ML20247H291
| ML20247H291 | |
| Person / Time | |
|---|---|
| Site: | 05200002, 05000470 |
| Issue date: | 03/30/1989 |
| From: | ABB COMBUSTION ENGINEERING NUCLEAR FUEL (FORMERLY |
| To: | |
| Shared Package | |
| ML20247G537 | List:
|
| References | |
| NUDOCS 8904040434 | |
| Download: ML20247H291 (461) | |
Text
{{#Wiki_filter:- _ - _ _ _ _ _ _ - _ _ _ _ _ - _ _ - _ _ _ . _ _ _ _ - (Sheet 1 of.11) CESSAR EHL"ic m. O EFFECTIVE PAGE LISTING CHAPTER 7
, Table of Contents Pace Amendment i D 11 D 111 D I iv D v E vi E vil i I
viii E ix E x E xi xii D xiii D xiv D xy D O xvi xvii D D xviii D xix D xx E xxi E xxii E xxiii E xxiv E xxv E l xxvi E xxvii E. xxviii D Text Pace Amendment 7.1-1 D 7.1-2 D 7.1-3 D 7.1-4 D 7.1-5 D 7.1-6 E 7.1-7 D b d 7.1-8 D 7.1-9 D 7.1-10 D Amendment E ADO 7,(# M ember M, N hhhhok7o PDC
(Sheet 2 of 11) CESSAR a!Oicui:n 9 EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Text- (Cont'd) Page . Amendment 7.1-11 D 7.1-12 E 7.1-13 D 7.1-14 D 7.1-15 D 7.1-16 D 7.1-17 D 7.1-18 E 7.1-19 D 7.1-20 D 7.1-21 E 7.1-22 D 7.1-23 D 7.1-24 D 7.1-25 D 7.1-26 D 7.1-27 D 7.1-28 D 7.2-1 E 7.2-2 E 7.2-3 E 7.2-4 E 7.2-5 7.2-6 E 7.2-7 E 7.2-8 E 7.2-9 E 7.2-10 E 7.2-11 E ! 7.2-12 E l 7.2-13 E 7.2-14 E 7.2-15 E 7.2-16 E 7.2-17 E 7.2-18 E 7.2-19 E I 7.2-20 E l 7.2-21 E j 7.2-22 E 7.2-23 E 7.2-24 E Amendment E f December 30, 1988 1
(Sheet 3 of 11) CESSAR Ensncan: 4 O v 1 EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Text (Cont'd) Pace Amendment 7.2-25 E 7.2-26 E 7.2-27 E 7.2-28 E 7.2-29 E 7.2-30 E l 7.2-31 E 7.2-32 E 7.2-33 E 7.2-34 E 7.2-35 E 7.2-36 E 7.2-37 7.2-38 E
/ 7.2-39 E 7.2-40 E 7.2-41 7.2-42 E 7.2-43 i 7.2-44 E 1 7.2-45 E 7.2-46 7.2-47 E 7.'2-48 E 7.2-49 E 7.2-50 E 7.2-51 E 7.2-52 E 7.2-53 E 7.2-54 7.2-55 E 7.2-56 E 7.3-1 E 7.3-2 E 7.3-3 E 7.3-4 E 7.3-5 E 7.3-6 E 7.3-7 E 7.3-8 E i 7.3-9 E 7.3-10 E Amendment E December 30, 1988 L_________-_____--____-___-___________-____--_ .___- ___-_. __ _-. ._. _ _ . - _ _ _ _ _ - - _ _ _ - _
(Sheet 4 of 11) CESSAR EMiincari:n 9 _ EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 ; Text (Conted) Page Amendment 7.3-11 E 7.3-12 E 7.3-13 E 7.3-14 E 7.3-15 E 7.3-16 E 7.3-16a E 7.3-17 E 7.3-18 E 7.3-19 E 7.3-20 E 7.3-21 E 7.3-22 E 7.3-23 E 7.3-24 E 7.3-25 E 7.3-26 E 7.3-27 E 7.3-28 E 7.3-29 E 7.3-30 E 7.3-31 E 7.3-32 E 7.3-33 E I 7.3-34 E 7.3-35 E 7.3-36 E 7.3-37 E 7.3-38 E 7.3-39 E 7.3-40 E 7.3-41 7.3-42 7.4-1 D 7.4-2 D 7.4-3 D 7.4-4 E 7.4-5 D 7.4-6 D 7.4-7 D O Amendment E December 30, 1988
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l (Sheet 5 of 11). CESSARneincm. O EFFECTIVE PAGE LISTING (Cont'd) CHAPTER _7_ Text (Cont'd) Pace Amendment
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7.4-8 D 7.4-9 D 7.4-10 D 7.4-11 D 7.4-12 D 7.4-13 D 7.5-1 D l 7.5-2 D I 7.5-3 D l 7.5-4 D l 7.5-5 D l 7.5-6 D 7.5-7 D 7.5-8 D n 7.5-9 7.5-10 7.5-11 D D D ] 7.5-12 E 7.5-13 D i 7.5-14 D 7.5-15 D 7.5-16 D 7.5-17 D 7.5-18 D 7.5-19 D 7.5-20 D 7.5-21 D 7.5-22 D 7.5-23 D 7.5-24 D 7.5-25 D 7.5-26 D 7.5-27 D l 7.5-28 D 7.5-29 D 7.6-1 E 7.6-2 D 7.6-3 E 7.6-4 E O Amendment E December 30, 1988 )
(Sheet 6 of 11) C E S S A R En nricui:n l 9 EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Text (Cont'd) page a 2Lmendment - 7.6-5 E 7.6-6 D 7.6-7 D 7.6-8 D 7.6-9 D 7.6-10 E 7.6-11 D 7.6-12 D 7.6-13 D 7.7-1 D 7.7-2 D 7.7-3 D 7.7-4 D 7.7-5 D 7.7-6 D 7.7-7 D 7.7-8 D 7.7-9 D 7.7-10 D 7.7-11 E 7.7-12 D 7.7-13 D 7.7-14 D 7.7-15 D 7.7-16 E 7.7-16a E 7.7-17 D 7.7-18 D 7.7-19 D 7.7-20 D 7.7-21 D 7.7-22 D 7.7-23 E 7.7-24 D 7.7-25 D 7.7-26 E 7.7-27 D 7.7-28 D 7.7-29 D ) I 7.7-30 D 7.7-31 D i i Amendment E l December 30, 1988 {
(Sheet 7 of 11) CESSAR HE?icamn
'i O
V EFFECTIVE PAGE LISTING (Cont'd)
% APTER 7 Text (Cont'd)
. Pace Amendment 7.7-32 D l 7.7-33 D 7.7-34 D 7.7-35 D 7.7-36 D 1 7.";-37 D 7.7-38 D 7.7-39 D 7.*i-40 D 7.7-41 D 7.'-42 E 7 . ', - 4 3 D 7.*/-44 D 7.1-45 D !
f 7 . '/ - 4 6 D l f 7.7-48 'D , 7.7-49 D l 7.7-50 D 7.7-51 D , 7.7-52 D 7.7-53 D 7.7-54 D 7.7-55 D 7.7-56 D 7.7-57 D 7.7-58 E i Tables Amendment 7.1-1 E 7.2-1 E 7.2-2 E 7.2-3 E 7.2-4 E 7.2-5 (Sheet 1) E 7.2-5 (Sheet 2) E 7.2-5 (Sheet 3) E 7.2-5 (Sheet 4) E 7.2-5 (Sheet 5) E 7.2-5 (Sheet 6) E
, 7.2-5 (Sheet 7) E 7.2-5 (Sheet 8) E Amendment E December 30, 1988
(Shast 8 of 11) CESSARUnisce O EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Tables (cont'd) Amendment 7.2-5 (Sheet 9) E 7.2-5 (Sheet 10) E 7 . 2 - f; (Sheet 11) E 7.2-5 (Sheet 12) E 7.2-5 (Sheet 13) E 7.2-5 (Sheet 14) E 7.2-5 (Sheet 15) E 7.2-5 (Sheet 16) E 7.2-5 (Sheet 17) E 7.2-5 (Sheet 18) E 7.2-5 (Sheet 19) E 7.2-5 (Sheet 20) E 7.2-5 (Sheet 21) E 7.2-5 (Sheet 22) E 7.2-5 (Sheet 23) E 7.2-5 (Sheet 24) E 7.2-5 (Sheet 25) E 7.2-5 (Sheet 26) E 7.2-5 (Sheet 27) E 7.2-5 (Sheet 28) E 7.2-5 (Sheet 29) E 7.2-5 (Sheet 30) E 7.3-1 E 7.3-2 E 7.3-3 E 7.3-4 E 7.3-5 E 7.3-6 E 7.4-1 (Sheet 1) D 7.4-1 (Sheet 2) D 7.4-2 E 7.5-1 (Sheet 1) D , 7.5-1 (Sheet 2) E 7.5-2 (Sheet 1) D 7.5-2 (Sheet 2) D 7.5-2 (Sheet 3) E 7.5-2 (Sheet 4) E 7.5-2 (Sheet 5) D 7.5-3 (Sheet 1) E 7.5-3 (Sheet 2) E 7.5-3 (Sheet 3) E 4 7.5-3 (Sheet 4) E l 7.5-3 (Sheet 5) E fj 7.5-3 (Sheet 6) D Amendment E f December 30, 1988 1
v i (Sheet 9 of 11) i CESSAR inn?,c.m., O EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Tables (Cont'd) Amendment 7.6-1 E j 7.7-1 D 7.7-2 D 7.7-3 E 7.7-4 D 7.7-5 D 7.7-6 D 7.7-7 D Fiqures Amendment 7.2-1 E 7.2-2 E 7.2-3 E 7.2-4 E 7.2-5 E O'. 7.2-6 E 7.2-7 E 7.2-8 E 7.2-9 E 7.2-10 E 7.2-11 E 7.2-12 E 7.2-13 E 7.2-14 E 7.2-15 E I 7.2-16 E 7.2-17 E l 7.2-18 E 7.2-19 E ' 7.2-20a E 7.2-20b E I 7.2-20c E I 7.2-21a E 7.2-21b E i
.7.2-22a E l 7.2-22b E 7.2-23a {
E 7.2-23b E 7.2-24 E ' 7.2-25 E O 7.2-26 7.2-27a E E 7.2-27b E Amendment E December 30, 1988
1 (Sheet 10 of 11) I CESSAR Meincy,=3 ,
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I O' EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Fictures (Cont'd) Amendment 7.2-28a E 7.2-28b E 7.2-29a E 7.2-29b E 7.2-30 E 7.3-1(a) E 7.3-1(b) E 7.3-1(c) E 7.3-1(d) E 7.3-2 E 7.3-3 E 7.3-4 E 7.3-5 E 7.3-6 E 7.3-7 E 7.3-8a E 7.3-8b E 7.3-9a E 7.3-9b E 7.3-10a E 7.3-10b E 7.3-11 E 7.3-12 E 7.3-13a E 7.3-13b E 7.3-14a E 7.3-14b E 7.3-15a E 7.3-15b E 7.3-16 E 7.3-17 E 7.3-18 E 7.3-19 E 7.3-20a E 7.3-20b E 7.3-20c E 7.3-20d E 7.3-21 E 7.3-22 E 7.3-23 E 7.3-24 E 7.5-1 D 7.5-2 D 7.5-3 D 7.5-4 D Amendment E December 30, 1988 ,
(Sheet.11 of 11) CESSAR Mninem:n O EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Fiqures (Cont'd) Amendment 7.5-5 D 7.5-6 D 7.5-7 D 7.5-8 E 7.6-1(a) E 7.6-1(b) E 7.6-1(c) E D 7.6-2 7.6-3 D 7.7-1 E 7.7-2 D 7.7-3 E-7.7-4 E j 7.7-5 D 7.7-6 D 7.7-7 E 7.7-8 E O 7.7-9 7.7-10 7.7-11 D D. D
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7.7-12 E ! 7.7'13 E 7.7-14 E 1 7.7-15 D 7.7-16 D . 7.6-17 D 7.7-18 D 7.7-19 D 7.7-20 D 7.7-21 D I 7.7-22 D 7.7-23 D 7.7-24 E 7.7-25a E I 7.7-25b E O Amendment E December 30, 1988
CESSAR !!!Mncue,. O TABLE OF CONTENTS CHAPTER 7 Section subiect Pace No. 7.0 INSTRUMENTATION AND CONTROLS 7.1-1
7.1 INTRODUCTION
7.1-1 7.1.1 IDENTIFICATION OF SAFETY-RELATED 7.1-1 l SYSTEMS 7.1.1.1 Plant Protection System (PPS) 7.1-1 7.1.1.1.1 Alternate Protection 7.1-2 D System ( APS ). 7.1.1.2 Reactor Trio System (RTS) 7.1-2 7.1.1.3 Enaineered Safety Feature 7.1-2 Systems (ESF Systems) 7.1.1.4 Systems Recuired for Safe 7.1-2 Shutdown l 7.1.1.5 Safety-Related Display 7.1-4 l Instrumentation l 7.1.1.6 All Other Systems Reauired 7.1-4 l for Safety 7.1.1.7 Desian Comparison 7.1-4 7.1.1.8 System Drawinas 7.1-5 7.1.2 IDENTIFICATION OF SAFETY CRITERIA 7.1-5 7.1.2.1 Desian Bases 7.1-5 7.1.2.1.1 Systems Required for Plant 7.1-6 Protection 7.1.2.1.2 Systems Required for Safe Shutdown 7.1-6 7.1.2.1.3 Safety-Related Display 7.1-6 Instrumentation 7.1.2.1.4 All Other Systems Required 7.1-6 tor Safety l l Amendment D. l 1 September'30, 1988
()l5!h!h/kEI C!$kNICATION I ei IhBLE OF CONTENTS (Cont'd) i CIIAPTER 7 j i gection pubie Pace No. 7.1.2.2 Conformance to IEEE 279-1971 7.1-7 7.1.2.3 Conformance to IEEE 308-1980 7.1-7 7.1.2.4 Conformance to IEEE 317-1983 7.1-7 7.1.2.5 Conformance to IEEE 323-1983, 7.1-7 as Augmented by Reculatory Guide 1.89 (Rev. 1, 6/84) 7.1.2.6 Conformance to IEEE 336-1985, 7.1-7 as Auamented by Reculatory Guide 1.30 (Rev. O, 8772) 7.1.2.7 Conformance to IEEE 338-1977 2 7.1-7 < as Auamented by Reaulatory Guide 1.118 (Rev. 2, 6/78) 7.1.2.8 Conformance to IEEE 344-1987, 7.1-8 as Auamented by Reculatory Guide 1.100 (Rev. 1, 8/77) 7.1.2.9 Conformance to IEEE 379-1977, 7.1-8 as Augmented by Reculatory Guide 1.53(Rev. O, 6/73) D 7.1.2.10 Conformance to IEEE 384-1981 1 7.1-9 as Auamented by Reculatory Guide 1.75 (Rev. 2, 9/78) 7.1.2.11 Conformance to IEEE 387-1984 7.1-10 7.1.2.12 Conformance to IEEE 450-1980 7.1-10 7.1.2.13 Conformance to IEEE 603-1980, 7.1-10 as Auamented by Reculatory Guide 1.153 (Rev. O, 12/85) 7.1.2.14 Comparison of Desian with 7.1-10 Reculatory Guide 1.6 (Rev. O, 3/71) O Amendment D il September 30, 1988 i
CESSAR Eniiricuim o V TABLE OF CONTENTS (Cont'd) CHAPTER 7 { l Section Subject Pace No j 7.1.2.15 Comformance to Reculatorv 7.1-10 Guide 1.11 (Rev. O, 3/71) 4 7.1.2.16 Conformance to Reculatorv 7.1-11 Guide 1.17 (Rev. 1. 6/73) 7.1.2.17 Conformance to Reculatory 7.1-12 Guide 1.22 (Rev. O. 2/721 7.1.2.18 Conformance to Reculatory 7.1-13 I Guide 1.29 (Rev. 3, 9/78) 7.1.2.19 Conformance to Regulatory 7.1-13 Guide 1.40 (Rev. O. 3/73) 7.1.2.20 Conformance to Reaulatorv 7.1-14 Guide 1.45 (Rev. O. 5/73)
\' 7.1.2.21 Conformance to Reculatorv 7.1-14 Guide 1.47 (Rev. O. 5/73) l D
l 7.1.2.21.1 Operating Bypasses '7.1-15 7.1.2.21.2 Trip Channel Bypasses 7.1-15 , 7.1.2.21.3 ESF Components Inoperable 7.1-15 7.1.2.22 Conformance to Reculatory 7.1-16 Guide 1.62 (Rev. O, 10/73) 7.1.2.23 Conformance to Reaulatorv 7.1-16 Guide 1.63 (Rev. 3, 2/87) , 7.1.2.24 Conformance to Regulatorv 7.1-17 l Guide 1.68 (Rev. 2. 8/78) 7.1.2.25 Conformance to Reaulatory 7.1-17 Guide 1.73 (Rev. O, 1/74) l 7.1.2.25 Conformance to Reaulatorv 7.1-17 Guide 1.97 (Rev. 3. 5/83) 7.1.2.27 Conformance to Reculatorv 7.1-18 Guide 1.105 (Rev. 2, 2/86)
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U Amendment D iii September 30, 1988
CESSAR Unific 1,2, O TABLE OF CONTENTS (Cont'd) CHAPTER 7 Section Subiect Pace No. l 7.1.2.28 Conformance to Reculatorv 7.1-18 Guide 1.106 (Rev. 1, 3/77) 7.1.2.29 Conformance to Reculatorv 7.1-19 Guide 1.120 (Rev. 1, 11/77), as Auamented by BTP CMEB 9.5-1 7.1.2.30 Conformance to Regulatorv 7.1-19 Guide to 1.133 (Rev. 1, 5/81) 7.1.2.31 Conformance to Reculatorv 7.1-19 Guide 1.151 (Rev. O, 7/83) 7.1.2.32 Conformance to Reaulatorv 7.1-20 Guide 1.152 (Rev. O, 11/85) 7.1.2.33 Conformance to Reculatorv 7.1-20 Guide 1.156 (Rev. O, 11/87) 7.1.2.34 Conformance to Reculatorv 7.1-20 D Guide 8.12 (Rev. 1, 1/81) 7.1.3 1NTERFACE REQUIREMENTS 7.1-21 f.2 REACTOR PROTECTIVE SYSTEM 7.2-1 1 7.
