperature below the design limits.
| |
| Additionally, one RB spray train is required to remove 1
| |
| (continued) l.
| |
| i Crystal River Unit 3 B 3.6-38 Revision No. 2 t
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| | |
| l 4
| |
| Reactor Building Spray and Containment Cooling Systems l l., B 3.6.6 1 J
| |
| BASES 1
| |
| i .
| |
| LCO iodine from the containment atmosphere and maintain <
| |
| ; -(continued) concentrations below those assumed in the safety analysis. ;
| |
| To ensure that these. requirements are met, two RB spray trains and two containment cooling units must be OPERABLE. ;
| |
| ; Therefore, in the event of an accident, the minimum requirements are met, assuming the worst-case single active 3 failure occurs.
| |
| 5 Each RB Spray System train includes a spray pump, spray ,
| |
| headers, nozzles, valves, piping, instruments, and controls i to ensure an OPERABLE flow path capable of taking suction from the BWST upon an Engineered Safeguards Actuation System signal and manually transferring suction to the reactor building emergency sump. ,
| |
| Each Containment Cooling System train includes demisters, l cooling coils, dampers, an axial flow fan driven by a two ,
| |
| speed water cooled electrical motor, instruments, and !
| |
| controls to ensure an OPERABLE flow path.
| |
| i APPLICABILITY In MODES 1, 2, 3, and 4, a DM.could cause a release of radioactive material to containment and an increase in ,
| |
| containment pressure and temperature, requiring the '
| |
| operation of the RB spray trains and containment cooling trains.
| |
| In MODES 5 and 6, the probability and consequences of these i events are reduced due to the pressure and temperature !
| |
| limitations of these MODES. Thus, the RB Spray System and -
| |
| the Containment Cooling System are not required to be OPERABLE in MODES 5 and 6.
| |
| ACTIONS L.1 l With one RB spray train inoperable, the inoperable containment spray train must be restored to OPERABLE status within 72 hours. In this Condition, the remaining OPERABLE spray and cooling trains are adequate to perform the iodine !
| |
| removal and containment cooling functions. The 72 hour Completion Time takes into account the redundant heat (continued)
| |
| Crystal River Unit 3 8 3.6-39 Revision No. 2
| |
| | |
| Reactor Building Spray and Containment Cooling Systems B 3.6.6 BASES ACTIONS A.1 (continued) removal capability afforded by the OPERABLE RB spray train and cooling system train (s), reasonable time for repairs, and the low probability of a DBA occurring during this period.
| |
| The 10 day portion of the Completion Time for Required Action A.1 is based upon engineering judgment. It takes into account the low probability of coincident entry into two Conditions in this LC0 coupled with the low probability of an accident occurring during this time. Refer to Section 1.3, " Completion Times", for a more detailed discussion of the purpose of the "from discovery of failure to meet the LC0" portion of the Completion Time.
| |
| B.1 and B.2 If the inoperable RB spray train cannot be restored to OPERABLE status within the required Completion Time, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours and in MODE 5 within 84 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. The extended interval to reach MODE 5 allows additional time to attempt restoration of the RB spray train and is reasonable when considering the driving force for a release of radioactive material from the Reactor Coolant System is reduced in MODE 3.
| |
| With one of the required containment cooling trains inoperable, the inoperable containment cooling train must be restored to OPERABLE status within 7 days. The components in this degraded condition provide iodine removal capabilities and are capable of providing at least 100% of the heat removal needs after an accident. The 7 day Completion Time was developed taking into account the redundant heat remova, capabilities afforded by combinations of the RB Spray System and Containment Cooling System and the low probability of a DBA occurring during this period.
| |
| l (continued) i Crystal River Unit 3 B 3.6-40 Revision No. 2 l l
| |
| | |
| . . _ __ _ _. __ _. _ ._ ~ ._
| |
| Reactor Building Spray and Containment Cooling Systems B 3.6.6 BASES ACTIONS [.d (continued) The 10 day portion of the Completion Time for Required Action C.1 is based upon engineering judgment. It takes into account the low probability of coincident entry into two Conditions in this LCO coupled with the low probability of an accident occurring during this time. Refer to Section 1.3 for a more detailed discussion of the purpose of the "from discovery of failure to meet the LC0" portion of the Completion Time.
| |
| D_d With two of the required containment cooling trains inoperable, one of the required containment cooling trains The must be restored to OPERABLE status within 72 hours.
| |
| components in this degraded condition (both spray trains are OPERABLE or else Condition E is entered) provide iodine removal capabilities and are capable of providing at least The 100% of the heat removal needs after an accident.
| |
| 72 hour Completion Time was developed taking into account the redundant heat removal capabilities afforded by .
| |
| combinations of the RB Spray System and Containment Cooling System and the low probability of a DBA occurring during
| |
| * this period.
| |
| E.1 and E.2 If the Required Actions and associated Completion Times of Condition C or D of this LC0 are not met, the plant must be To placed in a MODE in which the 1.00 does not apply.
| |
| achieve this status, the plant must be placed in at least '
| |
| The MODE 3 within 6 hours and in MODE 5 within 36 hours.
| |
| 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_d With two RB spray trains or any combination of three or more RB spray and required containment cooling trains inoperable, the unit is in a condition outside the accident analysis.
| |
| Therefore, LCO 3.0.3 must be entered immediately.
| |
| s i
| |
| (continued)
| |
| Crystal River Unit 3 B 3.6-41 Revision No. 2 l - - - - - - - _ - _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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| | |
| Reactor Building Spray and Containment Cooling Systems B 3.6.6 BASES (continued)
| |
| SURVEILLANCE SR 3.6.6.l REQUIREMENTS Verifying the correct alignment for manual, power operated,-
| |
| and automatic valves in the RB spray flow path provides assurance that the proper flow paths will exist for RB Spray System 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. These valves include valves in the main flow paths and the first normally closed valve in a branch line. In lieu of the first normally closed valve in the branch line, credit may be taken for verifying valve position of another valve downstream, providing the isolation of the flow path is achieved. Verifying correct valve alignment of valves immediately downstream of an unsecured valve still assures isolation of the flow path.
| |
| There are several exceptions for valve position verification due to the low potential for these types of valves to be mispositioned. The valve types which are not verified as part of this SR include vent or drain valves (both inside and outside the RB), relief valves outside the RB, instrumentation valves (both inside and outside the RB),
| |
| check valves (both inside and outside the RB), and sample line valves (Inside and outside the RB). A valve that receives an actuation signal is allowed to be in a non-accident position provided the valve will automatically reposition within the proper stroke time. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This SR 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.
| |
| SR 3.6.6.2 ;
| |
| 1 Operating each required containment cooling train fan unit ;
| |
| for 215 minutes ensures that all trains are OPERABLE and that all associated controls are functioning properly. It l also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action.
| |
| The 31 day Frequency was developed considering the known ;
| |
| reliability of the fan units and controls, the two train redundancy available, and the low probability of a significant degradation of the containment cooling trains (continued)
| |
| Crystal River Unit 3 B 3.6-42 Revision No. 2 l
| |
| | |
| Reactor Building Spray and Containment Cooling Systems .
| |
| B 3.6.6 l l
| |
| BASES l
| |
| 1 SURVEILLANCE SR 3.6.6.2 (continued)
| |
| REQUIREMENTS occurring between surveillances and has been shown to be acceptable through operating experience. ;
| |
| I It is preferable to run the fans in slow speed for this SR since this provider additional confidence the post-accident containment cooling train circuitry is OPERABLE.
| |
| * SR 3.6.6.3 Verifying that each RB spray pump's developed head at the flow test point is greater than or equal to the required developed head ensures that spray pump performance has not degraded during the cycle. Flow and differential pressure ,
| |
| are normal tests of centrifugal pump performance required by Section XI of the ASME Code (Ref. 5). Since the RB Spray System pumps cannot be tested with ficw through the spray ,
| |
| headers, they are tested on recirculation flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests ;
| |
| confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The i Frequency of this SR is in accordance with the Inservice Testing Program.