2.1 DESCRIPTION
7.2-1 l l 7.2.1.1 Systems Description 7.2-1 l 7.2.1.1.1 Trips 7.2-2 7.2.1.1.1.1 Variable Overpower 7.2-2 7.2.1.1.1.2 High Logarithmic Power 7.2-2 Level 7.2.1.1.1.3 High Local Power Density 7.2-3 7.2.1.1.1.4 Low Departure From Nucleate 7.2-3 Boiling Ratio 7.2.1.1.1.5 High Pressurizer Pressure 7.2-3 O Amendment D iv September 30, 1988
1 CESSARHnLm. TABLE CF CONTENIR (Cont'd) i CHAPTER 7 i Section Bubiect Pace No' l 7.2.1.1.1.6 Low Pressurizer Pressure 7.2-4 7.2.1.1.1.7 Low Steam Generator Water 7.2-4 Level 7.2.1.1.1.8 Low Steam Generator Pressure 7.2-4 7.2.1.1.1.9 High containment Pressure 7.2-5 7.2.1.1.1.10 Figh Steam Generator Water 7.2-5 Level 7.2.1.1.1.11 Manual Trip 7.2-5 7.2.1.1.1.12 Low Reactor Coolant Flow 7.2-6 E 7.2.1.1.2 Initiating Circuits 7.2-6 7.2.1.1.2.1 Process Measurements 7.2-6 7.2.1.1.2.2 CEA Position Measurements 7.2-6 1 7.2.1.1.2.2.1 CEA Position Monitoring 7.2-7 by the RPS O 7.2.1.1.2.2.2 Control and Protective Actions for CEA Misalignments 7.2-8 E 7.2.1.1.2.3 Ex-core Neutron Flux 7.2-10 i Measurements l 7.2.1.1.2.4 Reactor Coolant-F~4ow 7.2-10 Measurements 7.2.1.1.2.5 Core Protectjan Calculators 7.2-11 7.2.1.1.2.6 Bistable Trip Generation 7.2-14 7.2.1.1.3 Logic 7.2-16 7.2.1.1.4 Actuated Devices 7.2-18 7.2.1.1.5 Bypasses 7.2-18 7.2.1.1.6 Interlocks 7.2-21 j 7.2.1.1.7 Redundancy -7. 2-2 2 - 7.2.1.1.8 Diversity 7.2 7.2.1.1.9 Testing 7.2-24 7.2.1.1.9.1 Sensor Check 7.2-25 7.2.1.1.9.2 Trip Bistable Tests 7.2-25 l 7.2.1.1.9.3 Core Protection Calculator 7.2-28 l Tests 7.2.1.'.9.4 Local Coincidence Logic 7.2-29 l Testing E 7.2.1.1.9.5 RPS Initiation Logic festing 7.2-29 l ("]), (, 7.2.1.1.9.6 Manual Trip Test 7.2-30 Amendment E v December 30, 1988
CESSAR EBL"icari:n 1 O TADLE OF CONTENTS (Cont'd) { CHAPTER 7 Section Bubiect Pace No. 7.2.1.1.9.7 Bypass Testing 7.2-30 7.2.1.1.9.8 Response Time Tests 7.2-30 7.2.1.1.10 Vital Instrument Power 7.2-32 i supply l 7.2.1.1.11 System Arrangement 7.2-32 E 7.2.1.2 Desian Bases 7.2-32 7.2.1.3 Ssstem Drawinos 7.2-35 7.2.2 ANALYSIS 7.2-35 7.2.2.1 Introduction 7.2-35 7.2.2.1.1 Anticipated Operational 7.2-37 Occurrences 7.2.2.1.2 Accidents 7.2-39 7.2.2.2 Trio Bases 7.2-40 7.2.2.2.1 Variable Overpower Trip 7.2-40 7.2.2.2.2 High Logarithmic Power Level Trip 7.2-40 7.2.2.2.3 High Local Power Density Trip 7.2-41 7.2.2.2.4 Low DNBR Trip 7.2-41 7.2.2.2.5 High Pressurizer Pressure Trip 7.2-42 7.2.2.2.6 Low Pressurizer Pressure Trip 7.2-42 7.2.2.2.7 Low Steam Generator Water 7.2-42 Level Trips 7.2.2.2.8 Low Steam Generator Pressure Trips 7.2-43 7.2.2.2.9 High Containment Pressure Trip 7.2-43 I I 7.2.2.2.10 High Steam Generator Water 7.2-43 Level Trips 7.2.2.2.11 Low Reactor Coolant Flow 7.2-43 E j Manual Reactor Trip 7.2-44 7.2.2.2.12 7.2.2.3 Desian 7.2-44 i I 7.2.2.3.1 General Design Criteria 7.2-44 7.2.2.3.2 Equipment Design Criteria 7.2-46 , 7.2.2.3.3 Testing Criteria 7.2-52 1 Amendment E vi December 30, 1988 l 1 I __-______._A
~ CESSARanincm. b>O TABLE OF CONTENTS (Cont'd) CHAPTER 7 Section Subiect Pace No. 7.2.2.4 Failure Modes and Effects 7.2-53 Analysis (FMEAL 7.2.3 REACTOR PROTECTIVE SYSTEM INTERFACES 7.2-53 7.2.3.1 Power 7.2-53 7.2.3.2 Protection from Natural Phenomena 7.2-53 7.2.3.3 Protection from Pipe Failure 7.2-53 7.2.3.4 U!ssiles 7.2-53 7.2.3.5 Separation 7.2-54 : 7.2.3.6 Independence 7.2-54 ( 7.2.3.7 Thermal Limitations 7.2-54 7.2.3.8 Monitorina 7.2-54 7.2.3.9 Operational / Controls 7.2-54 7.2.3.10 Inspection and Testina 7.2-54 g 7.2.3.11 Chemistry /Samnlina 7.2-54 7.2.3.12 Materials 7.2-54 7.2.3.13 System Component Arrangement 7.2-54 7.2.3.14 Radiological Waste 7.2-54 7.2.3.15 overpressure Protection 7.2-55 i 7.2.3.16 Related Services 7.2-55 ; 7.2.3.17 Environmental 7.2-55 7.2.3.18 Mechanical Interaction 7.2-55 < t l l vii
# C 12ATl:N I
I J TABLE OF CONTENTS (Cont'd) ; 1 CHAPTER 7 Section Bubiect Pace No. E 7.2.4 AUXILIARY PROTECTION SYSTEM 7.2-55 7.3 ENGINEERED SAFETY FEATURES ACTUATION 7.3-1 SYSTEM 7.
3.1 DESCRIPTION
7.3-1 System Description E 7.3.1.1 7.3-2 7.3.1.1.1 ESFAS Measurement Channels 7.3-5 7.3.1.1.2 Logic 7.3-6 7.3.1.1.2.1 ESFAS Bistable and 7.3-6 Coincidence Logic 7.3.1.1.2.2 Actuating Logic 7.3-6 7.3.1.1.2.2.1 Component Control Logic 7.3-7 l 7.3.1.1.2.2.1.1 Solenoid-Operated Valves 7.3-7 7.3.1.1.2.2.1.1.1 Two-State Solenoid Valve 7.3-7 Control 7.3.1.1.2.2.1.1.2 Modulating Valves With 7.3-8 Solenoid Operators 6 7.3.1.1.2.2.1.2 Motor-Operated Valves 7.3-9 7.3.1.1.2.2.1.2.1 Interface Signals 7.3-9 7.3.1.1.2.2.1.2.2 Throttling and Full 7.3-10 Throw Designs 7.3.1.1.2.2.1.2.3 Thermal Overload 7.3-10 Monitoring , 7.3.1.1.2.2.1.3 Contactor-Operated 7.3-10 ] Components j 7.3.1.1.2.2.1.4 Circuit Breaker- 7.3-11 l Operated Components ) 7.3.1.1.2.2.1.5 Modulating Components 7.3-12 7.3.1.1.2.2.2 Group Actuation 7.3-13 O Amendment E viii December 30, 1988
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_ s-o j CESSAR ?!ninema n U TABLE OF CONTENTS (Cont'd) CHAPTER 7 Section Subiect Pace No 7.3.1.1.2.3 CSS-Diesel Loading Sequencer 7.3-13 lE 7.3.1.1.3 Bypasses 7.3-15 i 7.3.1.1.3.1 7.3.1.1.3.2 Bistable Trip Channel Bypass Operating Bypass 7.3-15 lE I 7.3-15 7.3.1.1.3.3 Bypasses and Inoperable 7.3-16 l l Status lE j l 7.3.1.1.4 Interlocks 7.3-16 7.3.1.1.5 Redundancy 7.3-16a 7.3.1.1.6 Diversity 7.3-17 7.3.1.1.7 Sequencing 7.3-17 7.3.1.1.8 Testing 7.3-17 7.3.1.1.8.1 Sensor Checks 7.3-18 g 7.3.1.1.8.2 Trip Bistable Test 7.3-18 7.3.1.1.8.3 Local Coincidence Logic Tests 7.3-18 7.3.1.1.8.4 Initiation Logic Tests 7.3-18 E 7.3.1.1.8.5 Actuating Logic Test 7.3-19 7.3.1.1.8.6 Selective Group Test 7.3-20 l 7.3.1.1.8.7 Bypass Tests 7.3-21 7.3.1.1.8.8 Response Time Tests 7.3-21 7.3.1.1.8.9 Diesel Load Sequencer Tests 7.3-22 E 7.3.1.1.9 Vital Instrument Power Supply 7.3-23 l 7.3.1.1.10 Actuated Systems 7.3-23 ' l 7.3.1.1.10.1 Containment Isolation 7.3-23 1 System 7.3.1.1.10.2 Containment Spray System 7.3-24 ] 1E 7.3.1.1.10.3 Main Steam Isolation System 7.3-24 8 7.3.1.1.10.4 Safety Injection System 7.3-25 a 7.3.1.1.10.5 Emergency Feedwater System 7.3-25 lE 7.3.1.2 Design Bases 7.3-26 7.3.1.3 System Drawinos 7.3-27 7.3.1.4 ESFAS Succortina Systems 7.3-27 j 7.3.2 ANALYSIS 7.3-27 Amendment E l ix December 30, 1988 ! L_-_-_-________________--_-__ _ _ _ - - - _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ - - . _ - _ _ - _ - _ _ _ _ _-
CESSAR E!nificuio O 4 TABLE OF CONTENTS (Cont'd) CHAPTER 7 I agetion gubiect Pace No. 7.3.2.1 Introduction 7.3-27 7.3.2.1.1 Design Basis Events (DBE) 7.3-28 7.3.2.2 Actuation Bases 7.3-29 7.3.2.2.1 Safety Injection Actuation 7.3-29 Signal (SIAS) 7.3.2.2.2 Containment Spray Actuation 7.3-30 E Signal (CSAS) 7.3.2.2.3 Containment Isolation 7.3-30 Actuation Signal (CIAS) 7.3.2.2.4 Main Steam Isolation Signal (MSIS) 7.3-30 7.3.2.2.5 Emergency Feedwater Actuation 7.3-30 Signal (EFAS) 7.3.2.3 Desian 7.3-31 7.3.2.3.1 General Design Criteria 7.3-31 7.3.2.3.2 Equipment Design Criteria 7.3-32 7.3.2.3.3 Testing Criteria 7.3-38 7.3.2.4 Failure Modes and Effects 7.3-39 Analysis (FMEA) 7.3.2.5 Setpoint Methodolocv 7.3-39 7.3.2.6 ESF Valve Operability 7.3-39 E 7.3.3 ENGINEERED SAFETY FEATURES ACTUATION 7.3-40 SYSTEM INTERFACE REQUIREMENTS 7.3.3.1 Power 7.3-40 7.3.3.2 Protection from Natural 7.3-40 Phenomena 7.3.3.3 Protection from Pipe Failurg 7.3-40 7.3.3.4 Missiles 7.3-40 1 7.3.3.5 Separation 7.3-40 7.3.3.6 Indep.endence 7.3-41 Amendment E x December 30, 1988 l j
CESSAR iMacue. O TABLE OF CONTENTS (Cont'd) CHAPTER 7 Section Subiect Pace No. 7.3.3.7 Thermal Limitations 7.3-41 7.3.3.8 Monitorina 7.3-41 7.3.3.9 Operational / Controls 7.3-41 7.3.3.10 Inspection and Testina 7.3-41 j l 7.3.3.11 Chemistry /Samolina 7.3-41 7.3.3.12 Materials 7.3-41 1 7.3.3.13 System Component Arrangement 7.3-41 ] d 7.3.3.14 Radiological Waste 7.3-41 j t 7.3.3.35 Overpressure Protection 7.3-41 j gs
-- 7.3.3.16 Related Services 7.3-41 ]
7.3.3.17 Environmental 7.3-41 7.3.3.18 Mechanical Interaction 7.3-42 7.3.3.19 Plant Monitorina System Inputs. 7.3-42 ) l I 7.4 SYSTEMS REOUIRED FOR SAFE SHUTDOWN 7.4-1 7.
4.1 DESCRIPTION
7.4-2 7.4.1.1 Systems Reauired for Safe 7.4-2 Shutdown 7.4.1.1.1 Plant Diesel Generators 7.4-3 7.4.1.1.2 Plant Diesel Generator Fuel Oil 7.4-3 Storage and Transfer System 7.4.1.1.3 Class 1E Power Distribution System 7.4-3 7.4.1.1.4 Station Service-Water System 7.4-3 7.4.1.1.5 Component Cooling Water System 7.4-4 7.4.1.1.6 Emergency Feedwater System 7.4-4 7.4.1.1.7 Atmospheric Dump System (ADS) 7.4-4 7.4.1.1.8 Shutdown Cooling System (SCS) 7.4-4
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CESSAREnacama O' TABLE OF CONTENTS (Cont'd) CHAPTER 7 Section Subiect Pace No. 7.4.1.1.8.1 Initiating Circuits and 7.4-4 Logic 7.4.1.1.8.2 Interlocks, Sequencing and 7.4-5 Bypasses 7.4.1.1.8.3 Redundancy and Diversity 7.4-5 1 7.4.1.1.8.4 Supporting Systems 7.4-5 7.4.1.1.9 Safety Injection System (SIS) 7.4-5 D 7.4.1.1.9.1 Initiating Circuits and 7.4-6 j Logic 7.4.1.1.9.2 Interlocks, Sequencing 7.4-6 ] and Bypasses 7.4.1.1.9.3 Redundancy and Diversity 7.4-6 7.4.1.1.9.4 Supporting Systems 7.4-6 7.4.1.1.10 Emergency Shutdown from Outside 7.4-6 the Control Room lf 7.4.1.1.10.1 Hot Standby 7.4-7 7.4.1.1.10.2 Cold Shutdown 7.4-7 7.4.1.1.11 Safety Depressurization System 7.4-8 (SDS) D ! 7.4.1.2 System Drawinas 7.4-8 7.4.2 ANALYSIS 7.4-8 j 7.4.2.1 Conformance to IEEE 279-1971 7.4-8 1: 7.4.2.2 Conformance to IEEE 308-1980 7.4-12 D 7.4.2.3 Conformance to General Desian 7.4-12 l Criterion,19_ 7.4.2.4 Consideration of Selected 7.4-12 Plant Contingencies l 7.4.2.4.1 Loss of Instrument Air Syston 7.4-12 7.4.2.4.2 Loss of Cooling Water to Vital 7.4-12 Equipment 7.4.2.4.3 Plant Load Rejection, Turbine 7.4-12 Trip, and Loss of Offsite Power Amendment D i 1 xii September 30, 1988
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( TABLE OF CONTENTS (Cont'd) CHAPTER 7 Spction Subiect Pace No. 7.4.2.5 Emercency Shutdown From Outside 7.4-13 ) the Control Room j 7.4.2.5.1 Design Capability for Prompt 7.4-13 3 Hot Standby and to Maintain D ) Hot Standby J' 7.4.2.5.2 Cold Shutdown 7.4-13 7.5 SAFETY RELATED DISPLAY INSTRUMENTATION 7.5-1 , i 7.