| |
| SR 3.6.6.4 i
| |
| Verifying an emergency design cooling water flow rate of 2 1780 gpm to any 2 of 3 containment cooling system heat ;
| |
| exchangers ensures the design flow rate assumed in the 7 safety analysis is being achieved. The SR verifies that, i with the SW System in the post-accident ES alignment, :
| |
| adequate flow is provided to the heat exchangers to remove the design basis reactor building heat load. The 24 month Frequency is based on the need to perform this Surveillance l under the conditions that apply during a plant outage. ,
| |
| While the cooling units can be aligned to the SW System :
| |
| during normal operations, other critical normal-running SW )
| |
| loads make it impractical to verify accident flow rate to- l the coolers with the plant on-line. On an ES actuation, i these normal-running loads are isolated and the SW flow ;
| |
| (continued)
| |
| Crystal River Unit 3 B 3.6-43 Revision No. 2
| |
| | |
| ! i Reactor Building Spray and Containment Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.4 (continued)
| |
| REQUIREMENTS normally supplied to them re-directed to the post-accident loads. The 24 month Frequency was also considered I
| |
| ' acceptable based upon the existence of other Technical Specification Surveillance Requirements. A degradation in
| |
| ' cooling unit performance between performances of this SR would likely be seen as an increase in RB temperature (monitored once per 12 hours in accordance with SR 3.6.5.1).
| |
| SR 3.6.6.5 and SR 3.6.6.6 '
| |
| These SRs require verification that each automatic R8 spray valve that is not locked, sealed, or otherwise secured in the correct position, actuates to its correct position and that each RB spray pump starts upon receipt of an actual or simulated actuation signal. The 24 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillances were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillances when performed at the 24 month Frequency.
| |
| Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| The SR is modified by a note indicating the SR is not applicable in the identified MODE. This is necessary in order to make the requirements for automatic system response ,
| |
| consistent with those for the actuation instrumentation. I SR 3.6. Q i This SR requires verification that each required containment cooling train actuates upon receipt of an actual or simulated actuation signal. In the event of a LOCA, the air i
| |
| steam mixture density is much higher than normal air density. The units are not designed to handle the full flow rate at this condition. To operate the unit at full flow (motor at high speed) at this condition, will.cause the l motor to overload and trip. To guard the motor from overloading, the volumetric flow rate must be cut l
| |
| l l (continued) l Crystal River Unit 3 8 3.6-44 Revision No. 2 l
| |
| | |
| i Reactor Building Spray and Containme.it Cooling Systems B 3.6.6 ,
| |
| (L'~ BASES 1 l
| |
| ~~ l SURVEILLANCE SR 3.6.6.7 (continued) .
| |
| i REQUIREMENTS approximately in half (motor at low speed).- Thus, this SR i i
| |
| ensures that the motors automatically switch to low speed upon receipt of the containment cooling engineered ;
| |
| safeguards actuation signal. The 24 month Frequency is based on engineering judgment and has been shown to be ,
| |
| acceptable through operating experience. See SR 3.6.6.5 and '
| |
| SR 3.6.6.6, above, for further. discussion of the basis for the 24 month Frequency. l The SR is modified by a note indicating the SR is not applicable in the identified MODE. This is necessary in order to make the requirements for automatic system response !
| |
| consistent with those for the actuation instrumentation. ,
| |
| 1 SR 3.6.6.8 With the containment spray header isolated and drained of i any solution, low pressure air or smoke can be blown through test connections. Performance of this Surveillance demonstrates that each spray nozzle is unobstructed and i provides assurance-that spray coverage of the containment during an accident is not degraded. Due to the passive +
| |
| nr.ture of the design of the nozzles, a test at 10 year intervals is considered adequate to detect obstruction of .
| |
| the spray nozzles. l l
| |
| 3 REFERENCES 1. FSAR, Section 1.4. ~
| |
| : 2. FSAR, Section 14.2.2.5.9.
| |
| : 3. FSAR, Section 6.3.
| |
| : 4. R0-2787 Requirement Outline, Reactor Building Fan >
| |
| ~ Assemblies, Addendum B, February 19, 1971.
| |
| ASME, Boiler and Pressure Vessel Code, Section XI. i 5.- l w.
| |
| Crystal River Unit 3 8 3.6-45 Revision No. 2 i
| |
| l
| |
| | |
| }
| |
| Containment Emergency Sump pH Control 4
| |
| B 3.6.7 8 3.6 CONTAINMENT SYSTEMS q i by B 3.6.7 Containment Emergency Sump pH Control (CPCS)
| |
| BASES BACKGROUND The CPCS raises the pH of water in the containment emergency sump to at least 7.0 following a Design Basis Accident (DBA). In the event of s loss of coolant accident (LOCA),
| |
| the trisodium phosphate dodecahydrate (TSP-C) contained in the CPCS storage baskets will be automatically dissolved in the reactor coolant and BWST inventory lost through the break. The CPCS performs no function during normal plant operations.
| |
| Radiciodine in its various forms is the fission product of primary concern in the~ evaluation of a DBA. It is absorbed by the spray from the containment atmosphere. To reduce the potential for elemental iodine re-evolution, the spray solution during the ECCS recirculation phase is adjusted (buffered) to an alkaline pH. This promotes iodine
| |
| - hydrolysis, in which iodine is converted to nonvolatile forms. TSP-C, because of its stability when exposed to radiation and elevated temperature and its non-toxic nature, 4 is the preferred buffer material. s The TSP-C storage baskets are designed and located to permit the contents of the baskets to be dissolved into the inventory in the RB sump as water level increases post-LOCA.
| |
| To ensure the desired range of pH is achieved, the stainless steel mesh screen storage baskets are located at the 95' elevation of the RB.
| |
| The design of the CPCS was established to provide a spray solution during the ECCS recirculation phase with a pH between 7.0 and 11.0 (Ref. 1). This range of alkalinity was established not only to ensure elemental iodine does not re-evolve, but also to minimize the long-term stress corrosion of mechanical system components that would occur if the acidic borated water were not buffered. The pH range also considers the environmental qualification of equipment in containment that may be subjected to the spray.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.6-46 Amendment No. 149 l l l
| |
| | |
| MFIVs B 3.7.3 8 3.7 PLANT SYSTEMS B 3.7.3 Main Feedwater Isolation Valves (MFIVs)
| |
| BASE 3 BACKGROUND The main feedwater isolation vvves (MFIVs) are designated valves in the Main Feedwatei caw) System which function in conjunction with other equipment to isolate MFW to the steam generators (OTSGs) in accordance with assumptions used in the high energy line break accident analyses.
| |
| At CR-3, the MFIVs for each OTSG consist of the MFW pump suction valve, the main /startup/ low load block valves (in parallel), and the MFW pump discharge cross connect valve between OTSG A and B (Ref. 1). All the OTSG A valves receive a ;ignal to close on low OTSG pressure from EFIC OTSG A MFW isolation automatic actuation logic channels A and B. OTSG B valves similarly receive signals from EFIC OTSG B MFW isolation automatic actuation logic channels A and B. The crossover valve receives closure signals from both channels of EFIC's OTSG A and 0TSG B MFW isolation logics (Ref. 2).
| |
| In addition to the above, the EFIC OTSG A MFW isolation logic trips MFW pump A on a OTSG A low pressure signal.
| |
| 0TSG B EFIC logic trips MFW pump B on OTSG B low pressure.
| |
| j EFIC also provides a trip of the opposite side MFW pump and closure of its suction valve on a single side feedwater l! isolation signal when the crossover valve is open. This logic is enabled by manual key switches which are administrative 1y controlled during times when both OTSGs are being fed from one MFW pump (typically below 55% power).
| |
| This reduces the system pressure on the MFW pump startup and low load block valves and assures these MFIVs can perform their intended function. The tripping of the other train assures main feedwater isolation for the case where the EFIC initiation is for the opposite side from the operating MFW pump.
| |
| This results in several layers of redundancy in that not ,
| |
| l only are the fluid system components (valves, pumps) '
| |
| redundant, but.the automatic closure signals to each component are also redundant.
| |
| (continued) 8 3.7-13 Revision No. 1 Crystal River Unit 3
| |
| .1
| |
| | |
| MFIVs B 3.7.3 BASES (continued) .
| |
| t 1 APPLICABLE Closure of the MFIVs terminates the addition of feedwater to l SAFETY ANALYSES an affected 0TSG. This limits the mass and energy releases i for breaks within containment, reduces cooldown effects, and l reduces the potential for a return to power due to a return to critical following reactor trip.
| |
| The steam line break analyses applicable to the CR-3 plant were performed prior to the design and installation of the Emergency Feedwater Initiation and Control (EFIC) System.
| |
| The EFIC System is safety-grade and supplies the instrumentation and logic for the automatic MFW isolation function. The analysis assumes certain Integrated Control System (ICS) actions including a closure of the MFW block valve on receipt of a reactor trip signal. However, due to the steam line break event sequence, the reactor trip signalwill be preceded by a signal from EFIC to close the MFIV on low OTSG pressure from the affected steam generator. .