5.1 DESCRIPTION
7.5-1 7.5.1.1 System Description 7.5-3 7.5.1.1.1 Safety-Related Plant Process 7.5-3 , Display Instrumentation fg 7.5.1.1.2 Reactor Trip System Monitoring 7.5-3 { i I 4 7.5.1.1.3 Engineered Safety Features 7.5-4 Monitoring , 7.5.1.1.4 CEA Position Indication 7.5-4 j 7.5.1.1.5 Post-Accident Monitoring 7.5-6 7.5.1.1.6 Automatic Bypass Indication on 7.5-6 l l a System Level ) 7.5.1.1.7 Inadequate Core Cooling 7.5-6 ) Monitoring Instrumentation ' D 7.5.1.1.7.1 Sensor Design 7.5-7 7.5.1.1.7.1.1 Saturation Margin 7.5-8 Sensors 7.5.1.1.7.1.2 Heated Junction Thermo- 7.5-8 couple (HJTC) Probe Assembly 7.5.1.1.7.1.3 Core Exit Thermocouple 7.5-9 l (CET) 7.5.1.1.7.2 Description of ICC Sensor 7.5-9 Signal Processing 7.5.1.1.7.2.1 Heated Junction Thermo- 7.5-10 couple _ 7.5.1.1.7.2.2 Core Exit Thermocouple 7.5-10
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CESSAR EE'rificaricu O TABLE OF CONTENTS (Cont'd) CHAPTER 7 i Section Bubiect Pace No. 7.5.1.1.7.3 ICC Information Displays 7.5-11 7.5.1.1.7.3.1 DIAS Channel P 7.5-11 7.5.1.1.7.3.2 DIAS Channel N 7.5-11 D 7.5.1.1.7.3.3 DPS ICC Displays 7.5-12 7.5.2 ANALYSIS 7.5-14 7.5.2.1 Analysis o.L Sa fetv-Related Plant 7.5-14 Process Displav Instrumentation 7.5.2.2 Analysis of Reactor Trio System 7.5-15 Monitoring 7.5.2.3 Analysis of Encineered Safety 7.5-15 Features Monitorina 7.5.2.4 Analysis of CEA Position 7.5-16 Indication 7.5.2.5 Analysis of Post-Accident 7.5-16 Monitorina Instrumentation 7.5.2.5.1 Equipment Qualification 7.5-17 j 7.5.2.5.2 Redundancy 7.5-18 ' 7.5.2.5.3 Power Source 7.5-19 7.5.2.5.4 Channel Availability 7.5-20 7.5.2.5.5 Quality Assurance 7.5-21 0 7.5.2.5.6 Display and Recording 7.5-21 ! 7.5.2.5.7 Range 7.5-22 j 7.5.2.5.8 Equipment Identification 7.5-22 ' 7.5.2.5.9 Interfaces 7.5-23 7.5.2.5.10 Servicing, Testing and Calibrati.on 7.5-24 7.5.2.5.11 Human Factors 7.5-24 7.5.2.5.12 Direct Measurement 7.5-25 7.5.2.6 Analysis of Automatic Bypass 7.5-25 Indication l l 7.5.2.7 Analysis of Inadeauate Core 7.5-26 I Coolina Monitors O1 Amendment D xiv September 30, 1988 l j
-CESSAR Encarie.
O TABLE OF CONTENTS (Cont'd) CKAPTER 7 Section Subject Pace No. 7.5.2.7.1 Description of ICC Progression 7.5-26 (Coolant States Related to ICC) D 7.5.2.7.1.1 Approach to ICC 7.5-27 7.5.2.7.1.2 Recovery from ICC 7.5-28' 7.5.2.7.2 Instrument Range 7.5-28 7.6 ALL OTHER INSTRUMENTATION SYSTEMS 7.6-1 REOUIRED FOR SAFETY 7.
6.1 INTRODUCTION
7.6-1 7.6.1.1 System Descriptions 7.6-1 7.6.1.1.1 Shutdown Cooling System Suction 7.6-1 Lino Valve Interlocks O,- 7.6.1.1.2 Safety Injection Tank Isolation Valve Interlocks 7.6-2 7.6.1.1.3 DIAS Channel N and DPS Alarms 7.6-3 7.6.1.1.3.1 Reactor Coolant Pump 7.6-3 < Cooling Water Supply D Monitoring 7.6.1.1.3.2 Safety Injection Tank 7.6-3 Pressure Monitoring 7.6.1.1.4 Fire Protection Instrumentation 7.6-4 and Detection System , l 7.6.1.2 Desian Bases 7.6-4 7.6.1.2.1 Shutdown Cooling System Suction 7.6-4 Line Valve Interlocks 7.6.1.2.2 Safety Injection Tank Isolation 7.6-5 Valve Interlocks 7.6.1.3 System Drawinas 7.6-5 i 7.6.2 ANALYSIS 7.6-5 l 7.6.2.1 Desian Criteria 7.6-5
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CESSAR HMicari:n O TABLE OF CONTENTS (Cont'd) CHAPTER 7 Section Bubiect Pace No. 7.6.2.1.1 Shutdown Cooling System Suction 7.6-5 Line Valve Interlocks 7.6.2.1.2 Safety Injection Tank Isolation 7.6-6 Valve Interlocks 7.6.2.1.3 DIAS Channel N and DPS Alarms 7.6-6 7.6.2.1.3.1 Reactor Coolant Pump Cooling 7.6-6 D supply Monitoring 7.6.2.1.3.2 Safety Injection Tank 7.6-7 Pressure Monitoring 7.6.2.2 Eauinment Desian Criteria 7.6-7 7.6.2.2.1 Shutdown Cooling System Suction 7.6-7 Line Valve Interlocks 7.6.2.2.2 Safety Injection Tank Isolation 7.6-10 Valve Interlocks 7.6.2.3 fire Protection Instrumentation 7.6-13 and Detection System D 7.7 CONTROL SYSTEMS NOT REOUIRED FOR SAFETY 7.7-1 7.
7.1 DESCRIPTION
7.7-1 7.7.1.1 Control Systems 7.7-1 7.7.1.1.1 Reactivity Control Systems 7.7-1 7.7.1.1.2 Pressurizer Pressure and Level 7.7-4 Control Systems D 7.7.1.1.2.1 Pressurizer Pressure Control 7.7-4 System 7.7.1.1.2.2 Pressurizer Level Control 7.7-5 System 7.7.1.1.3 Megawatt Demand Setter 7.7-5 7.7.1.1.4 Feedwater Control System 7.7-8 7.7.1.1.5 Steam Bypass Control System 7.7-9 7.7.1.1.6 Reactor Power Cutback System 7.7-10 7.7.1.1.7 Boron Control System 7.7-12 7.7.1.1.8 In-Core Instrumentation System 7.7-13 7.7.1.1.9 Ex-Core Neutron Flux Monitoring 7.7-13 1 System D Amendment D xvi September 30, 1988 1
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l O TABLE OF CONTENTS (Cont'd) l CHAPTER 7 Section Subiect Pace No. 7.7.1.1.10 Boron Dilution Alarm System 7.7-14 7.7.1.1.11 Alternate Protection System 7.7-14 7.7.1.1.12 Process Component Control System 7.7-15 D 7.7.1.1.13 Control and Monitoring Systems 7.7-16 Sensed Parameters 7.7.1.2 Desian Comnarison 7.7-20 7.7.1.2.1 Reactivity Control Systems 7.7-20 7.7.1.2.2 Pressurizer Pressure and Level 7.7-20 Control Systems D 7.7.1.2.3 Megawatt Demand Setter ~7.7-20 7.7.1.2.4 Feedwater Control System 7.7-21 7.7.1.2.5 Steam Bypass Control System 7.7-21 7.7.1.2.6 Reactor Power Cutback System 7.7-21 7.7.1.2.7 Boron Control System 7.7-21 j-~ 7.7.1.2.8 In-Core Instrumentation System 7.7-21 ( j 7.7.1.2.9 Ex-Core Neutron Flux Monitoring 7.7-21 System 7.7.1.2.10 Boron Dilution Alarm System 7.7-22 l 7.7.1.2.11 Alternate Protection System 7.7-22 l 7.7.1.2.12 Process Component Control System 7.7-22 ' 7.7.1.1.13 Control and Monitoring Systems 7.7-22 D Sensed Parameters 7.7.1.3 Advanced Control Complex 7.7-23 l 7.7.1.3.1 Main Control Room and Panels 7.7-24 l 7.7.1.3.2 Technical Support Center and 7.7-26 Emergency Operations Facility Interfaces i I 7.7.1.4 Himgrete Indication and Alarm 7.7-26 i SVadam (DIAS) 7.7.1.4.1 DIAS System Architecture 7.7-27 7.7.1.4.2 Discrete Indicators 7.7-29 7.7.1.4.3 Alarm Tiles and Message Windows 7.7-30 7.7.1.4.4 DIAS Environmental Qualification 7.7-31 i 7.7.1.4.5 DIAS Quality Classification 7.7-32 l 1 7.7.1.5 Intecrated Process Status Overview 7.7-32 l [Jk-T (IPSO) Amendment D xvii September 30, 1988
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CESSAR s!!Mem - O TABLE OF CONTENTS (Cont'd) l CHAPTER 7 Section Subiect Pace No. i 7.7.1.5.1 IPSO Configuration 7.7-33 7.7.1.5.2 IPSO Big Board Panel 7.7-33 7.7.1.5.3 DPS IPSO Display 7.7-34 7.7.1.6 NSSS Intecrity Monitorina System 7.7-34 7.7.1.6.1 Internals Vibration Monitoring 7.7-34 System (IVMS) j 7.7.1.6.2 Acoustic Leak Monitoring System 7.7-35 (ALMS) 7.7.1.6.3 Loose Parts Monitoring System 7.7-37 ! (LPMS) 7.7.1.7 Data Processina System (DPS) 7.7-37 7.7.1.7.1 DPS Functions 7.7-38 7.7.1.7.2 DPS Configuration 7.7-40 7.7.1.7.3 DPS Environmental Qualification 7.7-42 ' 7.7.1.7.4 DPS Verification and Validation 7.7-42 Requirements 7.7.1.8 DPS NSSS Annlications Procrams 7.7-42 1 7.7.1.8.1 Core Operating Limit Supervisory D 7.7-42 l System (COLSS) I i 7.7.1.8.1.1 General 7.7-42 . 7.7.1.8.1.2 System Description 7.7-44 l 7.7.1.8.1.3 Description of COLSS 7.7-46 Algorithms 7.7.1.8.1.3.1 Reactor Coolant 7.7-46 Volumetric Flow Rate 7.7.1.8.1.3.2 Core Power Calculation 7.7-46 7.7.1.8.1.3.3 COLSS Determination of 7.7-47 ; Power Distribution j 7.7.1.8.1.3.4 Core Power Operating 7.7-49 . Limit Based on Peak I Linear Heat Rate li 7.7.1.8.1.3.5 Core Power Operating 7.7-49 Limit Based on Margin f to DNB l l O i l Amendment D l xviii Septenber 30, 1988 l
CESSAREnWncum i ( 1 TABLE OF CONTENTS (Cont'd) CHAPTER 7-Section Subiect Pace No. 7.7.1.8.1.4 Calculation and Measurement 7.7-49
' Uncertainties 7.7.1.8.2 NSSS Monitoring Programs 7.7-50 7.7.1.8.3 NSSS Interactive Programs 7.7-54
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l 7.7.1.9 Balance of Plant Application 7.7-54 Proarams D 7.7.1.10 DPS Critical Functions Monitorina 7.7-55 < Procram j 1 7.7.2 ANALYSIS 7.7-56 l O i
.4 Amendment D xix September 30, 1988
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CESSAR Enhio. O LIST OF TABLES CHAPTER 7 Table Bubiect 7.1-1 Auxiliary and Supporting System Descriptions E 7.2-1 Reactor Protective System Bypasses 7.2-2 Reactor Protective System Monitored Plant Variable Ranges 7.2-3 Reactor Protective System Sensors 7.2-4 Reactor Protective System Design Inputs 7.2-5 Plant Protection System Failure Modes and Effects Analysis 7.3-1 ESFAS Bypasses 7.3-2 Design Basis Events Requiring ESF System Action 7.3-3 Monitored Variables Required for ESFAS Protective Signals 7.3-4 Engineered Safety Features Actuation System Sensors 7.3-5 Engineered Safety Features Actuation System Setpoints and Margins to Actuation 7.3-6 Engineered Safety Features Actuation System Plant Variable Ranges 7.4-1 Remote Shutdown Panel Instrumentation and Controls for Hot Standby D 7.4-2 Remote Shutdown Controlled Functions for Cold Shutdown ; 7.5-1 Safety-Related Plant Process Display Instrumentation 7.5-2 Engineered Safety Feature System Monitoring 7.5-3 Post-Accident Monitoring Instrumentation 9 Amendment E xx December 30, 1988 l J
_ l' CESSAREink m., o b LIST OF TABLES (Cont'd) CHAPTER 7 Table Subiect 7.6-1 Shutdown Cooling System and Safety Injection Tank Interlocks ! D 1 l 7.7-1 Alternate Protection System Sensed Parameters ! 7.7-2 DIAS Segments 7.7-3 Typical Sensor Locations for Acoustic Leak E Monitoring System 7.7-4 Location of Loose Parts Monitoring System Accelerometers 7.7-5 D DPS Nuclear Steam Supply System Application Programs j ii 7.7-6 COLSS Monitored Plant Variables 7.7-7 Balance of Plant Application Programs ' D l l l l
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CESSAREnkbmu IIIl LIST OF FIGURES ! CHAPTER 7 Fiqure Subiect 7.2-1 PPS Basis Block Diagram 7.2-2 PPS Functional Interface and Testing Diagram 7.2-3 Typical PPS Low Reactor Coolant Flow Trip Setpoint Operation i 7.2-4 Typical PPS Measurement Channel Functional ~ Diagram (Pressurizer Pressure Wide Range) 7.2-5 Reed Switch Position Transmitter Assembly Schematic 7.2-6 Reed $ witch Position Transmitter Cable Assemblies 7.2-7 DNBR/LPD Calculator System (CEA Calculators) 7.2-8 Ex-Core Neutron Flux Monitoring System E j 7.2-9 Reactor Coolant Pump Speed Sensors Typical for Each Reactor Coolant Pump 7.2-10 Core Protection Calculator Functional Block Diagram 7.2-11 PPS Bistable Trip Logic Functional Block Diagram 7.2-12 PPS Reactor Trip System Functional Logic Diagram 7.2-13 Typical PPS Channel Functional Bistable Trip Channel ' Bypass 7.2-14 Typical PPS Channel Functional RPS Initiation Logic 7.2-15 Typical PPS Variable Setpoint Operation (Manual l Reset) { i 7.2-16 PPS Testing Overlap i 7.2-17 PPS Manual Bistable Trip Test Functional Block Diagram O\ Amendment E xxii December 30, 1988 l J
CESSAREin bio O LIST OF FIGURES (Cont'd) CHAPTER 7 F_Lgure subiect 7.2-18 Typical PPS Channel Contact Bistable Interface Diagram 7.2-19 Plant Protection System Interface Logic Diagram 7.2-20a MCBD Symbols, Notes and Abbreviations l 7.2-20b MCBD Symbols, Notes and Abbreviations 7.2-20c MCBD Symbols, Notes and Abbreviations 7.2-21a RCS Loop 1 Temperatures (Narrow) MCBD 7.2-21b RCS Loop 2 Temperatures (Narrow) MCBD 7.2-22a RCS Loop 1 Temperatures (Wide) MCBD 7.2-22b RCS Loop 2 Temperatures (Wide) MCBD 7.2-23a Reactor Coolant Pump Pressure MCBD 7.2-23b Reactor Coolant Pump Speed MCBD 7.2-24 Pressurizer Pressure MCBD 7.2-25 Nuclear Instrumentation MCBD 7.2-26 Containment Pressure MCBD 1 7.2-27a Steam Generator-1 Level (Wide) MCBD 7.2-27b Steam Generator-2 Level (Wide) MCBD 7.2-28a Steam Generator-1 Pressure MCBD l 7.2-28b Steam Generator-2 Pressure MCBD 7.2-29a Steam Generator-1 Level (Narrow) MCBD l 7.2-29b Steam Generator-2 Level (Narrow) MCBD 7.2-30 Steam Generator Primary D/P MCBD O i Amendment E l xxiii December-30, 1988 l' l
CESSAR Enacucu 9 LIST OF FIGURES (Cont'd) CHAPTER 7 9 Fiqure gubiect 7.3-la ESFAS Functional Logic (SIAS) 1 7.3-lb ESFAS Functional Logic (CSAS, CIAS) i 7.3-1c ESFAS Functional Logic (MSIS) 7.3-1d ESFAS Functional Logic (EFAS 1, EFAS 2) 7.3-2 ESF-CCS Simplified Logic Diagram for Typical , Selective 2 out of 4 Actuation j 7.3-3 Functional Diagram of Engineered Safety Features-Component Control System (ESF-CCS) l 7.3-4 Typical Electrical Interface for Panel-Mounted Switches and Status Indicators E 7.3-5 Diesel Load Sequencer-Simplified Logic Diagram h 7.3-6 Diesel Load Sequencer-Simplified Test Logic Diagram 7.3-7 ESF-CCS Test Logic-Simplified Logic Diagram 7.3-8a Typical FCLD for a Solenoid-Operated Valve 7.3-8b Typical Electrical Interface for a Solenoid-Operated Valve 7.3-9a Typical FCLD for a Modulating Valve with Solenoid-Operator 7.3-9b Typical Electrical Interface for a Modulating l Valve with Solenoid Operator 7.3-10a Typical MOV Functional Interface Design 7.3-10b Typical Electrical Interface for a Motor-Operated Valve 7.3-11 Typical FCLD for a Full Throw McLor-Operated j Valve Amendment E xxiv December 30, 1988 j