| |
| A subsequent evaluation demonstrated that MFIV closure in 34 seconds after the event is initiated is bounded by the FSAR steam line break analysis. Therefore, the use of EFIC in .
| |
| the original safety analysis would have been consistent with the licensing position allowing mitigative functions to be performed by safety-grade systems in accident analysis. For these reasons, the steam line break accident analysis is bounding and remains conservative with respect to tne assumed ICS action.
| |
| The MFIVs satisfy Criterion 3 of the NRC Policy Statement.
| |
| LCO This LC0 ensures that the MFIVs will isolate MFW flow to the OTSGs following a FWLB or a main steam line break. The following valves are addressed by this LCO:
| |
| 0TSG A OTSG B FWV-30 Main block valve FWV-29 FWV-31 Low load block valve FWV-32 FWV-36 Startup block valve FWV-33 FWV-14 MFW pump suction valve FWV-15 FWV-28 MFW cross connect valve l
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| l j
| |
| ~
| |
| (continued)
| |
| . Crystal River Unit 3 8 3.7-14 Revision No. 1
| |
| | |
| MFlVs B 3.7.3 BASES (continued)
| |
| LCO EFIC Channel A (continued) Main FW Isolation Main FW Pump Trip Switch Function EFIC Channel B Main FW Isolation Main FW Pump Trip Switch Functica Two MFIVs in each flow path are required to be OPERABLE.
| |
| The MFIVs are considered OPERABLE when the valves are
| |
| ' capable of automatically closing on an isolation actuation signal. The function of the EFIC Channel A and B manual key switches is part of the OPERABILITY of the MFIVs. The failure of a switch (s) to be in the correct position or to be functional may constitute a condition which renders MFIVs not OPERABLE.
| |
| At least one valve in each flow path must be capable of isolating within the response time assumed in the accident analysis. Refer to the ACTIONS section for a description of what constitutes a flowpath for the purposes of this Specification.
| |
| A MFIV that is closed and deactivated is considered OPERABLE since it is already performing its safety function under an appropriate level of administrative control. Failure to meet the LCO requirements can result in additional mass and !
| |
| energy being released to containment following an SLB or FWLB inside containment.
| |
| APPLICABILITY In MODES 1, 2, and 3, the MFIVs are required to be OPERABLE in order to limit the amount of available fluid that would be added to containment in the case of a secondary system pipe break inside containment. This need to limit inventory '
| |
| is based on the energy associated with secondary coolant during these MODES of operation. ,
| |
| In MODES 4, 5, and 6, 0TSG energy is low. Therefore, the i
| |
| ' MFIVs are not required for isolation of potential high '
| |
| energy secondary system pipe breaks in these MODES.
| |
| (continued) 8 3.7-15 Revision No. 1 l Crystal River Unit 3 L _ _______ _ _ _. . _ - _ _ _ _ _ _ _ _
| |
| | |
| MFIVs B 3.7.3 BASES (continued) (a ACTIONS The ACTIONS table is modified by three Notes. Note 1 indicates that separate Condition entry is allowed for each flowpath. A flowpath is defined as any connected system piping, beginning upstream of the MFW pump suction valve, through which feedwater can travel to an OTSG. Note 2 allows MFW flow paths to be un-isolated under administrative 1 control. This Note provides for plant cooldown with MFW in its normal operating configuration, despite the MFIV being inoperable. The risk of not having redundant isolation capability during this brief transition period was i considered acceptable when compared to the risks of an 1 abnormal cooldown or MFW transient. Note 3 limits operation !
| |
| with a MFW start-up control valve isolated, consistent with l Condition D of this Specification. This limit is necessary l since other MFIV flow paths may be isolated in accordance I with the Required Actions of Condition A and B such that the startup flow path is also isolated.
| |
| A.1 and A.2 With one or more MFW flow paths with one MFIV inoperable, action must be taken to restore the affected valves to OPERABLE status, or to isolate the affected flow path within ,
| |
| 72 hours. When isolated, the valves are performing their i safety function.
| |
| The 72 hour Completion Time takes into account the redundancy afforded by the remaining OPERABLE valve in the flowpath, the MFW pump trip feature provided on low OTSG pressure, and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 72 hour Completion Time is reasonable, based on operating experience.
| |
| Isolated MFW flow paths must be verified to be in the correct position on a periodic basis. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of valve status indications available in the control room, and other administrative controls, to ensure that these valves are closed or .
| |
| isolated.
| |
| (continued)
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| Crystal River Unit 3 B 3.7-16 Revision No. 1 i
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| | |
| ~~
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| MFIVs B 3.7.3 BASES l
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| ACTIONS B_.1 and 8.2
| |
| ' (continued)
| |
| With one or more flow paths not capable of isolating within the required isolation time, action must be taken to restore one valve to within theThe required Requiredclosure time Actions are the or sameto isolate the affected flow path.
| |
| as those specified in Condition A of this Specif The 24 hour Completion Time reflects analysis that demonstrated reduced stroke times will not likely challengeH the containment analysis.
| |
| represented by this Condition is concidered more serious than Condition A.
| |
| When in Condition B, the Required Actions of Condition A are also applicable.
| |
| C_d With two inoperable valves in the same flow path, valveUnder these isolation capability has been lost.
| |
| at least one of the affected valves in eachThe flow path must 8 hour be restored to OPERABLE status within 8 hours.
| |
| Completion Time is reasonable, based on operating experience.
| |
| ACTIONS Q.d (continued) With a startup block valve (FWV-33, -36) in one or more flow paths inoperable, action must be taken to restore In this the affected valves Condition, to OPERABLE valve closure or isolationstatus is notwithin 72 hours.
| |
| an acceptable alternative action because the ICS controlled startup control valves are necessary to provide ar.d control mainClosure feedwater following a reactor trip.
| |
| block valves would preclude this function (continued) 1 Revision No. 1 8 3.7-17 Crystal River Unit 3 b ___
| |
| | |
| , ~-
| |
| i MFlVs B 3.7.3 BASES ' ,.
| |
| l ,
| |
| ACTIONS D_:.1 (continued)
| |
| The 72 hour Completion Time takes into account the redundancy afforded by the remaining OPERABLE valve in the flowpath, the MFW pump trip feature provided on low OTSG pressure, and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths.
| |
| E.1 and E.2 If the MFIVs cannot be restored to OPERABLE status, or I closed, or isolated within the associated Completion Time, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this status, the plant must be placed in ;
| |
| at least MODE 3 within 6 hours and in MODE 4 within i 12 hours. The allowed Completion Times are reasonable, i based on operating experience, to reach the required plant l conditions from full power conditions in an orderly manner ;
| |
| and without challenging plant systems. l
| |
| [
| |
| SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies that MFIV closure time is within the acceptance criteria in the Inservice Testing Program. In order to be consistent with the safety analysis, at least one valve in each flow path must have the capability to meet the 34 second response time for MFW isolation. This Surveillance is normally performed upon returning the plant to operation following a refueling outage. The MFIVs should not be tested at power since even a part stroke exercise increases the risk of a valve closure, and the risk of a plant transient with the plant generating power. As these valves are not tested at power, they are exempt from the ASME Code, Section XI (Ref. 2) quarterly valve stroke requirements.
| |
| This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This alle.,s delaying testing until MODE 3 in order to establish the test conditions most representative of those under which the acceptance criterion was generated.
| |
| (continud) 8 3.7-18 Revision No. 1 Crystal River Unit 3 i
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| i
| |
| | |
| MFlVs i
| |
| B 3.7.3 l ,
| |
| BASES l
| |
| SURVEILLANCE SR 3.7.3.1 (continued)
| |
| REQUIREMENTS The Frequency for this SR is in accordance with the Inservice Testing Program. Operating experience has shown that these components usually pass the Surveillance when performed at the this Frequency.
| |
| REFERENCES 1. FSAR, Section 10.2.1.2.
| |
| : 2. FSAR, Section 7.2.4.2.
| |
| : 3. ASME, Boiler and Pressure Vessel Code, Section XI.
| |
| 8 3.7-18A Revision No. 1 Crystal River Unit 3 4
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| i
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| i !
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| (~',1 1
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| l 1
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| i 1
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| i i
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| THIS PAGE INTENTIONALLY LEFT BLANK l 1
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| l l
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| l l
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| Crystal River Unit 3 B 3.7-18B Revision No. 1 i
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| I
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| | |
| TBVs B 3.7.4 B 3.7 PLANT SYSTEMS B 3.7.4 Turbine Bypass Valves (TBVs)
| |
| BASES BACKGROUND The TBVs provide a method for cooling the plant to Decay Heat Removal (DHR) System entry conditions via the main condenser. Following an accident, this is done in conjunction with the Emergency Feedwater (EFW) System, providing flow from the EFW tank (EFT-2). There are four air-operated TBVs, two per steam generator (OTSG). The TBVs are located downstream of the main steam isolation valves (MSIVs) and other remote power-operated isolation valves to permit the valves to be isolated if necessary.
| |
| Each TBV is sized to pass 3.75% of rated main steam flow (418,500 lbm/hr at normal steam conditions) and combined, the valves are capable of cooling down the plant at the design rate of 100*F/hcur (Ref.1). All four TBVs are controllable from the Main Control Board as well as local manual at the valves themselves. The TBVs are not available following a loss of offsite power (LOOP) due to the loss of the Circulating Water System and eventually the condenser. However, the licensing basis for the Steam Generator Tube Rupture (SGTR) accident does not require a LOOP be assumed.
| |
| In the event of a LOOP, the Atmospheric Dump Valves (ADVs) would be relied upon to perform the secondary side heat removal function. Analysis performed during initial licensing demonstrated that the ADVs can be used to cool down the plant and still meet 10 CFR 100 limits, although I
| |
| the offsite dose would be significantly higher than those associated with a TBV-based cooldown.
| |
| The ADVs are air-operated valves equipped with pneumatic controllers to permit control of the cooldown rate. The valves are provided with a backup supply of bottled
| |
| : i. nitrogen. Manual valve alignment is necessary to use this i nitrogen to operate the ADVs on loss of pressure in the normal instrument air supply. The nitrogen supply is sized l to provide sufficier.t pressurized gas to operate the ADVs i for four hours, the time required to cope with a Station l Blackout event. This also provides the capability to I
| |
| operate the ADVs to minimize the radiological consequences of a Steam GenGrator Tube Rupture with a LOOP (a beyond design and licensing basis scenario).
| |
| (continued)
| |
| Crystal River Unit 3 8 3.7-19 Revision No. 12
| |
| | |
| TBVs B 3.7.4 BASES (continued)
| |
| [
| |
| APPLICABLE The TBVs are assumed to be used by the operator to cool down SAFETY ANALYSIS the plant following the design basis SGTR event (Ref. 2).
| |
| The initiating event is a double-ended rupture of a single OTSG tube, resulting in a primary to secondary leak rate of 435 gpm; too large for normal makeup to compensate. RCS pressure decreases to the Reactor Protection System (RPS) low-pressure trip setpoint and the reactor is automatically shut down. In turn, the turbine trips and the OTSGs are isolated. Prior to operator actions to cool down the unit, the TBVs, ADVs, and the main steam safety valves (MSSVs) are assumed to operate automatically to relieve steam and maintain the OTSG's pressure and temperature below the design value. This is assumed to occur over a period of one minute, 8 minutes following initiation of an event.
| |
| At 9 minutes into the event, the analysis assumes secondary side pressure has decreased to below the ADV and MSSV setpoints and that the direct release to the environment is terminated. From this point in time until 8 hours after the start of the event, both OTSGs are continuously steamed to the condenser in order to remove decay heat and cooldown/
| |
| de-pressurize the RCS to DHR System entry conditions. The analysis assumes all four TBVs are available to perform this function. At 8 hours into the event, offsite radioactivity releases are terminated as OHR is assumed to be in operation.
| |
| The proper operation of the TBVs allows both OTSGs, both the faulted and intact (assumed to have a 1 gpm primary to secondary leak rate), to be steamed to the condenser. This is significant in terms of offsite dose consequences resulting from the SGTR. A gas-liquid partition factor for iodine of 1.0 E-4 was assumed for releases occurring through the condenser. Releases directly to the atmosphere assume a partition factor of 1.0. Offsite doses calculated from the event are directly proportional to the value assumed for the partition factor. Thus, proper operation of the TBVs is necessary to maintain dose consequences associated with a SGTR to a minimum.
| |
| The TBVs satisfy Criterion 3 of the NRC Policy Statement.
| |
| (continued)
| |
| Crystal River Unit 3 8 3.7-20 Revision No. 12
| |
| | |
| l TBVs L B 3.7.4 j_ BASES (continued) 1
| |
| ! LCO Each TSV (two per OTSG) is required to be OPERABLE for this !
| |
| 4 LCO. Failure to meet the LCO can result in the inability to cooldown to DHR System entry conditions following a SGTR
| |
| -event while maintaining offsite doses to a minimum. A TBV i is considered OPERABLE when it is capable of providing a
| |
| : controlled relief of the main steam flow, and is capable of j fully opening and closing when manually commanded to do so ;
| |
| , by the operator. ,
| |
| i
| |
| , APPLICABILITY In MODES 1, 2, and 3, the pressures and temperatures in the '
| |
| f RCS are high enough to initiate a SGTR and require secondary i side depressurization. Therefore, the TBVs are required to
| |
| ! be OPERABLE in these MODES. ,
| |
| l .
| |
| , In MODES 4, 5, and 6, a SGTR is not a credible event due to ,
| |
| the reduced stresses in the generator tubes and low driving l head for release to the environment.
| |
| 4 ,
| |
| 4 i ACTIONS A.1 and A.2 ,
| |
| .j j With one or more TBV(s) inoperable, action must be taken to restore all TBVs to OPERABLE status. The 7 day Completion. ,
| |
| Time is reasonable to repair inoperable TBVs, based on the :
| |
| l availability of other means of depressurizing the RCS i i following a SGTR, and the low probability of this event t occurring during the 7 day period. As an alternative to restoring the TBV(s) to OPERABLE status, the associated 0TSG J j ADV must be verified to be OPERABLE within 7 days. This 1 entails verifying that SR 3.7.4.1 is " current" for the ADV, l or performing the Surveillance. Reliance on the ADV to
| |
| ; satisfy the ACTIONS of this Specification is considered i acceptable based on the early analysis.
| |
| i B.1 and B.2 If the TBVs cannot be restored to OPERABLE status within the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours, and in MODE 4 within 12 hours. The allowed I
| |
| l (continued) ,
| |
| i Crystal' River Unit 3 B 3.7-21 Revision No. 12
| |
| %- ,__ _ _ _ . . - . _ _ - _ . , , _ - . . - . - _ __ - . - , - - - . - .i
| |
| | |
| TBVs !
| |
| B 3.7.4 l
| |
| .e .
| |
| BASES ACTIONS 8.1 and 8.2 (continued)
| |
| Completion Times are reasonable, based on operating i experience, to reach the required plant conditions from full l power conditions in an orderly manner and without ,
| |
| challenging plant systems.
| |
| SURVEILLANCE SR 3.7,4.1 REQUIREMENTS To perform a controlled cooldown of the RCS, the TBVs must.
| |
| be able to be opened remotely and throttled through their ,
| |
| full range. This SR ensures that the TBVs are tested through a full control cycle at least once per fuel cycle.
| |
| Performance of inservice testing or use of a TBV during a plant cooldown satisfies this requirement'. Operating '
| |
| experience has shown that.these components usually pass the :
| |
| Surveillance when performed at the 24 month Frequency. l Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| REFERENCES 1. FSAR, Section 10.2.1.4.
| |
| : 2. FSAR, Section 14.2.2.2.
| |
| Crystal River Unit 3 8 3.7-22 Revision No. 12
| |
| | |
| Spent Fuel Pool Boron Concentration B 3.7.14 BASES' SURVEILLANCE SR 3.7.14.1 (continued)
| |
| REQUIREMENTS Operating experience has shown significant differences between boron measured near the top of the pool and that measured elsewhere. As long as this SR is met, the analyzed t events are fully bounded. The 7 day Frequency is acceptable because no major replenishment of pool water is expected to take place over this period of time. e REFERENCES 1. Criticality Safety Analysis of the Crystal River Unit 3 Pool A Spent Fuel Storage Rack, S. E. Turner, ,
| |
| Southern Science, SS-162.
| |
| : 2. Technical Specification Change Request 175, dated October 31, 1989.
| |
| : 3. NRC Safety Evaluation Report for Amendment 134 to CR-3 Operating License, dated April 16, 1991.