CESSAR !!nincmou O LIST OF FIGURES (Cont'd) CHAPTER 7 Fiqure Subiect 7.3-12 Typical FCLD for a Throttling Motor-Operated Valve 7.3-13a Typical FCLD for a Contactor-Operated Component 7.3-13b Typical Electrical Interface for a Contactor-Operated Component 7.3-14a Typical FCLD for a Circuit Breaker-Operated Component 7.3-14b Typical Electrical Interface for a Circuit Breaker-Operated Component 7.3-15a Typical FCLD for a Modulating Component 7.3-15b Typical Electrical Interface for a Modulating O. Component 7.3-16 Typical ESF Initiation to Actuation Logic E Functional Diagram 7.3-17 Simplified Schematics for Thermal Overload 7.3-18 In-containment Refueling Water Storage Tank MCBD 7.3-19 Reactor Drain Tank MCBD 7.3-20a Safety Injection Tank 1 MCBD 7.3-20b Safety Injection Tank 2 MCBD 7.3-20c Safety Injection Tank 3 MCBD 7.3-20d Safety Injection Tank 4 MCBD 7.3-21 Containment Spray MCBD 7.3-22 Shutdown Cooling MCBD 7.3-23 Safety Injection MCBD Amendment E xxv December 30, 1988
CESSAR Ennnema O LIST OF FIGURES (Cont'd) CHAPTER 7 Fiqure subiect 7.3-24 Safety Depressurization MCBD 7.5-1 Post-Accident Monitoring 7.5-2 HJTC Sensor-HJTC/ Splash Shield 7.5-3 Heated Junction Thermocouple Probe Assembly 7.5-4 HJTC Sensor and Separator Tube 7.5-5 In-core Instrumentation Locations D 7.5-6 Electrical Diagram of HJTC 7.5-7 HJTC System Processing Configuration (One Channel Shown) E 7.5-8 Pressurizer Level MCBD f 7.6-la Functional Control Logic, Shutdown Cooling System 7.6-1b Functional Control Logic, Shutdown Cooling System 7.6.lc Functional Control Logic, Shutdown Cooling System 7.6-2 Functional Control Logic, Safety Injection System 7.6-3 Safety-Related Interlock Test Method 7.7-1 Reactor Regulating System Block Diagram 7.7-2 CEDMCS - RPS Interface Block Diagram 7.7-3 Pressurizer Pressure Control System Block Diagram 7.7-4 Pressurizer Level Control System Block Diagram 7.7-5 Megawatt Demand Setter Block Diagram 7.7-6 Simplified MDS Block Diagram, Automatic Dispatch Mode D 7.7-7 Feedwater Control System Block Diagram 7.7-8 Steam Bypass Control System Block Diagram I Amendment E xxvi December 30, 1988 L___- _ _ _ _ _ _ ____
CESSAR ElMincamn /* U LIST OF FIGURES (Cont'd) CHAPTER 7 Fiqure Subject 7.7-9 Reactor Power Cutback System Simplified Block Diagram 7.7-10 Baronometer Block Diagram 7.7-11 Boron Dilution Alarm System Simplified Block Diagram 7.7-12 Alternate Protection System Block Diagram 7.7-13 Process-Component Control System Simplified Block Diagram 7.7-14 Nuplex 80+ Control Room 7.7-15 ACC Information Processing Block Diagram (Q/ 7.7-16 DIAS-P Segment Architecture 7.7-17 DIAS-N Segment Block Diagram 7.7-18 Discrete Indicator (Pressurizer Pressure and Level) 7.7-19 IPSO / DIAS /DPS Data Communications 7.7-20 Block Diagram of the Data Processing System 7.7-21 Overview of Hierarchical Display Structure D 7.7-22 Data Processing System Configuration 7.7-23 Functional Diagram of the Core Operating Limit Supervisory System l 7.7-24 Alternate Protection System (ARTS) MCBD 1 E 7.7-25a Alternate Protection System (AFAS-1) MCBD 7.7-25b Alternate Protection System (AFAS-2) MCBD i I s/ 2 1 Amendment E j xxvii December 30, 1988 ! l
( h h khk bkbkflCATl3N l l l O' LIST OF ABBREVIATIONS CHAPTER 7 ACC - Advanced Control Complex ADS - Automatic Dispatch System I AFAS - Alternate Feedwater Actuation System { APS - Alternate Protection System j ARTS - Alternate Reactor Trip System ! AWP - Automatic Withdrawal Prohibit ! BCS - Boron Control System BDAL - Boron Dilution Alarm Logic CCS - Component Control System CEDMCS - Control Element Drive Mechanism Control System CMI - CEA Motion Inhibit CRT - Cathode Ray Tube CWP - CEA Withdrawal Prohibit DIAS - Discrete Indication and Alarm System DPS - Data Processing System , EOF - Emergency Operations Facility ) t ESF - Engineered Safety Feature FWCS - Feedwater Control System IVMS - Internals Vibration Monitoring System i IPSO - Integrated Process Status Overview MCR - Main Control Room D MDS - Megawatt Demand Setter NDL - Nuclear Data Link NPM - Nuclear Power Module < PAMI - Post-Accident Monitoring Instrumentation PCCS - Process Component Control System (Process CCS) PI - Proportional Integral PLCS - Pressurizer Level Control System PPCS - Pressurizer Pressure Control System PPS - Plant Protection System RPCS - Reactor Power Cutback System RPS - Reactor Protective System l RRS - Reactor Regulating System RSCR - Remote Shutdown Control Room RSP - Remote Shutdown Panel RTSS - Reactor Trip Switchgear System SBCS - Steam Bypass Control System SPDS - Safety Parameter Display System TCS - Turbine Control System TSC - Techical Support Center , 1 O Amendment D xxviii September 30, 1988 l l
CESSAR85bmu n ( )
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7.0 INSTRUMENTATION AND CONTROLS
7.1 INTRODUCTION
The System 80+* Standard Design includes the Nuplex 80+* Advanced Control Complex (ACC). The design integrates both NPM and BOP instrumentation and control interfaces into the ACC design. The ACC design consists of the following major interdependent systems: Main control Panels (MCP), Remote Shutdown Panel (RSP) , Discrete Indicator and Alarm Sytem (DIAS), an expanded Data Processing System (DPS), ESF and Process Component Control D Systems (CCS), Megawatt Demand Setter (MDS) and all the systems which were in the previous System 80 design as described in CESSAR-F. The Nuplex 80+ design takes advantage of modern digital processing equipment to implement the safety, control and information display systems. These systems are implemented in accordance with the Human Factors Engineering design criteria and process as described in Chapter 18.
,r~ 7.1.1 IDENTIFICATION OF SAFETY-RELATED SYSTEMS i )
G' The safety-related instrumentation and controls, including supporting systems, are identified below. The responsibility for the design of each system is identified as follows: Combustion Engineering (C-E) Others (O) 7.1.1.1 Plant Protection System (PPS) (C-E) The PPS includes the electrical and mechanical devices and circuitry required to perform the protective functions defined below. A. Reactor Protective System (RPS) The RPS is the portion of the PPS that acts to trip the reactor when required. The RPS is described in Section 7.2. B. Engineered Safety Features Actuation System (ESFAS) The ESFAS is the portion of the PPS which activates the Engineered Safety Feature systems listed in Section 7.1.1.3 and described in Section 7 3.
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Amendment D 7.1-1 September 30, 1988 t _ _ _ _ _ _ _ _ _ -
k)! h!h)khI bb. IC ATl* N l 9 7.1.1.1.1 Alternate Protection System (APS) (C-E) The Alternate Protection System (APS) augments reactor protection and emergency feedwater actuation by utilizing non-1E trip logic U I which is separate and diverse from the Plant Protection System. Refer to Section 7.7.1.1.11 for a description of these ATWS mitigation systems. I 7.1.1.2 Reactor TriD System (RTS) (C-E) l The RTS includes the RPS portion of the PPS, Reactor Trip Switchgear System (RTSS) and the arrangement of components that perform a reactor trip after receiving a signal from the RPS j either automatically or manually by the operator. The RTS j initiates a reactor trip based on the signals from the sensors > which monitor various NSSS parameters and the containment pressure. ; i 7.1.1.3 Encineered Safety Feature Systems (ESF Systems) l l l The ESF Systems include the ESFAS and the arrangement of i components that perform protective actions after receiving a signal from the ESFAS or the operator. The ESF Systems are: A. Containment Isolation System (C-E) / (0) B. Main Steam Isolation System (0) C. Safety Injection System (C-E) D. Emergency Feedwater System (C-E) / (O) D 1 E. Containment Spray System (C-E) / (0) F. Safety Depressurization System (C-E) G. Supporting Systems (O) The instrumentation and controls for ESF Systems are described in Section 7.3. 7.1.1.4 Systems Required for Safe Shutdown l Systems required for safe shutdown are defined as those essential ( for pressure and reactivity control, coolant inventory makeup, and removal of residual heat once the reactor has been brought to a subcritical condition. These systems are categorized according to the following shutdown modes: Amendment D 7.1-2 September 30, 1988
CESSARENGem,, ! s I ( A. Het Shutdown Systems required for maintenance of the primary system at, or near, operating temperature and pressure. B. Cold Shutdown Systems required to cool down and maintain the primary system at, or near, ambient conditions. C. Safe Shutdown The systems required for safe shutdown are listed below. and ; described in Section 7.4. The safe shutdown systems required to place the reactor in hot shutdown include: A. Emergency Diesel Generator (O) B. Emergency Diesel Generator Fuel Storage and Transfer System (0) l C. Emergency Power Storage System (0) D. Emergency On-site Power Distribution System (0) E. Safety Injection System (C-E) F. Emergency Feedwater System (C-E) / (0)
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G. Atmospheric Steam Dump System (0) ! l' H. Safety Depressurization System (C-E) In addition, Remote Shutdown Panel (RSP) equipment and systems l are provided to allow emergency shutdown from outside the control room. The safe shutdown systems or portions of systems required to place the reactor in cold shutdown include those in A. through H. above, plus the following: I. Station Service Water System (0) J. Component Cooling Water System (O) K. Shutdown Cooling System (C-E) D C L. Heating, Ventilating and Air Conditioning Systems (0) Amendment D 7.1-3 September 30, 1988 I n j
CESSAREneb . I O l 7.1.1.5 Safetv-Related Displav Instrumentation The safety-related display instrumentation provides information to the operator to allow him to adequately monitor plant operating conditions and to perform any required manual safety functions. Safety-related display instrumentation is described in Section 7.5. Safety-related displays are provided for: A. Safety-Related Plant Process Display Instrumentation (C-E)/ (0) B. Reactor Trip System Monitoring (C-E) C. Engineered Safety Features Actuation System Monitoring (C-E) / (0) D. CEA Position Indication (C-E) E. Post-Accident Monitoring Indication (C-E) / (O) F. ESF Systems Performance and Availability (C-E),' ?) ' Indication G. Critical Functions Monitoring Indication (C-E) / (O) 7.1.1.6 All Other Systems Recuired for Safety Other systems required for safety include the interlocks required to prevent overpressurization of the Shutdown Cooling System and to ensure safety injection availability. These are provided as listed below and described in Section 7.6. A. Shutdown Cooling System Suction Line Isolation Valve Interlocks (C-E) B. Safety Injection Tank Isolation Valve Interlocks (C-E) 7.1.1.7 Desian Comparison The Peactor Protective System (RPE is designed by Combustion Engineering. The system will be functionally identical to the system provided for the Palo Verde Nuclear Generating Station (PVNGS, NRC Docket No. 50-528) with the following exception: () The Supplementary Protection System (SPS) is replaced by the Alternate Protection System (APS), as described in Section 7.7.1.1.11. The APS is specifically designed to increase the reliability of reactor trip initiation and address ATWS Amendment D 7.1-4 September 30, 1988
CESSARM5Lmu 10 V Mitigating Systems Actuation Circuitry (AMSAC) . requirements by incorporating an alternate emergency feedwater actuation j signal. The Engineered Safety Features Actuation System (ESFAS) is designed by Combustion Engineering. Each initiation system D logic, including testing features, is similar to the logic for f the RPS and is contained in the same physical enclosures. The l actuation logic and devices are contained in the ESF Component j Control System (CCS). The danign of this system is-described in Section 7.3. The following ESFAS changes from the PVNGS design have been made: A. Recirculation Actuation Signal (RAS) has been deleted due to the addition of the in-containment refueling water storage tank. B. EFAS initiation logic is simplified- by deleting the requirement for individual automatic identification and isolation of a ruptured steam generator. 7.1.1.8 System Drawines I & C system Measurement Channel Block Diagrams (MCBDs), functional, control and logic diagrams 'till appear at the end of each section of Chapter 7. All other I & C drawings for the auxiliary support systems are located within the applicable system section of CESSAR-DC. 7.1.2 IDENTIFICATION OF SAFETY CRITERIA Comparison of the design with applicable Regulatory Guide recommendations and the degree of compliance with the appropriate design bases, General Design Criteria, standards, and other documents used in the design of the systems listed in Section l 7.1.1 are described in Sections 7.1.2.2 through 7.1.2. 34, and in each of the sections describing the system. (Refer to Sections , 7.2 through 7.6.) l 7.1.2.1 Desian Bases l The design bases for the safety-related instrumentation and control of each safety-related system are presented in the section of this chapter that discusses the system to which the information applies. l Consideration has been given to instrument error in the selection l A of all safety system setpoints. Where setpoints are listed in
.\ Chapter 7, it is understood that these are nominal values. The actual setpoint may vary within prescribed accuracies which have been considered in selection of the values.