| |
| i l ,
| |
| I l
| |
| Crystal River Unit 3 B 3.7-71 Amendment No. 149
| |
| | |
| Spent Fuel Assembly Stora e l B 3.7. 5 i
| |
| . 1 B 3.7 PLANT SYSTEMS ;
| |
| 8 3.7.15 Spent Fuel Assembly Storage l
| |
| BASES BACKGROUND This document describes the Bases for the Spent Fuel Assembly Storage which imposes storage requirements upon irradiated and unirradiated fuel assemblies stored in the fuel storage pools containing high density racks. The storage areas, which are part of the Spent Fuel System, governed by this Specification are:
| |
| : a. Fuel storage pool "A" and
| |
| : b. Fuel storage pool "B".
| |
| In general, the function of the storage racks is to support and protect :iew and spent fuel from the time it is placed in the storage area until it is shipped offsite.
| |
| Spent fuel is stored underwater in either fuel storage pool A or B. Only fuel pool A has the capability to store failed fuel in containers. Spent fuel pool A features high density poison storage racks with a 10 1/2 inch center-to-center distance capable of storing 542 assemblies. Fuel pool A is -
| |
| capable of storing fuel with enrichments up to 5.0 weight percent U-235 (Ref. 1) without exceeding the criticality criteria of Reference 3 providing the fuel has sufficient burnup.
| |
| Spent fuel pool B also contains high density racks separated into 2 regions. The racks in Region I have a 10.60 inch center-to-center spacing capable of storing 174 assemblies.
| |
| The high density racks in Region 2 have 9.17 inch center-to-center distance capable of storing 641 assemblies. Fuel pool B is capable of storing fuel with enrichments up to 5.0 weight percent U-?35 (Ref. 2) without exceeding the criticality criteria of Reference 3, providing the fuel has sufficient burtup and required storage configuration.
| |
| It should be noted that the maximum enrichment limits are actually nominal values. The tolerance of fuel supplied by i DOE is i 0.013 weight percent. Thus, it is possible to have fuel with an initial enrichment slightly in excess of the stated limit. This is accounted for in the criticality analysis and is therefore acceptable. l (continued)
| |
| Crystal River Unit 3 B 3.7-72 Revision No. 11 i
| |
| i
| |
| | |
| Spent Fuel Assembly Storage j B 3.7.15 BASES BACKGROUND Both of the spent fuel pools are constructed of reinforced 1 (continued) concrete and lined with stainless steel plate. They are t located in the fuel handling area of the auxiliary building ,
| |
| (Ref. 2).
| |
| New fuel storage requirements are addressed in Section 4.0,
| |
| " Design Features".
| |
| )
| |
| APPLICABLE The function of the spent fuel storage racks are to support SAFETY ANALYSES and protect spent fuel assemblies from the time they are placed in the pool until they are shipped offsite. The spent fuel assembly storage LCO was derived from the need to 3 establish limiting conditions on fuel storage to assure sufficient safety margin exists to prevent inadvertent criticality. The spent fuel assemblies are stored entirely underwater in a configuration that has been shown to result in a reactivity of less than 0.95 under worse case conditions (Ref. I and 2). The spent fuel assembly enrichment requirements in this LC0 are required to ensure inadvertent criticality does not occur in the spent fuel pool.
| |
| Inaovertent criticality within the fuel storage area could i
| |
| result in offsite radiation doses exceeding 10 CFR 100 limits.
| |
| The spent fuel assembly storage satisfies Criterion 2 of the NRC Policy Statement.
| |
| LCO Limits on the irradiated fuel assembly storage in high density 1
| |
| * racks were established to ensure the assumptions of the criticality safety analysis of the spent fuel pools is maintained.
| |
| Limits on initial fuel enrichment and burnup for spent fuel stored in pool A have been established. Two limits are defined:
| |
| : 1. Initial fuel enrichment must be less than or equal to 5.0 weight percent U-235, and (continued)
| |
| Crystal River Unit 3 8 3.7-73 Revision No. 11
| |
| | |
| Spent Fuel Assembly Storage I B 3.7.15 i
| |
| I BASES LC0 2. For spent fuel with initial enrichment less than or (continued) equal to 5.0 weight percent and greater than or equal to j 3.5 weight percent, fuel burnup must be within the limits specified in Figure 3.7.15-1. (Figure 3.7.15-1 presents required fuel assembly burnup as a function of initial enrichment.) (
| |
| l Fuel enrichment limits are based on avoiding inadvertent criticality in the spent fuel pool. The CR-3 spent fuel storage system was initially designed to a maximum enrichment of 3.5 weight percent. Enrichments of up to 5.0 weight percent are permissible for storage in spent fuel pool A as I long as the fuel burnup is sufficient to limit the worst case J reactivity in the storage pool to less than 0.95. Fuel burnup ;
| |
| reduces the reactivity of the fuel due to the accumulation of fission product poisons. Reference 1 documents that the required burnup varies linearly as a function of enrichment with 10500 megawatt days per metric ton uranium (Mwd /mtV) required for fuel with 5.0 weight percent enrichment and 0 burnup required for 3.5 weight percent enriched fuel.
| |
| Similar types of restrictions have been established for Pool B.
| |
| : 1. Initial fuel enrichment must be 1 5.0 weight percent U-235, and
| |
| : 2. For Region 1, fuel with initial enrichment 15.0 weight percent and 2 2.08 weight percent, fuel burnup must be within the limits specified in Figure 3.7.15-2 and arranged in a required checkerboard configuration with new fuel or burned fuel of s 5.0 weight percent, and
| |
| : 3. For spent fuel with an initial enrichment of s 5.0 weight percent and 21.63 weight percent in Region 2, fuel burnup must be within the limits specified in Figure 3.7.15-3. (Figure 3.7.15-3 presents required fuel assembly burnup as a function of initial enrichment.)
| |
| The LC0 allows compensatory loading techniques, specified in the FSAR and applicable fuel handling procedures, as an alternative to storing fuel assemblies in accordance with Figures 3.7.15-1 and 3.7.15-2, and figure 3.7.16-3. This is acceptable since these loading patterns assure the same degree of subtriticality within the pool.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.7-74 Revision No. 11 i
| |
| | |
| 1 Spent fuel Assembly Storage 1 B 3.7.lS l l
| |
| 7 i BASES (continued) ' ,
| |
| APPLICABILITY In general, limiting fuel enrichment of stored fuel prevents inadvertent criticality in the storage pools. Inadvertent criticality is dependent on whether fuel is stored in the ,
| |
| pools and is completely independent of plant MODE.
| |
| Therefore, this LCO is applicable whenever any fuel assembly is stored in high density fuel storage locations.
| |
| ACTIONS A.1 Required Action A.1 is modified by a Note indicating LC0 3.0.3 does not apply. Since the design basis accident of concern in this Specification is an inadvertent criticality, and since the possibility or consequences of this event are independent of plant MODE, there is no reason to shutdown the plant if the LC0 or Required Actions cannot be met. .
| |
| When the configuration of fuel assemblies stored in the spent ,
| |
| fuel pool is not in accordance with Figure 3.7.15-1, . Figure 3.7.15-2, Figure 3.7.15-3, or the FSAR, immediate action must be taken to make the necessary fuel assembly movement (s) to bring the configuration into compliance. The Immediate Completion Time underscores the necessity of restoring spent fuel pool irradiated fuel loading to within the initial i assumptions of the criticality analysis.
| |
| The ACTIONS do not specify a time limit for completing l
| |
| movement of the affected fuel assemblies to their correct location. This is not meant to allow an unnecessary delay in resolution, but is a reflection of the fact that the complexity of the corrective actions is unknown.
| |
| r (continued)
| |
| Crystal River Unit 3 8 3.7-75 Revision No. 11
| |
| | |
| J Spent Fuel Assembly Storage
| |
| ; B 3.7.15 7
| |
| BASES (continued) i SURVEILLdCE SR 3.7.15.1 REQUIREMENTS Verification by administrative means that initial enrichment 4
| |
| and burnup of fuel assemblies in accordance with Figure 3.7.15-1 and Figure 3.7.15-2, and Figure 3.7.15-3 is required prior to storage of spent fuel in storage pool A or pool B (as i applicable). This surveillance ensures that fuel enrichment limits, as specified in the criticality safety analysis (Ref.
| |
| 2), are not exceeded. The surveillance Frequency (prior to storage in high density region of the fuel storage 2001) is appropriate since the initial fuel enrichment anc, burnup cannot change after removal from the core.
| |
| 1 REFERENCES 1. Criticality Safety Evaluation of the Pool A Spent Fuel l Storage Racks in Crystal River Unit 3 with Fuel of 5.0%
| |
| Enrichment, S. E. Turner, Holtec Report HI 931111, 4 December 1993.
| |
| : 2. Crystal River Unit 3 Spent Fuel Storage Pool B Criticality Analysis, W. A. Wittkopf, L. A. Hassler, B&W Fuel Company, BAW-2209P, October 1993. ,
| |
| : 3. NUREG 0800, Standard Review Plan, Section 9.1.1 and 9.1.2, Rev.2, July 1981.
| |
| : 4. 10 CFR 100.
| |
| : 5. CR-3 FSAR, Section 3.6. I i
| |
| Crystal River Unit 3 8 3.7-76 Revision No. 11 i
| |
| | |
| I DC Sources-Operating 8 3.8.4 N
| |
| l B 3.8 ELECTRICAL POWER SYSTEMS l B 3.8.4 DC Sources-0perating BASES BACKGROUND The CR-3 station DC electrical power system provides the i l emergency diesel generator (EDG) with initial field flash i l
| |
| and control power. It also provides both motive and control !
| |
| )
| |
| power to selected safety related equipment and is the ;
| |
| preferred AC vital bus power (via the inverters). The ;
| |
| design and construction of the CR-3 electrical system ;
| |
| preceded 10 CFR 50 Appendix A. However, the general design :
| |
| criteria (GDCs) issued in 1971 were considered in the design and construction. The electric power system for CR-3 is in compliance with the intent of 10 CFR 50 Appendix A, GDC 17, !
| |
| l Electric Power Systems (Ref. 1), in that it is designed to 3 have sufficient independence, redundancy, and testability to '
| |
| perform its safety functions, assuming a single failure.
| |
| The DC electrical power system also conforms to the .
| |
| recommendations of Regulatory Guide 1.6 (Ref. 2) and l IEEE-308 (Ref. 3).
| |
| The 250/125 VDC electrical power system consists of two l independent and redundant safety related Class 1E DC i l electrical power subsystems (Train A and Train B). Each .i
| |
| ! subsystem consists of two 125 VDC batteries, the associated i l battery charger for each battery, and all the associated j contral equipment and interconnecting cabling.
| |
| The 250 VDC source is obtained by use of two 125 VDC batteries connected in series. Additionally, there is one spare battery charger per subsystem, which provides backup ;
| |
| service in the event that one of the normally aligned ;
| |
| battery chargers is out of service. The spare battery !
| |
| charger meets the requirements for independence and redundancy between subsystems and as such, may be substituted for one of the preferred chargers for the ,
| |
| , purposes of satisfying this LCO. ,
| |
| t'
| |
| ! During normal operation, the 250/125 VDC load is powered from the battery chargers with the batteries floating on the
| |
| ; system. In the event of a loss of normal power to the !
| |
| ! battery charger, the DC loads are automatically powered from the station IE batteries. l i
| |
| ; i
| |
| ,. (continued) 1 i
| |
| 5 Crystal River Unit 3 B 3.8-39 Revision 8 '
| |
| | |
| 1 i
| |
| DC Sources-0perating ,
| |
| B 3.8.4 i BASES
| |
| . BACKGROUND The Train A and Train B DC electrical power subsystems (continued) provide the control power for their associated Class IE AC power load group, 4160 V switchgear, and 480 V load centers.
| |
| The DC electrical power subsystems also provide DC electrical power to the inverters, which in turn power the AC vital buses.
| |
| The DC power distribution system is described in more detail in the Bases for LC0 3.8.9, " Distributions System-Operating," and LCO 3.8.10 " Distribution ,
| |
| Systems-Shutdown. "
| |
| l Each battery has adequate storage capacity to carry the required loads-continuously for at least 2 hours and to j perform three complete cycles of intermittent loads .
| |
| discussed in the FSAR, Chapter 8 (Ref. 4).
| |
| Each 250/125 VDC battery is separately housed in a ,
| |
| ventilated room apart from its charger and distribution '
| |
| centers. Each subsystem is located in an area separated ,
| |
| physically and electrically from the other subsystem to ;
| |
| ensure that a single failure in one subsystem does not cause '
| |
| a failure in a redundant subsystem. There is no shared i '
| |
| equipment between redundant Class IE subsystems, such as '
| |
| batteries, battery chargers, or distribution panels. !
| |
| The batteries are rated at 1708 amp-hours. This time-current capacity is based on the discharge of 116 cells from the fully charged condition down to 1.81 volts per cell (average of all cells) at maximum discharge. The minimum !
| |
| cell voltage requirement corracoonds to a total minimum 1
| |
| , output of 105 volts per battery bank at 77'F (Ref. 4). '
| |
| The Train A.and Train 8 DC electrical power subsystems have ,
| |
| ample power output capacity for the steady state operation of connected loads required during normal operation, while at the same time maintaining its battery bank fully charged.
| |
| Each battery charger also has sufficient capacity to restore '
| |
| the battery from the design minimum charge to its fully charged state within 24 hours while supplying normal steady state loads discussed in the FSAR, Chapter 8 (Ref. 4).
| |
| (continued) <
| |
| Crystal River' Unit 3 8 3.8-40 Revision 8
| |
| , , .. _ _______- U
| |
| | |
| i
| |
| : i i
| |
| DC Sources-Operating
| |
| * B 3.8.4 (
| |
| i
| |
| ; BASES (continued) !
| |
| J I
| |
| APPLICABLE -
| |
| The initial conditions of Design Basis Accident (DBA) and l i SAFETY ANALYSES transient analyses in the FSAR, Chapter 6 (Ref. 6) and i l Chapter 14 (Ref. 7), assume that Engineered Safeguards (ES) ;
| |
| i . systems are OPERABLE. The DC electrical power system provides normal and emergency DC electrical power for the '
| |
| i EDGs, emergency auxiliaries, and control and switching -
| |
| i during all MODES of operation. i The OPERABILITY of the DC electrical power subsystems is consistent with the initial assumptions of the accident '
| |
| analyses and the design basis of the plant. This includes maintaining at least one DC electrical power subsystem i 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. [
| |
| DC electric power subsystems satisfy Criterion 3 of the NRC i Policy Statement. ,
| |
| LC0 Two DC electric power subsystems Are required to be OPERABLE !
| |
| in order to ensure the availability of the required power to ;
| |
| shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (A00) or a :
| |
| postulated DBA. Each DC electrical power subsystem (i.e. ;
| |
| train) consists of two batteries, a battery charger for each ,
| |
| battery and the corresponding control equipment and !
| |
| interconnecting cabling within the train. Loss of one DC -
| |
| electrical power subsystem (train) does not prevent the minimum safety function from being performed (Ref. 4). !
| |
| i An OPERABLE DC electrical power subsystem requires both ;
| |
| batteries and their respective required chargers to be ;
| |
| operating and connected to the associated DC buses.
| |
| APPLICABILITY Two DC electrical power subsystems are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that: :
| |
| (continued)
| |
| Crystal River Unit 3 B 3.8-41 Revision B
| |
| | |
| DC Sources--Operating B 3.8.4 l
| |
| BASES
| |
| { I J
| |
| APPLICABILITY a. Acceptable fuel design limits and reactor coolant (continued) pressure boundary limits are not exceeded as a result of A00s or abnon.al transients; and
| |
| : b. Adequate core cooling is provided, and containment integrity and other vital functions are maintained in the event of a postulated DBA.
| |
| DC electrical power requirements for MODES 5 and 6 are addressed in the Bases for LC0 3.8.5, "DC Source s --Shutdown. "
| |
| ACTIONS ad In Condition A, one safety system train is no longer capable of completely responding to an event (single failure protection is lost). Additionally, there is an increased potential for a loss of the associated DC buses during normal operation. It is therefore imperative that the operator's attention focus on stabilizing the plant in order to minimize the potential for complete loss of DC power to the affected train.
| |
| If one of the required DC electrical power subsystems is inoperable (e.g., inoperable battery, inoperable required battery charger (s), or inoperable battery charger and associated inoperable battery), the remaining DC electrical power subsystem has the capacity to support a safe shutdown and to mitigate an accident condition. However, a subsequent worst-case single failure would result in the complete loss of tne remaining 250/125 VDC electrical power subsystems with attendant loss of ES functions. Therefore, continued power operation is limited to 2 hours. The 2 hour Completion Time is based on the recommendations of Regulatory Guide 1.93 (Ref. 8) and reflects a reasonable time to assess plant status as a result of the inoperable DC electrical power subsystem and, if the DC electrical power subsystem is not restored to OPERABLE status, to prepare for a safe and orderly plant shutdown.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.8-42 Revision 8
| |
| | |
| DC Sources-Operating 8 3.8.4 BASES
| |
| . ACTIONS B.1-and 8.2 (continued)
| |
| If the inoperable DC electrical power subsystem cannot be restored to OPERABLE status within the~ associated Completion Time, the plant must be placed in a MODE in which the LC0 does not apply. To achieve this status, the plant must be placed in.at least MODE 3 within 6 hours and in MODE 5 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. -The 36 hour Completion Time for placing the plant in MODE 5 is also consistent with the recommendations of Regulatory Guide 1.93 (Ref. 8).