Amendment D 7.1-5 September 30, 1988
CESSARnnL - 7.1.2.1.1 Systems Required for Plant Protection The instrumentation and controls for the Reactor Trip System and D Engineered Safety Feature systems conform to the following: A. The systems conform to IEEE Standards 279-1971 and 603-1980. l D Detailed discussion of conformance for these and other safety-related system instrt antation and controls is provided in the applicable section of this chapter. Conformance to these and other IEEE Standards is in Sections 7.1.2.2 through 7.1.2.13. discussed Dl B. Comparison with Regulatory Guide recommendations for Water-Cooled Nuclear Power Plants, Division of Reactor Standards, Nuclear Regulatory Commission, is discussed in Sections 7.1.2.5 through 7.1.2.10, and 7.1.2.13 through 7.1.2.34. D C. The quality assurance program is described in Chapter 17. D. General Design Criteria for Nuclear Power Plants, Appendix A to 10 CFR 50 as described in Section 3.1. 7.1.2.1.2 Systems Required for Safe Shutdown The design bases for the systems required for safe shutdown are described in Section 7.4. 7.1.2.1.3 Safety-Related Display Instrumentation The design bases for safety-related display instrumentation, are described in Section 7.5. 7.1.2.1.4 All Other Systems Required for Safety The design bases for all other systems required for safety are described in Section 7.6. Auxiliary and support systems not in the Nucle - Power Module D (NPM) licensing scope, but necessary to the proper functioning of NPM licensing scope safety systems are identified in the CESSAR section for the safety system requiring the support system. Descriptions of these systems are included in the appropriate E CESSAR section as identified in Table 7.1-1. O Amendment E 7.1-6 December 30, 1988 v
CESSAR E!L"icari:n V I 7.1.2.2 Conformance to IEEE 279-1971 l . Extent of conformance to IEEE Standard 279-1971 is discussed in l Sections 7.2, 7.3 and 7.6. 7.1.2.3 Conformance to IEEE 308-1980 Standardized Functional Descriptions of electrical components, equipment and systems which are not within the System 80+ D Standard Design but which are vital to safe operation are described in Chapter 8. Conformance to IEEE. 308-1980, "IEEE Standard Criteria for Class 1E Power Systems for Nuclear Power p Generating Stations," as criteria in the design of these systems ! is discussed in the site-specific SAR. 7.1.2.4 Conformance to IEEE 317-1983 a l Electrical penetrations and their conformance to IEEE 317-1983, i
" Electrical Penetration Assemblies in Containment Structures for Nuclear Power Generating Stations," will be discussed in the site-specific SAR.
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m 7.1.2.5 Conformance to IEEE 323-1983, as Auamente_4 { by Reculatory Guide 1.89 (Rev. 1, 6/84) l Compliance with IEEE 323-1983, "IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations," for D instrumentation is discussed in Combustion Engineering Topical , Report CENPD-255-A, " Qualification of Combustion Engineering Class 1E Instrumentation" (Reference 2). The basic qualification requirements are discusE.ed in Section 3.11. 7.1.2.6 Conformance to IEEE 336-1985, as Aucmented by Reculatory Guide 1.30 (Rev. O, 8/72) Conformance with IEEE 336-1985, " Installation, Inspection, and Testing Requirements for Instrumentation and Electric Equipment During the Construction of Nuclear Power Generating Stations," are discussed in Section 1.8 and the site-specific SAR. 7.1.2.7 Conformance to IEEE 338-1977, as Aucmented by D Reculatory Guide 1.118 (Rev. 2, 6/78) The PPS and ESF-CCS, as well as the RTSS, are designed so that they can be periodically tested in accordance with the criteria of IEEE 338-1977, " Periodic Testing of Nuclear Power Generating Station Class 3E Power and Protection Systems." Combustion Engineering supplies the response times of instrumentation and O control components as a result of factory tests to the site D U Amendment D 7.1-7 September 30, 1988
CESSAREnnnem O operator. It is the site operator's responsibility to test the lD integrated response time of each protection system after installation. Testing criteria are specified in Sections ; 7.2.2.3.3 and 7.3.2.3.3. Minimum testing frequency requirements ( are provided in the Technical Specifications (Chapter 16). l Since operation of the ESF Systems is not expected, the systems are periodically tested to verify operability. Complete channels, in the NPM ESFAS, can be individually tested without D initiating protective action and without inhibiting the operation of the system. The system can be checked from the sensor signal through the actuation devices. The functional modules in the sensor system can be tested during reactor operation. The sensors can be checked by comparison with similar channels. Those actuated devices, which are not tested during reactor operation, will be tested during scheduled reactor shutdown to show that they are capable of performing the necessary functions. 7.1.2.8 Conformance to IEEE 344-1987, as Augmented by Reculatory Guide 1.100 (Rev. 1, 8/77) D Compliance with IEEE 344-1987, "IEEE Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations," is discussed in Combustion Engineering Topical Report CENPD-182, "Seisnic Qualification of Instrumentation Equipment," (Reference 3). The basic seismic qualification requirements are discussed in Section 3.10. The adequacy of the design of Class 1E Equipment is verified by a combination of testing and/or analysis for the performance of its D functions during and after the equipment is subjec.ted to the forces resulting from one SSE preceded by a number of DBEs. Also, the similarity between the tested equipment and the , installed equipment is proven (e.g., design, orientation, foundation, per f ormance) ,. The seismic tests take into ! consideration the operability of the equipment during seismic events. 7.1.2.9 Conformance to IEEE 379-1977, as Augmented by Regulatory Guide 1.53 (Rev. O, 6/73) Instrumentation for the PPS and ESF CCS, and the RTSS conform to the requirements of IEEE 379-1977, "IEEE Standard Application of the Single Failure Criterion to Nuclear Power Generating Station Class 1E Systems," as augmented by Regulatory Guide 1.53,
" Application of the Single Failure Criterion to Nuclear Power Amendment D 7.1-8 September 30, 1988
CESSARMu h a
.G Plant Protection Systems." A discussion of the application of the single failure criterion is provided in Sections 7.2.2.3.2 and 7.3.2.3.2 for these systems.
7.1.2.10 Conformance to IEEE 384-1981, as Augmented by D j Regulatory Guide 1.75 (Rev. 2, 9/78) The instrumentation for the safety-related electric systems conforms to the requirements of IEEE 384-1981, "IEEE Standard Criteria for Independence of Class 1E Equipment and Circuits," as augmented by Regulatory Guide 1.75, " Physical Independence of Electric Systems." A discussion of the physical independence is provided below which describes the compliance with Section 4.6 of IEEE 279-1971 and General Design Criteria 3 and 21. The PPS is divided into four assemblies which are physically l located in different geographic fire zones within the control complex. Each assembly contains one of the four redundant channels of the RPS and ESFAS. This provides the separation and independence necessary to meet the requirements of Section 4.6 of l IEEE 279-1971. The independence and separation of redundant Class 1E circuits (A) U within and between the PPS assemblies or ESF-CCS assemblies is accomplished primarily through the use of fiber-optic technology and, as necessary, by 6-inch separation, barriers or conduits. The optical technology ensures that no single credible event in a PPS channel can prevent the circuitry in any other redundant D channel from performing its safety function. The ESF Component Control System cabinets provide separation and independence for the selective two-out-of-four actuation and component control logic of the redundant ESF systems trains. Each train's component control logic is contained in a separate cabinet. The redundant cabinets are physically separated from each other by locating them in separate zones. Redundant train remote I/O multiplexer are located to maintain physical separation. The RTSS consists of a set of four Reactor Trip Switchgears l ' (RTSG). Each RTSG and its associated switches, contacts and l relays is contained in a separate cabinet. Each cabinet is physically separate from the other cabinets. This method of construction ensures that a single credible failure in one RTSG cannot cause malfunction or failure in another cabinet. The separation and independence of the power supplies for each of the above systems is discussed further in Chapter 8. ( \ () Protection system analog and digital signals sent to non-Class 1E systems for status monitoring, alarm and display (e.g., DPS, Amendment D 7.1-9 September 30, 1988
1 CESSAR inL"lCATION l l are isolated from the protection system. 9 l DIAS, CEDMCS) Tiber-optic isolation and other techniques are used to ensure no credible failures on the non-1E side of the isolation device will affect the PPS side and that independence of the PPS is not jeopardized. 7.1.2.11 Conformance to IEEE 387-1984 Conformance to IEEE 387-1984 , "IEEE Standard Criteria for Diesel-Generator Units Applied as Standby Power Supplies for Nuclear Power Generating Stations," as criteria in the design of these systems is discussed in Sections 8.3.1, and 9.5.4 through 9.5.8. 7.1.2.12 Conformance to IEEE 450-1980 Conformance to IEEE 450-1980, "IEEE Recommended Practice for Large Lead Storage Batteries for Generating Stations al.d Substations," as criteria in the design of these systems is discussed in Chapter 8 and the site-specific SAR. 7.1.2.13 Conformance to IEEE 603-1980, as Augmented by Reculatory Guide 1,153 (Rev. O, 12/85) The safety systems such as PPS, ESF-CCS and RTSS conform to the requirements of IEEE 603-1980, " Standard Criteria for Safety Systems for Nuclear Power Generating Stations," as augmented by Regulatory Guide 1.153, " Criteria for Power, Instrumentation, and D Control Portion of Safety Systems." For descriptions of conformances, refer to Sections 7.1.2.2, 7.1.2.3, 7.1.2.5, 7.1.2.7, 7.1.2.9 and 7.1.2.10. 7.1.2.14 Comparison of Desicn with Reculatory Guide 1.6 (Rev. O, 3/71) See Chapter 8 and the site-specific SAR. 7.1.2.15 Conformance to Reculatory Guide 1.11 (Rev. O, 3 / 71_), Guidelines for instrument lines which penetrate primary reactor containment, and which are part of the reactor coolant pressure boundary or are connected directly to the containment atmosphere do not apply, since there are no lines which fall directly into this category. Conta.nment pressure is monitored by four redundant pressure transmR m s located outside of :ontainment which monitor containment atmosphere. The lines bo-h inside and . outside containment are kept as short as possible. No other instrument lines penetrate reactor containment. 1 l I Amendment D l 7.1-10 September 30, 1988
CESSAR Ennem:,. l O G J l 7.1.2.16 Conformance to Reculatory Guide 1.17 l (Rev. 1, 6/73) I l The following design features address the requirements of D Regulatory Guide 1.17, " Protection of Nuclear Power Plants Against Industrial Sabotage"- A. Separate Geographic Locations for Equipment , l
- 1. Redundant channels of safety-related instrumentation and control cabinets are designed 'to be located in separate plant locations. These equipment locations can be desigt.ed by the site operator to meet Regulatory Guide 5.7, " Control of Personnel Access to Protected l Areas, Vital Areas and Material Access Areas."
B. Limited Ability to change System Hardware and Software Configurations
- 1. Portions of systems are designed to limit the ability of operating and maintenance personnel to change basic system functions (e.g., setpoints can be changed, but l the trip function calculation cannot be atte"ed).
V 2. The transfer of control between the Main Control Room and Remote Shutdown Panel is under key lock administrative control with built-in alarms.
- 3. The PPS design does not permit bypassing either the RPS or ESFAS signals at the system level. Bypasses can be i initiated in only one of the four redundant protection I channels at a time. Attempts to bypass additional i
channels will automatically put the channel in a trip l state, as discussed in Sections 7.2.1 and 7.3.1.
- 4. Vital instrumentation cabinet doors are locked and equipped with " door open" alarms. l C. Fail-Safe Design Philosophy
- 1. Systems are generally designed to fail safely upon de-energization, removal of printed circuit boards and disconnection of cables and data links.
- 2. Test modes are designed such that they do not prevent system actuation.
O Amendment D 7.1-11 September 30, 1983
1 CESSAR nai"icarieu D. Safety System Status Monitoring
- 1. Critical safety system setpoints can be determined l manually and/or are automatically monitored via the l plant Data Processing System.
- 2. Reactor trip and ESFAS initiation trip channel bypass alarms are provided. l l
- 3. Component level bypasses in the ESF systems result in l system level inoperable alarms for the affected systems, as described in Section 7.1.2.21.
l E. Diverse Manual vs Automatic Reactor Trip and ESFAS Initiation
- 1. Reactor Trip and ESFAS are automatically initiated by the PPS. These same functions can be manually a initiated by the operator. The RTSS and ESF-CCS manual initiation trips do not rely on any PPS components for actuation. Therefore, these functions can be manually initiated with a complete failure of the PPS automatic initiation logic.
The above features are designed to impede sabotage. See Chapter E 13 and the site-specific SAR for a more comprehensive discussion on protection against sabotage. 7.1.2.17 Conformance to Regulatory Guide 1.22 _(Rev. O, 2/72) D The PPS, ESF-CCS, and the RTSS, as described in Section 7.1.1, ; contorm to the guidance of Regulatory Guide 1.22, " Periodic ( Testing of Protection System Actuation Functions." This conformance is described below. A. Provisions are made to permit periodic testing of the complete PPS, ESF-CCS, and RTSS with the reactor operating at power or when shutdown. These tests cover the trip D action from sensor input to actuated devices. Those ESF actuated devices which could affect operations are not tested while the reactor is operating but, instead, are tested while the reactor is shutdown. t B. The provisions of this position are incorporated in the q testing of the PPS, from sensor to actuation device, including the ESFAS and ESF-CCS and the RTSS as designed by D Combustion Engineering and as implemented in the j site-specific SAR. l Amendment E 7.1-12 December 30, 1988
CESSARMMinc-l \ V C. No provisions are made in the design of the PPS, ESF-CCS, D and RTSS at the systems level to intentionally bypass an actuation signal that may be required during power operation. All bypasses are on a channel level to prevent an operator from inadvertently bypassing a trip function. D. The manual testing circuitry for an RPS channel is interlocked to prevent testing in more than one redundant channel simultaneously. When a channel is bypassed for manual testing, the bypass is automatically indicated in the D main control room. > E. When an ESFAS is bypassed for manual testing, the bypass is automatically indicated in the main control room. I F. Actuated devices which cannot be tested during reactor l operation will be tested by the ESFAS circuitry when the reactor is shut down. I A further description of the PPS, RTSS and ESF-CCS test features is provided in Sections 7.2 and 7.3. ] O 7.1.2.18 Conformance to Reculatory Guide 1.2_%, i (Rev. 3, 9/78) The PPS and ESF-CCS and other instrumentation and controls necessary for safety conform to the guidance of Regulatory Guide 1.29, " Seismic Design Classification." This conformance is described below. The systems designated as Seismic Category I are items listed in C.l.k, C.1.1, C.l.n and C l.q. The seismic classification and qualification methods are discussed in Combustion Engineering's Topical Report CENPD-182 (Reference 3), Chapter 18 and Section 3.10. The systems which fall under C.1.q will be discussed in CESSAR Chapter 8 and the site-specific SAR. Those portions of structures, systems, or components whose continued function is not required, are designated as Seismic Category II and designed so that the SSE will not cause a failure D which will reduce the functioning of any plant safety feature to an unacceptable level, including incapacitating injury to the occupants of the control room. , 7.1.2.19 Conformance to Reculatory Guide 1.40 (Rev. O, 3/73) Continuous duty motors and their conformance to Regulatory Guide 1.40, " Qualification Tests of Continuous-Duty Motors Installed Inside the Containment of Water-Cooled Nuclear Power Plants," are discussed in the site-specific SAR. D Amendment D 7.1-13 September 30, 1988
CESSAR 8!'UrlCATCN O 7.1.2.20 Conformance to Recn11atory Guide 1.45 (Rev. O, 5/73) The Acoustic Leak Monitoring System, as described in the NSSS Integrity Monitoring System, Section 7.7.1.6, is employed as one D ! of the three methods of detecting RCS leaks in accordance with Regulatory Guide 1.45, " Reactor Coolant Pressure Boundary Leakage Detection Systems." Refer to Section 5.2.5 for a more comprehensive discussion on RCS leak detection methods. 7.1.2.21 Conformance to Reculatory Guide 1.47 (Rev. O, 5/73) The design of the RPS and the ESFAS as indicated in Sections 7.2 and 7.3, is consistent with the recommendations of Regulatory Guide 1.47, " Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems. " Conformance is described below. A. Annunciator outputs are provided to indicate, at the system level, the bypassing or deliberate inducing of inoperability of a protection system. The system level alarms are actuated when a component actuated by a protection system is bypassed or deliberately rendered inoperable. B. Those auxiliary and support systems within the CESSAR licensing scope provide automatic annunciator activation to indicate, on a system level, the bypassed or deliberately induced inoperability of an auxiliary or support system that effectively bypasses cr renders inoperable a protection system and the systems actuated or controlled by a protection system. , C. Annunciation is provided in the control room, at the system level, for each bypassed or deliberately induced inoperable status in a protection system. i
- 1. These are supplied for those systems discussed in A. I and B. above. J l
- 2. All of these bypasses are expected to be used at least l once a year. )
)
J
- 3. All of these bypasses are expected to be usable when the annunciated system is expected to be operable.
D. The operator is able to activate each system level bypass indicator manually in the control room. O; Amendment D 7.1-14 September 30, 1988 i t - _ __-.__--_o
CESSAR naincam. Bypasses and inoperable status conditions can be classified into the following groups:
- 1) operating bypasses, D
- 2) trip channel bypasses, and
- 3) ESF components inoperable.
There are no system level bypasses for the RPS or-ESFAS. 7.1.2.21.1 Operating Bypasses The operating bypass is used during routine startup and shutdown. These bypasses must be manually inserted. They utilize permissive logic generated from the parameter (s) being bypassed to ensure the bypass is removed if plant. conditions deviate to the point where the bypass is no longer safe. (Example: If the coolant system pressure rises above a predetermined setpoint, the RPS/ESFAS pressurizer pressure bypass is automatically removed. ) Once a bypass is automatically removed, the manual normal l (unbypassed) position must be actuated and then the bypass position reactuated in order to reinsert the bypass. O This prevents cycling the bypass with the permissive contact D Q status. Bypass status indication is provided on the PPS remote operator's modules for each channel. The bypass and bypass permissive status are provided to the plant Data Processing System. operating bypasses include the RPS/ESFAS pressurizer pressure bypass, the high log power bypass and the CPC DNBR/LPD trip bypass. ] 7.1.2.21.2 Trip Channel Bypasses These bypasses are used to individually . bypass channel trip l inputs to the protection system logic for maintenance or testing. The trip logic is converted from a two-out-of-four to a two-out-of-three logic for the parameters being bypassed, while maintaining a coincidence of two for actuation. Only one channel for any one parameter may be bypassed at any one time. These , bypasses must be manually initiated and removed. Individual' bypass. indication is provided locally at' the PPS and at the PPS remote operator's modules located in the control room. In addition, the status of each bypass is provided to the plant Data D Processing System. I 7.1,.2.21.3 ESF Components Inoperable The bypassed and/or inoperable condition of ESF components is monitored by the ESF-CCS, as described in Section 7.3. ESF-CCS status outputs are provided to the Data Processing System (DPS) d which processes logic to indicate at the system. level, the Amendment D 7.1-15 September 30, 1988
l CESSAR Eninc.1cu O bypassing, inoperability or deliberate inducing of inoperability f of an ESF system. The DPS also provides status information at the component level. The operator has the ability to activate each ESF system level bypass indicator manually in the control D room. Inoperable indication is shown on the DPS CRTs, Integrated Process Status Overview (IPSO) panel and Discrete Indication and Alarm System (DIAS) alarm tiles as further described in Sections 7.7.1.4 and 7.7.1.5. 7.1.2.22 Conformance to Reculatory Guide 1,62
.(Rev. O. 10/73)
Manual initiation of the RPS is described in Sections 7.2.1.1.1.11 and 7.2.2.3.2. Manual initiation of the ESFAS is 0 described in Section 7.3.2.3.2. Conformance to Regulatory Guide 1.62, " Manual Initiation of Protective Actions," is as follows: A. Each of the above systems can be manually actuated. B. Manual initiation of a protective action causes the same actions to be performed by the protection system as would be performed if the protection system had been initiated by automatic action. C. Manual switches are located in the control room, ESF CCS and at the RTSS for use by the operators. Some ESF functions D also have manual actuation at the Remote Shutdown Panel. D. The amount of equipment common to the manual and automatic initiation paths is kept to a minimum, usually just the actuation devices. No single credible failure in the manual, automatic, or common portions of the protective system will prevent initiation of a protective action by manual or automatic means. E. Manual initiation requires a minimum of equipment consistent with the needs of A, B, C, and D above. F. Once initiated, manual protective action will go to completion. Conformance to Reculatory Guide 1.63 0
'7.1.2.23 (Rev. 3, 2/87)
Electrical penetrations and their conformance to Regulatory Guide 1.63, " Electric Penetration Assemblies in Containment Structures for Water-Cooled Nuclear Power Plants," are discussed in Section 3.8.2 and the site-specific SAR. O! i Amendment D ) 7.1-16 September 30, 1988 l l j
CESSAR an&"icaris. O 7.1.2.24 Conformance to Regulatory Guide 1.68 (Rev. 2, 8/78) D l Conformance with Regulatory Guide 1.68, "Preoperational and Initial Start-Up Test Program for Water-Cooled Power Reactors," is discussed in Chapter 14. I 7.1.2.25 Conformance to Regulatory Guide 1.73 (Rev. O, 1/74) The Nuclear Power Module licensing scopo electric valve operators l intended to be installed inside the containment are qualified in compliance with Regulatory Guide 1.73, " Qualification Tests of Electric Valve Operators Installed Inside the Containment of Nuclear Power Plants," (see Section 3.11) . The Class 1 electric valve operators inside the containment are qualified according to ) the requirements of Section II of Appendix B to 10 CFR 50. The J qualification tests of the electric valve operators follow the ) applicable requirements of IEEE 382-1980, 344-1987 and 323-1983. l The qualification tests demonstrate the design adequacy of the j operators for service inside containment. These tests simulate ' those conditions that would be imposed during and after a Design
/~} Basis Event (e.g., LOCA) and those occurring during normal V operating conditions. The qualification adequacy of design for service under DBE conditions subject to tests verify the l the following:
l A. To the extent practicable subcomponents (e.g., limit j switches) are not integrated with the valve operator j mechanism but are, instead, part of the installed operator assembly. B. The test sequence described in IEEE 382-1980 or the actual service sequence is used during operator qualification tests whichever has the most severe operating conditions. l C. The valve operator is tested under the severest environmental conditions (T, P, RH, Radiation) that simulate j i the conditions to which the valve operator is expected to be l l exposed during and following a DBA. 1 D. The radiological source term for qualification tests is based on the same source term used in Regulatory Guide 1.7 ; taking into consideration the containment size, beta and gamma radiation. 7.1.2.26 Conformance to Regulatory Guide 1.97 (Rev. 3, S/83) The design of the post-accident monitoring instrumentation and information display via the DPS and DIAS is described in Amendment D 7.1-17 September 30, 1988 !
CESSAR 880icari:n G! Sections 3.1 and 7.5. The design conforms to Regulatory Guide l 1.97, " Instrumentation for Light-Water-Cooled Nuclear Power Plants To Assess Plant and Environs Conditions During and Following an Accident." 7.1.2.27 Conformance to Regulatory Guide 1.105 ' (Rev. 2, 2/86) The generation of safety system setpoints conforms to ISA-S67.04-1987, "Setpoints for Nuclear Safety Related Instrumentation Used in Nuclear Power Plants." i The setpoint methodology is similar to that explained in CEN-278(V), " Selection of Trip Setpoint Values for the Plant l' Protection System," submitted on the Palo Verde Nuclear Generating Station Unit 1 Docket, STN-50-528. The environment considered when determining errors is the most detrimental realistic environment calculated or postulated to exist up to the longest time of the required Reactor Trip or Engineered Safety Feature Actuation. This environment may be different for different events analyzed. For the setpoint calculation, the accident environment error calculation for process equipment uses the environmental conditions up to the longest required time of trip or actuation that results in the largest errors, thus providing additional conservatism to the resulting setpoints. The reference leg heating component uncertainties for steam generator level also take into account pressure and temperature ; variation within the steam generator. ll For all temperature and pressure setpoints, the trip will be D f initiated at a point that is not at saturation for the equipment. { For level setpoints, no analysis setpoint is within 5% of the l ends of the level span. i 7.1.2.28 Conformance to Regulatory Guide 1.106 I (Rev. 1, 3/77) l Conformance to Regulatory Guide 1.106, " Thermal Overload E Protection for Electric Motors on Motor-Operated Valves," is accomplished as follows. Thermal overload protection devices are ; not used in safety-related motor-operated valve control circuits. i Thermal overload signals are used only for status annunciation. ) The ESF-CCS, as described in Section 7.3, has the design , capability to provide MOV thermal overload status which is available via the DIAS and DPS described in Section 7.7.1.4 and i 7.7.1.7. I ! Amendment E l 7.1-18 December 30, 1988 l
CESSAR EHL"ic m. O V 7.1.2.29 Conformance to Reculatory Guide 1.120 (Rev. 1, 11/77), as lucraented by BTP CMEB 9.5-1 The following design features address the guidelines contained in Regulatory Guide 1.120, " Fire Protection Guidelines For Nuclear Power Plants": A. Redundant channels and divisions of safety-related instrumentation and control cabinets are designed to be located in separate geographic plant fire zones. B. The Control Complex is designed to allow a safe plant shutdown with a major fire in the main control room. The design utilizes fiber-optics and other signal isolation technologies in conjunction with ' the ability to manually transfer control-to the Remote Shutdown Panel (s). C. The minimization of combustible materials is considered in I the design and fabrication of the instrumentation and controls. D. The control room design includes provisions to locate fire protection system auc'.4.ble and visual alarm panels within the control room or, alternately, to integrate the alarms into the DIAS and DPS.
.D E. Control room and computer room equipment, panels and consoles that are safety related, contain fire detection devices with local and remote alarm annunciators.
The above features and design considerations form only a part of the defense in depth fire protection philosophy. See section 9.5 and the site-specific SAR for a more comprehensive discussion of the plant's fire protection program. 7.1.2.30 Conformance to Reculatory Guide 1.133 (Rev. 1. 5/Esi) The design of the Loose Parts Monitoring System conforms . - to Regulatory Guide 1.133, " Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors," and is described in detail in Section 7.7.1.6.3. 7.1.2.31 Conformance to Reculatory Guide 1.151 (Rev. O. 7/83) All protection and control sensing methods meet the independence requirements of Regulatory Guide 1.151, " Instrument Sensing g Lines" as described in Sections 3.1.20, 7.1.3(E) and 7.7.1.1.13. Amendment D 7.1-19 September 30, 1988
CESSAR 8!!nnCAT10N O l 7.1.2.32 Conformance to Reculatory Guide 1.151 l (Rev. O, 11/85) l Regulatory Guide 1.152, " Criteria for Programmable Digital Computer System Software in Safety-Related Systems of Nuclear Power Plants," states that the requirements set forth in ANSI /IEEE-ANS-7-4.3.2-1982 provide a method acceptable to the NRC staff for designing software, verifying software, implementing software, and validating computer systems in safety-related systems of nuclear power plants. A. The Core Protection Calculator System (CPCS) described in Section 7.2.1.1.2.5 is a digital computer system that generates reactor trip signals for low DNBR and high Local Power Density. The CPCS software is developed and tested in accordance with Regulatory Guide 1.152 as described by CEN-39(A)-P, "CPC Protection Algorithm Software Change Procedure," (Reference 4). I B. The Plant Protection System (PPS) described in Section l 7.2 is a multiple microprocessor based system that generates RPS and ESF initiation signals. The PPS software is developed and tested in accordance with Regulatory Guide 1.152. C. The ESF Component Control System (CCS) described in Section 7.3 is a multiple microprocessor based system that controls and actuates ESF fluid system components. The ESF-CCS software is developed and tested in accordance with Regulatory Guide 1.152. D. The Discrete Indication and Alarm System (DIAS) described in D Section 7.7.1.4 is a microprocessor based system that includes PAMI. The DIAS software is developed and tested in accordance with Regulatory Guide 1.152. 7.1.2.33 Conformance to Regulatory Guide 1.156 (Rev. O, 11/87) Conformance to Regulatory Guide 1.156, " Environmental Qualification of Connection Assemblies for Nuclear Power Plants", is as described in Sections 7.1.2.5, 7.1.2.8 and 7.1.2.18. 7.1.2.34 Conformance to Reaulatory Guide 8.12 (Rev. 1, 1/81) Conformance to Regulatory Guide 8.12, " Criticality Accident Alarm Systems," for the reactor is accommodated via the Boron Dilution Alarm Logic described in Section 7.7.1.1.10. In addition, the l l Amendment D 7.1-20 September 30, 1988
CESSAR Mai"icario. O Ex-Core Neutron Flux Monitoring System Start-up Channels provide an audible count rate via speakers located in the main control room and containment building. i Both the DIAS and DPS are designed to present this alarm p 4 information, as well as any other plant specific criticality accident alarms, to the control room operator. 7.1.3 INTERFACE REQUIREMENTS General instrumentation and control interface requirements are discussed below. Specific interface requirements are discussed in the principal section for the safety-related systems. Table 7.1-1 identifies the applicable section where standardized functional descriptions for the interfacing auxiliary and supporting systems are provided. A. Power The Class 1E electrical power system shall be divided into two independent divisions (Trains A and B) corresponding to the ESF actuated equipment trains. The preferred source to p each division is a separate start-up transformer connected to the site operator's transmission grid via two independent transmission lines. Separate independent emergency diesel generators shall be provided as back-up to each division. The Class 1E instrument power system shall be divided into four redundant instrumentation power busses A, B, C and D. Each instrumentation bus shall be fed from a separate battery to provide stable and noise free power to its respective channel (A, B, C or D) of Class 1E instrumentation and controls. The power distribution system shall be configured such that Class 1E instrumentation power busses A and C are derived ; from the Train A division and its emergency diesel generator. The remaining Class 1E instrumentation power busses B and D shall be derived from the Train B division i and its emergency diesel generator. The non-Class 1E instrumentation power system shall be divided into two separate instrumentation power buses X and Y. Each instrumentation bus shall be fed from a separate l battery to provide stable and noise free power to its
- respective non-Class 1E instrumentation and control channels ]~
! (X or Y). The power distribution system shall be configured such that the non-Class 1E instrumentation power buses X and tO Y con be energized from a non-safety-related Alternate AC U Source. E Amendment E 7.1-21 December 30, 1988
CESSARE!Lb - i i O Refer to Chapter 8 for Standardized Functional Descriptions of the AC and DC electric power systems. B. Protection From Natural Phenomena D Class 1E equipment shall be located within the plant so as to ensure the various natural phenomena specified in GDC 2 which are applicable to the specific site will not result in degradation of that equipment below the level required to i allow it to perform required protective action assuming a single failure. Refer to Section 3.1.2 for additional discussion on compliance with GDC 2. C. Protection From PiDe Failure The location of safety-related instrumentation and control components shall take into account their potential damage , due to piping failures, such as pipe whip or jet impingement ! from high or medium energy fluid systems. The location of these components and the routing of 1E and associated cables and sensing lines should avoid such hazards or shall be provided with adequate protection such that required protective action can be performed assuming a ; single piping failure, its associated effects, and a single ; failure. l D. Missiles The safety-related equipment shall be protected from potential missile sources. The 1E and associated cabling and sensing lines shall be handled in a similar fashion. E. Separation ! I The routing of lE and associated cabling and sensing lines o ! from sensors shall meet the requirements of Regulatory l Guides 1.75 and 1.151. They shall be arranged to minimize the possibility of common mode failure. This requires that the cabling for the four safety channels be routed separately; however, the cables of different safety ; functions within one channel may be routed together. Low ! energy signal cables shall be routed separately from all l power cables. Safety-related sensors shall be separated. l The separation of their safety-related cables requires that ! the cables be routed in separate cable trays. Associated D circuit cabling from redundant channels shall be handled the j same as 1E cabling. I Amendment D 7.1-22 September 30, 1988
CESSAR En'Jncari:n O Non-Class 1E instrumentation circuits and cables (low level) which may be in proximity to Class 1E or associated circuits and cables, are to be treated as associated circuits unless analyses or tests demonstrate that credible failures therein 0 J cannot adversely affect Class 1E circuits. Non-Class 1E 1 channels X and Y instrumentation and control circuits and a cabling should be separated from each other.