| |
| s SURVEILLANCE SR 3.8.4.1 REQUIREMENTS
| |
| .; Verifying battery. terminal voltage while the battery is on i' float charge helps to ensure the effectiveness of the charging system and the ability of the batteries to perform t
| |
| , their intended function. A 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 based on the nominal design voltage of the battery and are :
| |
| , consistent with the initial voltages assumed in the battery i sizing calculations. The 7 day Frequency is consistent with manufacturer recommendations and IEEE-450 (Ref. 9). .
| |
| L SR 3.8.4.2 A visual inspection to detect corrosion of the battery cells ;
| |
| and connections provides an indication of physical damage or j abnormal deterioration that could potentially affect battery j performance. The visual inspection for corrosion is not :
| |
| in+ ended to require removal of and inspection under each t terminal connection. The removal of visible corrosion is a .
| |
| preventive maintenance activity. The presence of visible-corrosion does not necessarily represent a failure of this '
| |
| SP, provided visible corrosion is removed during performance !
| |
| of SR 3.8.4.2. l (continued) i Crystal River Unit 3 8 3.8-43 Revision 8 I
| |
| l
| |
| | |
| DC Sources-Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.2 (continued)
| |
| REQUIREMENTS As an alternative to the visual inspection, the option is provided to measure connection resistance of each inter-cell, inter-rack, inter-tier, and terminal connection. This verification provides a more conclusive determination of battery OPERABILITY than provided by the visual. If the battery meets the acceptance criteria for connecticn resistance, it is OPERABLE, regardless of the amount of visible corrosion present at the terminals and connectors.
| |
| The acceptance criteria established for connection resistance are established based upon the ceiling value established by the manufacturer.
| |
| The 92 day Frequency for these inspections is considered acceptable based on operating experience related to detecting corrosion trends.
| |
| SR 3.8.4.3 Visual inspection of the battery cells, cell plates, and ,
| |
| battery racks provides an indication of physical damage or i abnormal deterioration that could potentially degrade battery performance.
| |
| The 18 month Frequency is based on engineering judgment, considering the desired plant conditions needed to perform the Surveillance. Operating experience has shown the SR is typically passed when performed at the 18 month Frequency.
| |
| Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| i 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 provide an I indication of physical damage or abnormal deterioration that could indicate degraded battery condition. The anticorrosion material is used to help ensure good ,
| |
| electrical connections and to reduce terminal deterioration.
| |
| J (continued) h Crystal River Unit 3 B 3.8-44 Revision 8 !
| |
| | |
| . -._ ._~.-.-.-....-.-.-.- .--.-. - ...-. ---..-..._- .. _-
| |
| I DC Sources--Operating B 3.8.4 '
| |
| i BASES SURVEILLANCE SR 3.8.4.4 and SR 3.8.4.5' (continued) ,
| |
| I REQUIREMENTS "
| |
| The connection resistance acceptance criteria of SR 3.8.4.5
| |
| ! are established based upon the ceiling value established by i the manufacturer. i 1 The 18 month Frequency of the Surveillance is based.on engineering judgment, considering the desired plant conditions needed to perform the Surveillance. Operating experience has shown the SR is typically passed when performed at the 18 month Frequency. Therefore, the l Frequency was concluded to be acceptable from a reliability standpoint.
| |
| SR 3.8.4.6 This SR verifies that each battery charger be capable of ;
| |
| supplying 190 amps and 2125 V for 2 8 hours. These !
| |
| requirements are based on the design capacity of the chargers (Ref. 4) less some margin for testing. This allows j the SR to verify, to the extent practical, the design current output of the' charger without exceeding the design -!
| |
| rating of 200 amps. According to Regulatory Guide 1.32 l (Ref.10), the battery charger supply capacity is based on !
| |
| the largest combined demands of the various steady state loads and the charging capacity needed to restore the t battery from the design minimum charge state to the fully charged state, irre:pective of the status of the plant '
| |
| during these demand occurrences. The CR-3 1E battery !
| |
| charger sizing calculations indicate a current of ,
| |
| approximately 100 amps is adequate to perform this function.
| |
| Thus, the minimum reqaired charging current and duration .
| |
| ensure that these requirements are satisfied, with 1 substantial margin. i The Fiequency is acceptable, considering the plant !
| |
| conditions needed to perform the test and the other ;
| |
| administrative controls which ensure adequate charger .
| |
| performance during the 18 month interval. !
| |
| (continued) i Crystal River Unit 3 B 3.8-45 Revision 8 ]
| |
| -l
| |
| | |
| _ __ . _ _ _ . _ _ _ ._ .__ _ . _ _ _ _ _ .. _ _ _ _ . _ _ . _ ~ _ . _ _ _ _ _ _ _
| |
| DC Sources-Operating B 3.8.4
| |
| ,n BASES
| |
| (
| |
| l SURVEILLANCE SR 3.8.4.7 l REQUIREMENTS l A battery service test is a special as-found test of the battery capability. It is performed to verify the design ;
| |
| requirements (battery duty cycle) of the DC electrical power i
| |
| system. The discharge rate and test length correspond to the design duty cycle requirements specified in Reference 12.
| |
| The 24 month Frequency meets the intent of the recommendations of Regulatory Guide 1.32 (Ref. 10) and Regulatory Guide 1.129 (Ref.11), which state that the ,
| |
| battery service test should be performed during refueling '
| |
| i operations, or at some other outage.
| |
| This SR is modified by two Notes. Note 1 allows the performance of a modified performance discharge test in lieu of a service test once per 60 months.
| |
| 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 4 to determining its percentage of' rated capacity. The modified performance discharge test shall satisfy the requirements of both the service test and the performance test. Initial conditions for the modified performance discha ge test should be identical to those specified for a i
| |
| service test.
| |
| The reason for Note 2 is that performing the Surveillance would perturb the electrical distribution system and challenge safety systems. However, Note 2 acknowledges that should an unplanned event occur in MODES 1, 2, 3, or 4, that following verification that the acceptance criteria of the SR are met, the event can be credited as a successful performance of this SR.
| |
| ! l l
| |
| l l 1 l !
| |
| 1 (continued)
| |
| ( Crystal River Unit 3 B 3.8-46 Revision 8
| |
| | |
| DC Sources-Operating I B 3.8.4 e
| |
| BASES -
| |
| \
| |
| I SURVEILLANCE 3.8.4.8 SR )
| |
| REQUIREMENTS i A battery performance discharge test is a test of the !
| |
| constant current capacity of a battery to detect any change in the capacity determined by the acceptance test. The 4
| |
| performance test is normally done in the as-found condition i after the battery has been in service for a period of time.
| |
| The test is intended to determine overall battery !
| |
| ; degradation due to age and usage.
| |
| A battery modified performance discharge test is described in the bases for SR 3.8.4.7. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.8; however, only the modified performance discharge test may be used to satisfy ;
| |
| SR 3.8.4.8 while satisfying the requirements of SR 3.8.4.7 '
| |
| at the same time.
| |
| The acceptance criteria for this Surveillance are consistent with IEEE-450 (Ref. 9) and IEEE-485 (Ref. 5). These references recommend that consideration be given to -
| |
| replacing the battery if its capacity is below 80% of the l manufacturer rating. A capacity of 80% is an indication that the battery rate of deterioration is potentially increasing, even if there is still ample capacity to meet the design load requirements. :
| |
| The Frequency for this test is 60 months, or more frequently i as the battery approaches the end of its expected life, or other signs of degradation are present. A 12 month Frequency is established if the battery shows degradation or has reached 85% of its expected life with capacity < 100% of manufacturer's rating. Degradation is indicated, according to IEEE-450 (Ref. 9), when the battery capacity drops by more than 10% relative to its capacity on the previous performance test or when it is below the manufacturer rating. A 24 month Frequency is established when the battery reaches 85% of the expected life, but the capacity is still 2 100% of the manufacturer's rating. These Frequencies are consistent with the recommendations in IEEE-450 (Ref. 9).
| |
| I (continued)
| |
| Crystal River Unit 3 8 3.8-47 Revision 8
| |
| | |
| 1.