]
F. Independence i Cabling associated with redundant channels of safety-related circuits shall be installed such that a single credible ! event cannot cause multiple channel malfunctions or I interactions between channels. G. Thermal Limitations j The safety-related equipment shall be located so as not to violate the temperature and humidity limits of Section 3.11. ! H. Monitorina I Auxiliary and supporting systems for the safety-related s) instrumentation and controls shall be designed to cause a i s./ systems level bypass indication when they are bypassed or I deliberately made inoperable. The bypass indication would be provided for the safety-related system which would be l affected by the bypassing or deliberate inoperability of the auxiliary or supporting system. The RPS and ESFAS alarms and the remote PPS and DNBR/LPD Calculator Operator's Modules are located in the main control room. D Most of the Balance of Plant (BOP) auxiliary and supporting system instrumentation, alarms and displays required to be monitored on the Main Control and Remote Shutdown Panels shall be interfaced through the DIAS, DPS, ESF-CCS and/or Process-CCS to satisfy Nuplex 80+ Human Factors Engineering l (HFE) design criteria identified in Chapter 18. Other l n.onitoring equipment and. modules supplied by the site j operator for installation in the main control panels shall i be designed to be- compatible with the HFE design assumptions, criteria and task analyses identified in Chapter 18. Refer to Sections 7.3, 7.7.1.1.12, 7.7.1.4 and 7.7.1.7 for functional descriptions of the ESF-CCS, Process-CCS, DIAS l f
\
and DPS. Amendment D 7.1-23 September 30, 1988
CESSAR anEncun h l I. Operational Controls ' The RPS and ESFAS manual actuation devices are located in l D the control room. The instrumentation and control components of the safe shutdown systems on the Remote Shutdown Panel or at local locations shall be manually q operable. Most BOP auxiliary and supporting system controls required to be operated from the Main Control and/or Remote Shutdown P5nels shall be interfaced through the ESF-CCS and r7,rcess-CCS to satisfy Chapter 18 HFE design criteria. All D other control modules supplied by the site operator for installation in these panels shall be designed to be compatible with the HFE design assumptions, criteria and task analyses identified in Chapter 18. J. Inspection and Testiny The PPS, including sensors, shall be capable of being periodically tested in accordance with the Technical Specifications of Chapter 16. Those portions which could adversely affect reactor operations shall be capable of being tested when the reactor is shut down. All other safety-related instrumentation shall be capable of being tested during normal operation. K. Chemistry /Samnlina The components of the safeP/ v alated equipment shall be located so as not to exceed the chemistry limits specified in Section 3.11. L. Materials Not applicable to the safety-related instrumentation and controls equipment. : M. System Component Arrangement Safety-related components shall be located so as to conform to the separation, independence, and other criteria specified in this chapter. The safety-related components shall be located to provide access for maintenance, testing and operation as required. D The redundant channels and divisions of safety-related ) instrumentation and control cabinets shall be located in ! separate plant control complex locations. These locations
]
Amendment D 7.1-24 September 30, 1988
)
CESSAR E!ninCATION O shall conform to Regulatory Guides 1.17 and 1.120 for safety system security and fire protection as described in Sections 7.1.2.16 and 7.1.2.29. The control complex design and arrangements shall maintain independence between the Main Control Room and Remote Shutdown Panel such that transfer of control can be achieved as described in Sections 7.4.1.1.10 and 7.7.1.3. D Analog and digital signals provided to the components shall not share the same multi-conductor cable, unless specifically called for or approved by Combustion Engineering. N. Radiological Waste Radiological waste discharge lines or components shall not be routed or located next to the Nuplex 80+ Main Control D Room, Remote Shutdown Panel or protection system electronic components in a manner that will result in exceeding the radiation limits specified in Section 3.11. O. Overpressure Protect ion The components of the safety-related equipment shall be located so as not to exceed the pressure limits specified in Section 3.11. P. Related Services A fire protection program shall be provided to protect the D Nuplex 80+ Advanced Control Complex and other safety-related equipment, including sensors, consistent with GDC 3. This program shall include facilities for detection, alarming, and extinguishing of fires. Facilities and methods for minimising the probability and effects of fires, including fire barriers, fire resistant and non-combustible materials, and other such items, shall be employed whenever possible. Adequate drainage shall be provided if water is used to extinguish fires. Inadvertent operation or rupture of fire protection systems shall not result in the reduction of the functional capability of safety-related systems or components below that required to perform their safety funccion. Physical identification shall be provided to enable plant personnel to recognize that PPS, ESF-CCS Cabinets, RTSS, and their cabling are safety-related. The cabinets shall be D Amendment D 7.1-25 September 30, 1988
1 CESSAR EnWicari s identified by nameplates. A color coding scheme shall be e used to identify the physically separated channel from sensor to the PPS (refer to Section 7.1.3(E)).cabling The lD same color code shall be used for interbay or intercabinet identification. Cabling or wiring within a bay at the cabinet which is in the channel of its circuit classification shall not be color coded. The cabinet nameplates and cabling shall be color 1 coded as follows: ] D Protective ESF Train Channel Divisioni Associated Channel Channel A: Red A: Red Channel J: White / Red Stripe j Channel B: Green B: Green Channel K: White / Green Stripe Channel C: Yellow Channel L: White / Yellow Stripe Channel D: Blue Channel M: White / Blue Stripe All non-panel mounted protection system instrumentation and j control components shall be identified with a name tag which D provides the channel number and the suffix A, B, C, or D to specifically identify the protection channel with which the component is identified. Q. Environmental Environmental support systems shall be provided to ensure that the environmental conditions of the safety-related systems do not exceed the requirements for 1E equipment as defined in Section 3.11. The control room shall be designed to provide adequate radiation protection for personnel access and occupancy receiving 0 under accident conditions without radiation exposure in excess of 5 rem whole body, or its equivalent to 1 any part of the body, for the duration of the accident. R. Mechanical Interaction Seismic requirements for safety-related equipment are specified in Section 3.10. l S. Data Processina System Inputs The inputs from the RPS, ESFAS and BOP auxiliary support systems can be sent to the DPS for display, trending, data l Amendment D 7.1-26 September 30, 1988 1 i
CESSAREannema O logging and other historical functions but are not used for other control functions. These inputs shall have proper isolation to prevent any failure in the DPS from adversely affecting the RPS, ESFAS or BOP safety related auxiliary D support systems. Refer to Section 7.7.1.7 for a description of the Data Processing System. l l l l I I (U) Amendment D 7.1-27 September 30, 1988
l CESSAR EnMem:n O REFERENCES FOR SECTION 7.1
- 1. " Description of the C-E Nuclear Steam Supply System Quality Assurance Program," Combustion Engineering, Inc.,
CENPD-210-A, Revision 04, January 1987. D
- 2. " Qualification of Combustion Engineering Class 1E Instrumentation," Combustion Engineering, Inc.,
CENPD-255-A-1983, Revision 03, October 1985. lD
- 3. " Seismic Qualification of Instrumentation Equipment,"
Combustion Engineering, Inc., CENPD-182, May 1977.
- 4. "CPC Protection Algorithm Software Change Procedure,"
Combustion Engineering, Inc., CEN-39(A)-P, Revision 03, D November 1986. i 4 f 1 1 O Amendment D 7.1-28 September 30, 1988
W! hhk ET llCATl!N TABLE 7.1-1 AUXILIARY AND SUPPORTING SYSTEM DESCRIPTIONS E Applicable CESSAR-DC Description Chapter or Section D Control Room 18.4 Emergency Operations Facility 18.4 Technical Support Center 18,4 Electric Power Distribution System 8 Fire Protection System 9 Diesel Generator System 8 and 9.5
-s Station Service Water System 9.2 Component Cooling Water System 9.2 Instrument Air System 9 Automatic Dispatch System 10.2 Environmental Support Systems (HVAC) 9.4 1
l l Amendment E December 30, 1988
~
i CESSARiMMN - O 7.2 REACTOR PROTECTIVE SYSTEM 7.
2.1 DESCRIPTION
7.2.1.1 System Description j The Reactor Protective System (RPS) portion of the Plant Protection System (PPS)- (as shown on Figure 7.2-1) consists of sensors, calculators, logic, and other equipment necessary to E monitor selected Nuclear Power Module (NPM) conditions and to effect reliable and rapid reactor shutdown (reactor trip) if monitored conditions approach specified safety system settings. The system's functions are to protect the core fuel design limits l and Reactor Coolant System (RCS) pressure boundary for l Anticipated Operational Occurrences, and also to provide l assistance in mitigating the consequences of accidents. Four measurement channels with electrical and physical separation: are provided for each parameter used in the direct generation of trip signals, with the exception of Control Element Assembly (CEA) position which is a two channel measurement. l The Reactor Protection System (RPS) portion of the PPS includes the following functions: bistable trip, local-coincidence logic, E ( reactor trip initiation logic and automatic testing of PPS logic. The bistable trip processors generate trips. based on the measurement channel digitized value exceeding a digital setpoint. The bistable trip processors provide their trip signals to the coincidence processors located in the four redundant PPS channels. The coincidence processors evaluate the local coincidence logic based on the state of the four like trip signals and their respective bypasses. The coincidence signals are used in the generation of the RTSS or ESF-CCS initiation. Software is developed and tested for the above processors, as , stated in Section 7.1. A coincidence of two like trip signals is required to generate a reactor trip signal. The fourth channel I is provided as a spare and allows bypassing of one channel while l maintaining a two-out-of-three system. l The reactor trip signal deenergizes the control Element Drive-Mechanism (CEDM) coils, allowing all CEAs to drop into the core. PPS interfaces (RPS and ESFAS) for functions, such as operator interaction, alarm annunciation and testing (manual and automatic), are shown on Figure 7.2-2. The local and main control room PPS operator's module (one per E channel) provides for entering trip channel bypasses, operating bypasses, and variable setpoint resets. These modules also provide indication of status of bypasses, operating bypasses, Amendment E 7.2-1 December 30, 1988
CESSARE!!Oc-O bistable trip and pre-trip. The local operator module provides the man-machine interface during manual testing of bistable trip i functions not tested automatically. ! The main control room (MCR) panels provide means to manually initiate engineered safeguards. t The Remote Shutdown Panel provides selected functions needed for , safe shutdown and cooldown, as described in Section 7.4. Each PPS channel cabinet contains a manual transfer switch that enables the RSP or MCR for PPS channel functions that are common to both. E The Interface and Testing Processor (ITP) , one per channel, communicates with the bistable trip processors, coincidence processors, operator's modules, Engineered Safety Features-Component Control System (ESF-CCS), Reactor Trip Switchgear System (RTSS) and ITP's in the other three channels to monitor, test and control the operational state of the PPS. It also provides selected PPS channel status and test results information to the Data Processing System (DPS), and Discrete Indication and Alarm System (DIAS). 7.2.1.1.1 Trips 7.2.1.1.1.1 Variable Overpower The variable overpower trip is provided to trip the reactor when indicated neutron flux power either increases at a great enough rate, or reaches a preset value. The flux signal used is the average of the three linear subchannel flux signals originating in each nuclear instrument safety channel. The nominal trip l setpoints are provided in Table 7.2-4. ! Pre-trip alarms are initiated below the trip value to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.2 High Logarithmic Power Level The high logarithmic power level trip is provided to trip the , reactor when indicated neutron flux power reaches a preset value. The flux signal used is the logarithmic power signal originating in each nuclear instrument safety channel. The nominal setpoint l is provided in Table 7.2-4. The trip may be manually bypassed by the operator. This bypass point is provided in Table 7.2-1. 1 1 0' 1 Amendment E 7.2-2 December 30, 1988 l _________-__-______A
CESSAR n.Mir"icarien 1 Pre-trip alarms are initiated below the trip value to provide audible and visible indication of approach to a trip condition. 8 The trip bypass also bypasses the pre-trip alarms. } 7.2.1.1.1.3 High Local Power Density The high local power density trip is provided to trip the reactor when calculated core peak local power density reaches a preset value. The preset value is less than that value which would E cause fuel centerline melting. The calculation of the peak local power density is performed by the Core Protection Calculators (CPCs), which compensate the calculated peak local power density to account for the thermal capacity of the fuel. A trip results if the compensated peak local power density reaches the preset value. The calculated trip assures a core peak local power density below the safety limit for peak linear heat rate (kW/ft). The nominal trip setpoint is given in Table 7.2-4. The effects of core burnup are considered in the determination of the local power density trip. Pre-trip alarms are initiated below the trip value to provide audible and visible indication of approach to a trip condition. I O 7.2.1.1.1.4 Low Departure from Nucleate Boiling Ratio
.O The low Departure from Nucleate Boiling Ratio (DNBR) trip is provided to trip the reactor when the calculated DNBR approaches l a preset value. The calculation of DNBR is performed by the CPCs based on core average power, reactor coolant pressure, reactor inlet temperature, reactor coolant flow, and the core '
power distribution. The CPC system calculations include E allowances for sensor and processing time delays and inaccuracies i such that a trip is generated within the CPCs before violation l of the DNBR safety limit in the limiting coolant channel in the core occurs during Anticipated Operational occurrences. The " nominal trip setpoint is given in Table 7.2-4. i The low DNBR trip incorporates a low pressurizer pressure floor, with the value given in Table 7.2-4. At this pressure, a low DNBR trip will automatically occur. { Pre-trip alarms are initiated above the trip value to provide j l audible and visible indication of approach to a trip condition. 7.2.1.1.1.5 High Pressurizer Pressure The high pressurizer pressure trip is provided to trip the I reactor when measured pressurizer pressure reaches a high preset p value. The nominal trip setpoint is provided in Table 7.2-4.