| |
| DC Sources-0perating 8 3.8.4 c'
| |
| BASES % -
| |
| i 1
| |
| 1 SURVEILLANCE SR 3.8.4.8 (continued)
| |
| REQUIREMENTS I
| |
| This SR is modified by a Note indicating the SR should not j be performed in MCDES 1, 2, 3, or 4 since performing the j Surveillance would perturb the electrical distribution l system and challenge safety systems. However, the Note l acknowledges that should an unplanned event occur in MODES 1, 2,-3, or 4, that following verification that the acceptance' criteria of the SR are met, the event can be credited as a successful performance of this SR.
| |
| REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.
| |
| : 2. Regulatory Guide 1.6, March 10,1971.
| |
| : 3. Proposed IEEE-308, dated 1969.
| |
| : 4. FSAR, Chapter 8.
| |
| : 5. IEEE-485-1983,' June 1983.
| |
| {
| |
| : 6. FSAR, Chapter 6.
| |
| : 7. FSAR, Chapter 14.
| |
| : 8. Regulatory Guide 1.93, December 1974.
| |
| : 9. IEEE-450-1995 I
| |
| : 10. Regulatory Guide 1.32, February 1977.
| |
| : 11. Regulatory Guide 1.129, December 1974.
| |
| : 12. CR-3 Calculation E90-0099, i
| |
| i l
| |
| l Crystal River Unit 3 B 3.8-48 Revision 8
| |
| | |
| Nuclear Instrumentation B 3.9.2 3 B 3.9 REFUELING OPERATIONS
| |
| ; B 3.9.2 Nuclear Instrumentation 4
| |
| BASES 1
| |
| BACKGROUND The source range neutron flux monitors are used during 4
| |
| refueling operations to monitor the core reactivity i i condition. The installed source range neutron flux monitors are part of the Nuclear Instrumentation (NI) System. These detectors are located external to the reactor vessel and detect neutrons leaking from the core.
| |
| l The installed source range neutron flux monitors are boron tri-fluoride (BF3) detectors operating in the proportional region of the gas filled detector characteristic curve. The ;
| |
| 4 6etectors monitor the neutron flux in counts per second.
| |
| : The instrument range covers seven decades of neutron flux
| |
| ; (0.1 to 1E+6 cps). The instruments provide continuous ,
| |
| visual indication in the control room and an audible indication to alert operators to a possible reactivity i excursion. Audible indication is also required within j containment to alert personnel working on the refueling
| |
| < floor to an increasing count rate. NI System design ,
| |
| criteria is contained in Reference 1. i APPLICABLE Two OPERABLE source range neutron flux monitors are required ,
| |
| SAFETY ANALYSES to provide a signal to alert the operator to unexpected changes in core reactivity, such as by a boron dilution accident or an improperly loaded fuel assembly. The safety analysis of the uncontrolled boron dilution accident is ;
| |
| described in Reference 2. While the analysis does not -
| |
| identify the specific indication instrumentation assumed to alert the operator to the event, it is reasonable to assume the source range neutron flux monitors are a primary indication for a wide range of postulated dilution sources. t The analysis of the most limiting uncontrolled boron ;
| |
| dilution accident demonstrates that there is sufficient time -
| |
| and indication available for the operator to detect the event and take corrective action to terminate the event i prior to reaching criticality. ;
| |
| l The source range neutron flux monitors satisfy Criterion 3 of the NRC Policy Statement. ]
| |
| l (continued)
| |
| Crystal River Unit 3 8 3.9-5 Revision No. 7
| |
| | |
| 1 Nuclear Instrumentation B 3.9.2 BASES (continued) .... I i
| |
| l LCO This LC0 requires two source range neutron flux monitors ;
| |
| OPERABLE to ensure that redundant monitoring capability is '
| |
| available to detect changes in core reactivity. While this LCO is normally met by use of the BF, detectors, the post-accident monitoring wide range neutron flux. instrumentation i has been shown to be functionally equivalent and may be i relied upon to comply with this LCO. The use of portable '
| |
| detectors is also. permitted for purposes of complying with this LCO. If used, portable detectors should be functionally equivalent to the installed source range monitors and satisfy the applicable Surveillance ,!
| |
| Requirements.
| |
| Audible indication from one of the neutron monitors is ,
| |
| required in both the' control room and containment in order i to alert personnel to changes in count rate. ,
| |
| i i
| |
| APPLICABILITY In MODE 6, the source range neutron flux monitors are i required to be OPERABLE to determine changes in core !
| |
| reactivity. There is no other direct means available to !
| |
| check core reactivity levels. In portions of MODE 2, MODES ~
| |
| 3, 4 nd 5, the monitors are required to be OPERABLE by r !
| |
| LC0 3.i.9, " Source Range Neutron Flux." \ j t
| |
| In MODE i, the neutron flux level is above the indicated I range of the monitors, the monitors are de-energized and no !
| |
| . longer relied upon for reactivity and power-level monitoring. Thus, there are no requirements on source range i neutron flux monitors in MODE 1. !
| |
| l i
| |
| ACTIONS A.1 and A.2 l
| |
| [
| |
| With only one source range- neutron flux monitor OPERABLE, i redundant neutron count rate indication has been lost. !
| |
| Since these instruments are the only direct means of monitoring core reactivity conditions, CORE ALTERATIONS and ,
| |
| positive reactivity additions must be suspended immediately. !
| |
| Suspension of CORE ALTERATIONS shall not preclude completion ;
| |
| of movement of a component to a safe position, but it does '
| |
| preclude choosing a position that would result in a positive reactivity addition to the core.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.9-6 Revision No. 7
| |
| . -.e.- -
| |
| | |
| Nuclear Instrumentation B 3.9.2 l
| |
| BASES ACTIONS 8.1 and 8.2 (continued)
| |
| With no source range neutron flux monitor OPERABLE, actions to restore a monitor to OPERABLE status shall be initiated immediately. Once initiated, actions shall be continued until a source range neutron flux monitor is restored to OPERABLE status.
| |
| With no source range neutron flux monitor OPERABLE, there is no direct means of detecting changes in core reactivity.
| |
| However, since CORE ALTERATIONS and positive reactivity additions are suspended (in accordance with Required Actions A.1 and A.2), the core reactivity condition should remain relatively stable 0ntil two source range neutron flux monitors are restored to OPERABLE status. Additional confidence in the plant's stability during this condition is provided by performing SR 3.9.1.1 to ensure that the required baron concentration exists.
| |
| The Completion Time of 4 hours is sufficient to obtain and analyze a reactor coolant sample for baron concentration and provides prompt confirmation the plant is operating in an acceptable condition. The subsequent Completion Time of once per 12 hours ensures that unplanned changes in baron concentration would be identified. The Completion Time is reasonable based on engineering judgment, considering the low probability of a change in core reactivity during this time period.
| |
| SURVEILLANCE SR 3.9.2.1 REQUIREMENTS SR 3.9.2.1 is the performance of a CHANNEL CHECK. It is based on the assumption that the two indication channels should be consistent with each other given existing core conditions. Changes in fuel loading and core geometry can result in significant differences between source range channels, but each channel should be consistent with its local conditions.
| |
| The Frequency of 12 hours is based on engineering judgment and is consistent with the Frequency specified for the equivalent SR of the same instruments in LCO 3.3.9.
| |
| (continued)
| |
| Crystal River Unit 3 B 3.9-7 Revision No. 7
| |
| | |
| Nuclear Instrumentation-B 3.9.2 BASES ,'
| |
| SURVEILLANCE SR 3.9.2.2 REQUIREMENTS (continued) SR 3.).2.2 is the performance of a CHANNEL CALIBRATION every 24 months. The CHANNEL CALIBRATION for the source range nuclear instrumentation is a complete check and re-adjustment of the channels, from the pre-amplifier input to the indicators. The 24 month Frequency is based on the results of a review of instrument drift data conducted in accordance with NRC Generic Letter 91-04. .
| |
| Performance of SR 3.3.9.2 meets the requirements of this Surveillance, and one performance may be used to satisfy both requirements.
| |
| This SR is modified by a Note stating that neutron. detectors are excluded from the CHANNEL CALIBRATION. It is not necessary to test the detectors because generating a meaningful test signal is difficult. The detectors are of simple construction, and any_ failures in the detectors will be apparent as change in channel output.
| |
| f REFERENCES 1. FSAR, Section 7.3.1.2.
| |
| : 2. FSAR, Section 14.1.2.4.
| |
| l i
| |
| l i
| |
| i Crystal River Unit 3 8 3.9-8 Revision No. 7 I l
| |
| .}}
| |