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i Amendment E-7.2-3 December 30, 1988 i
CESSAR EnDicaritu O Pre-trip alarms are initiated below the trip setpoint to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.6 Low Pressurizer Pressure The low pressurizer pressure trip is provided to trip the reactor when the measured pressurizer pressure falls to a low preset value. The nominal trip setpoint for normal operation is provided in Table 7.2-4. At pressures below the normal operating range, this setpoint can be manually decreased to a fixed increment below the existing pressurizer pressure down to a minimum value. The incremental and minimum values are given in Table 7.2-4. This ensurc_ ~apability of a trip when required during plant cooldown. The trip may be manually bypassed by the operator. This bypass point is provided in Table 7.2-1. The bypass is automatically i removed as pressure is increased above a fixed value and the low pressure setpoint automatically increases, maintaining the fixed increment between the plant pressure and the setpoint. These values are shown in Table 7.2-4. Pre-trip alarms are initiated above the trip setpoint to provide 3 audible and visible indication of approach to a trip condition. 7.2.1.1.1.7 Low Steam Generator Water Level A variable low steam generator water level trip is provided to , trip the reactor when measured steam generator water level falls E to a low calculated value. The low level setpoint is programmed such that as reactor power decreases, the level setpoint is decreased from the normal full power value down to a minimum , preset low power value. Separate trips are provided from each steam generator. The nominal trip setpoint is provided in Table 7.2-4. Pre-trip alarms are initiated above the trip setpoint to provide j audible and visible indication of approach to a trip condition. l 7.2.1.1.1.8 Low Steam Generator Pressure j The low steam generator pressure trip is provided to trip the 2 reactor when the measured steam generator pressure falls to a low j preset value. Separate trips are provided from each steam j generator. The nominal trip setpoint during normal operation is j provided in Table 7.2-4. At steam generator pressures below j normal, the operator has the ability to manually decrease the j setpoint to a fixed increment below existing system pressure. O Amendment E 7.2-4 December 30, 1988 i
CESSAREna mm i w This is used during plant cooldown. During startup, this setpoint is automatically increased and remains at the fixed increment ' below generator pressure. This fixed increment is provided in Table 7.2-4. I Pre-trip alarms are initiated to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.9 High Containment Pressure The high containment pressure trip is provided to trip the reactor when measured containment pressure reaches a high preset value. The nominal trip setpoint is provided in Table 7.2-4. The trip is provided as additional design conservatism (i.e., additional means of providing a reactor trip). The high containment pressure trip setpoint is selected in conjunction with the high-high containment pressure setpoint to prevent exceeding the containment design pressure during a design basis LOCA or main steam line break accident. Pre-trip alarms are initiated to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.10 High Steam Generator Water Level
%d A high steam generator water level trip is provided to trip the reactor when measured steam generator water leve.1 rises to a high preset value. Separate trips are provided from each steam generator. The nominal trip setpoint is provided in Table 7.2-4. ;
l Pre-trip alarms are initiated to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.11 Manual Trip A manual reactor trip is provided to permit the operator to trip the reactor. Actuation of two adjacent switches in the main control room will cause interruption of the AC power to the CEDMs. Two independent sets of trip pushbuttons are provided, either one of which will cause a reactor trip. There are also manual reactor trip switches at the reactor trip switchgear. The remote manual initiation portion of the Reactor Trip System is designed as an input to the RTSS. This design is consistent with the recommendations of NRC Regulatory Guide 1.62. The amount of equipment common to both automatic and manual initiation is kept to a minimum. Once initiated, the manual trip will go to completion as required in Section 4.16 of IEEE i p Standard 279-1971. 1 V j 7.2-5
I l l l (;IEEiSi/ Lit ilMinCATl!N I h 1 7.2.1.1.1.12 Low Reactor Coolant Flow l The low reactor coolant flow trip is provided to trip the reactor when the pressure alfferential across the primary side of either steam generator decreases below a rate limited variable setpoint, as shown in Figure 7.2-3. A separate trip is provided for each steam generator. This function is used to provide a reactor trip for a reactor coolant pump sheared shaft event. Pre-trip alarms are provided. ! 7.2.1.1.2 Initiating Circuits 7.2.1.1.2.1 Process Measurements Various pressures, levels, and temperatures associated with the NPM are continuously monitored to provide signals to the RPS trip bistable processors. These process protective parameters are E measured with four independent process instrument channels. A detailed listing of the parameters measured is contained in Table 7.2-3. A typical protective channel, as shown in Figure 7.2-4, consists of a sensor / transmitter, loop power supply, current loop E resistors, and fiber-optic transmitter outputs to the process control systems. Main control room and RSP displays are provided from Data Processing System (DPS), and Discrete Indication and Alarm System (DIAS) via the PPS. The piping, wiring, and components of each channel are physically separated from that of other like protective channels to provide independence. The output of each transmitter is an ungrounded current loop. Exceptions are: l A. Nuclear instruments. B. Reactor coolant pump speed sensors which provide a pulsed voltage signal. Signal isolation is provided for DIAS, DPS, and process control system inputs via fiber-optic cables. Each redundant channel is powered from a separate vital AC bus. E 7.2.1.1.2.2 CEA Position Measurements CEA positions are monitored by two diverse means. This monitoring is used for display of CEA position to the operator O Amendment E 7.2-6 December 30, 1988 I
CESSAR En#icuiu O ! l and to initiate alarms and control actions to prevent CEA ! misalignments. CEA misalignments are factored into the CPC calculation of DNBR and LPD to appropriately reduce the margins to trip. 7.2.1.1.2.2.1 CEA Position Monitoring by the RPS I The position of each CEA is an input to the RPS. These positibns are measured by means of two reed switch assemblies on each CEA. Each reed switch assembly consists of a series of magnetically actuated reed switches spaced at intervals along the CEA housing and wired with precision resistors in a voltage divider network l (see Figure 7.2-5). A magnet attached to the CEA extension shaft I actuates the adjacent reed switches, causing voltages proportional to position to be transmitted for each assembly. The two assemblies and wiring are physically and electrically separated from each other (see Figure 7.2-6). The CEAs are arranged into control groups that are controlled as E subgroups of CEAs. The subgroups are symmetric about the core center. The subgroups am required to move together as a control group and should always indicate the same CEA group position. l O Each CPC channel monitors the position of one " target" CEA in each subgroup via the reed switch position signal. The " target" CEA represents a measure of subgroup CEA position. To make each CPC channel aware of position deviations of CEAs within a subgroup, all CEA positions are monitored by the CEA Calculators. One set of the redundant reed switch signals for all CEAs is monitored by one CEA Calculator, and the other set of signals by the redundant CEA Calculator. Each CEA Calculator monitors the .) position of all CEAs within each control subgroup. Should a CEA l deviate from its subgroup position, the CEA Calculators 'ill ( monitor the event, activate alarms via DPS and DIAS, and trar ait appropriate " penalty" factors to the CPCs. Within the CPCs the l penalty factors result in the initiation of control actions to l mitigate the event and, if still needed, a reduction in i margins-to-trip for low DNBR and'high local power density. This ! assures conservative operation of the RPS. The control and protection actions for single CEA deviation events are described in more detail below. The CEA Calculators provide the position of each regulating, I shutdown and part-strength CEA via the CPC operator's module, and DPS displays in the main control room. Optical isolation is utilized at each CEA Calculator for these outputs. The detailed signal paths of CEA position information within the RPS are chown in Figure 7.2-7. V . I Amendment E l 7.2-7 December 30, 1988
CESSAREEN-0l 7.2.1.1.2.2.2 Control and Protective Actions for CEA Misalignments To avert unwarranted reactor trips due to single CEA deviation ) events, the control and protection systems have design features j to minimize the probability of these avents occurring. In I addition, the RPS will initiate protective actions for those events that cannot be precluded and which have not been successfully terminated by the control systems. A. CEDMCS The Control Element Drive Mechanism Control System (CEDMCS) monitors the mechanical actions of the Control Element Drive Mechanism for each CEA to provide continuous closed loop control of the drive mechanism. If, during control group E motion, a mechanism fails to move its CEA, the CEDMCS will block further movement of the remainder of the control group to prevent CEA deviations from occurring. In addition, the CEDMCS continuously determines CEA position based on counting the number of inward and outward mechanical actions of the CEDM. If a position deviation is detected among CEAs in a control group, a CEA Motion Inhibit , (CMI) is generated. The CEDMCS also monitors the dropped rod contact (DRC) of the reed switch position transmitter (RSPT). If a rod drop occurs for a 12-finger CEA, the CEDMCS will initiate a reactor power cutback. The reduced power is sufficient to ; avert a condition requiring protective action. This is further explained below. The CEDMCS CEA Withdrawal Prohibit (CWP) two-out-of-four logic utilizes three signals from each CPC to generate a CEA withdrawal prohibit signal. The CPC signals are Hi Pressurizer Pressure CWP, DNBR CWP and LPD CWP generated at pre-trip conditions of Hi Pressurizer Pressure, DNBR and LPD respectively. B. Reactor Protection System l Due to the differences in required control and protective actions for insertion and withdrawal deviations, each event is explained separately below. I
- 1. Insertion Deviations The CPCs use the most conservative insertion deviation penalty factors from the two CEACs to initially !
l generate a CEA Motion Inhibit. This CMI initiation is Amendment E 7.2-8 December 30, 1988 1 l l t
C E S S A R En Wicaritu A effectively a one-out-of-two logic function performed in each CPC channel. All four CPC channels generate a CMI signal-which is interfaced to the CEDMCS to block rod motion and thereby prevent further CEA deviations. The CEDMCS executes the rod block on coincidence of ; two-out-of-four CMI signals from the CPCs. ] i While the CMI logic is being executed, the CPCs also I apply the most conservative insertion penalty factor to { the DNBR and LPD calculations. If the calculations result in a pre-trip condition, each CPC will generate i a Reactor Power Cutback (RPC) signal. The RPC demand signals are sent to the CEDMCS which actuates gravity insertion of CEAs (i.e., Reactor Power Cutback) using a j two-out-of-four actuation logic. j l The reduction in reactor power will be sufficient to i I prevent a DNBR or LPD trip. However, regardless of { this control action, the CPCs continue to use the most E j conservative insertion penalty factor in the DNBR and LPD trip algorithms. If the Reactor Power Cutback is , l not successfully executed or does not result in l sufficient thermal margin, a DNBR_and/or LPD trip will j be generated. If a CEAC is out of service, the CPCs will use the ' available CEAC penalty factors to generate the CMI, RPC and reactor trip signals. To relax technical specification limitations during this mode of operation, the CEDMCS also initiates CMI and Reactor Power Cutback signals. This was described in Paragraph A above. l 2. Withdrawal Deviations l A CMI is generated by the integrated actions of the CEACs, CPCs and CEDMCS for withdrawal deviations in the same manner as for insertion deviations described in paragraph 1 above. The CEDMCS also prevents withdrawal deviations through its own CEA position monitoring, . group motion interlocks and self-generated CMI, as l 1 described in A above. These four levels of single CEA ; deviation prevention,- coupled with the inherent low probability of the event (i.e., these events are rare in C-E plants) and analysis that shows acceptable effects of the event (see Chapter 15), have resulted in the reclassification of single CEA withdrawals from Anticipated Operational Occurrences to Accidents.
/' Therefore, there is no need for the CPCs to initiate protective action for single CEA withdrawal deviation Amendment E 7.2-9 December 30, 1988
CESSAR 8Heicari:u O events. It is noted that this reclassification also encompasses a group insertion with a single stuck CEA. j 7.2.1.1.2.3 Ex-core Neutron Flux Measurements i The ex-core nuclear instrumentation includes neutron detectors located around the reactor core, and signal conditioning equipment located within the containment and the auxiliary building. Neutron flux is monitored from source levels throtigh full power operation, and signal outputs are provided for reactor and information display. There are 4 E protection, control channels of safety instrumentation (see Figure 7.2-8). The four safety channels provide neutron flux information from near startup neutron flux levels to 200% of;7r ted power covering E a single range of approximately 1 x 10 to 200% power (9 decades). Each safety channel consists of three fission chambers, a preamplifier and a signal conditioning drawer , containing power supplies, a logarithmic amplifier (including ' combination counting and mean square variation techniques), linear amplifiers, test circuitry, and a rate-of-change of power E circuit. These channels provide the RPS information for ' rate-of-change of power display, DNBR, local power density, and overpower protection. The detector assembly provided for each safety channel consists of three identical fission chambers stacked vertically along the length of the reactor core. The use of multiple subchannel detectors in this arrangement permits the determination of axial E , power shape during power operation. l The fission chambers are mounted in holder assemblies, which in turn are located in four dry instrument wells (thimbles) at or in the primary shield. The wells are spaced around the reactor ! vessel to provide optimum neutron flux information. Four safety channel preamplifier / filter assemblies for the fission chambers are mounted outaide the reactor containment building in the penetration area. Physical and electrical l separation of the preamplifiers and cabling between redundant E channels is provided. 7.2.1.1.2.4 Reactor Coolant Flow Measurements The speed of each reactor coolant pump motor is measured to provide a basis for calculation of reactor coolant flow through each pump. The measurement of reactor coolant pump speed is accurate to within 0.43% of the actual pump speed. Two metal discs, each with 44 uniformly spaced slots about its periphery are scanned by proximity devices. The metal discs are attached Amendment E 7.2-10 December 30, 1988 w __________
CESSARnNnc-O to the pump motor shaft, one to the upper portion and one to the ! lower portion (see Figure 7.2-9). Each scanning device produces a voltage pulse signal. CPCs to calculate flow rate is based upon every N The pulse train that is thnput pulse from-to the the scanning device. The frequency of this pulse . train is proportional to pump speed. Adequate separation between proximity devices is provided. The mass flow rate is obtained using the pump speed inputs from ; the four reactor coolant pumps,. the cold leg temperatures, and l the hot leg temperatures. The volumetric flow rate through each l reactor coolant pump is dependent upon the rotational speed of j the pump and the pump head. This relationship is typically shown l in pump characteristic curves. Flow changes resulting from changes in the loop flow resistances occur slowly (i.e., core crud buildup and increase in steam generator resistance). I Calibration of the calculated mass flow rate will be performed periodically using instrumentation which is not part of the Reactor Coolant Pump Speed Sensing System. Flow reductions associated with pump speed reductions are more l rapid than those produced from loop flow resistance changes. l Mass flow rate is calculated for each pump from the pump speed' E e the density of cold leg coolant and a correction term based on j l the hot leg temperature. ; The mass flow rates calculated for each pump are summed to give a core mass flow rate. This flow rate is then used in the.CPC DNBR and AT power algorithms. The RCP speed is also transmitted from each CPC channel over fiber-optic data links to the DPS where signal cross-channel E validation is performed prior to use for display and use in COLSS. The reactor coolant pump speed measurement system is designed, manufactured, tested, and installed to the identical design, quality assurance, and testing criteria as the remainder of the signal generation and processing equipment for signals utilized by the RPS. 7.2.1.1.2.5 Core Protection Calculators-Four independent CPCs are provided, one in each protection channel. Calculation of DNBR and local power density is performed in each CPC, utilizing the input signals described 1 below. The DNBR and local power density so calculated are compared with trip setpoints for initiation of a low DNBR trip (Section 7.2.1.1.1.4) and the high local power density trip (Section 7.2.1.1.1.3). Amendment E 7.2-11 December 30, 1988
i l I I CESSAR n%flCAT10N 1 i O Two independent CEA Calculators are provided as part of the DNBR/LPD Calculator System to calculate individual CEA deviations i from the position of the other CEAs in their subgroup. The CPCs E , and CEA calculations are described in detail in References 1 and !
- 2. I As shown in Figure 7.2-10, each CPC receives the following i inputs: !
A. Core inlet and outlet temperature. ] B. Pressurizer pressure, i C. Reactor coolant pump speed. D. Ex-core nuclear instrumentation flux power (each subchannel from the safety channel). E. Selected CEA position. F. Penalty factors for CEA deviations within a subgroup from the CEA Calculators. Input signals are conditioned and processed. The following calculations are performed in the CPC or the CEA Calculators: A. CEA deviations. B. Correction factor for excore flux power for shape annealing and CEA shadowing. C. Reactor coolant flowrate from reactor coolant pump speeds l and temperatures and DNBR penalty for pump speeds less than E a setpoint. D. AT power from reactor coolant temperatures, pressure, and flow information. J E. Ex-core flux power: Ex-core flux power signals are summed and corrected for CEA shadowing, shape annealing, and cold leg temperature shadowing. This corrected flux power is periodically calibrated to the actual core power measured independently 1 of the Reactor Protection System. This calibration does not ! modify the inherent fast time response of the ex-core l signals to power transients. Ol i Amendment E 7.2-12 December 30, 1988 j
CESSARnEncamn (O V F. Axial power distribution from the corrected ex-core . flux power signals. G. Fuel rod and coolant channel planar radial' peaking factors, selection of predetermined coefficients based on CEA positions. H. DNBR. . I. Comparison of DNBR with a fixed trip setpoint. 1 J. Local power density. K. Comparison of local power density with a fixed trip setpoint. L. CEA deviation alarm. M. Calculation of cold leg temperature difference for asymmetric steam generator transient trip determination. E Outputs of each CPC are: A. DNBR trip and pre-trip. B. DNBR margin (to DIAS and DPS for control board indication). C. Local power density trip and pre-trip. l l D. Local power density margin (to DIAS and DPS for control board indication). E. Calibrated neutron flux power (to DIAS and DPS for control E board indication). F. High pressurizer pressure pre-trip to CEDM Control System CWP logic. j J G. CEA inward deviation cutback demand to Reactor Power Cutback l System. I H. CEA deviation motion inhibit to CEDM Control System. I. RCP speeds and other CPC measurement channel parameters to Data Processing System. ; t Amendment E 7.2-13 December 30, 1988
CESSAR ES%u,w O J. RPC Demand Signal to RPCS logic. K. CMI Signal to CEDM Control System CMI logic. Each calculator is mounted in cabinets located in separate channelized equipment rooms with an operator's display and control module located in the main control room. From the four modules an operator can monitor all calculators, including specific inputs or calculated functions. 7.2.1.1.2.6 Bistable Trip Generation Except for the CPCs, signals from process measurement loops are sent to bistable comparators where the input signals are compared to either fixed or variable setpoints. Refer to Table 7.2-4 for identification of trip parameters vs. type setpoints. When the input parameter reaches the setpoint the bistable produces trip signals. In the case of the Core Protection Calculator outputs, the CPC provides trip status inputs to the bistable logic. See Figure 7.2-18. The trip outputs of the bistable logics are sent to the local coincidence logics. (Each bistable logic in each E channel provides a trip signal to each of the four protective channels - Figure 7.2-11). A pre-trip output is also provided as part of the bistable logic. . In addition to the trip and pre-trip functions, the bistables logic contain test logic. The test logic allows testing of the following bistable information: j
- 1. Analog input
- 2. Trip setpoint
- 3. Pre-trip setpoint
- 4. Status information (pre-trip, trip, operating bypass).
A. Bistable with Fixed Setpoint For those bistables whose setpoint is fixed, (i.e., digital), the setpoint can be changed at the PPS. Access to change the setpoint is controlled by administrative f procedures. All of the fixed setpoints are monitored by the automatic test network. B. Bistable with Variable Setpoint Variable setpoints are provided for some bistables to permit safe and orderly plant startup and shutdown. Three types of variable setpoints are utilized, they are: Amendment F 7.2-14 December 30, 1988
CESSARUninema o O
- 1. Variable setpoint with manual reset.
- 2. Variable setpoint with automatic rate limiting.
- 3. Variable setpoint with diverse trip parameter.
3.1 Variable setpoint with manual reset This type of variable setpoint is a function of the input , signal to the bistable. The design permits manually j initiated automatic decrementing of the setpoint. ! Decrementing of the setpoint may be initiated at the PPS ) operator's modules or remote shutdown panel. When decremented, the satpoint resets itself to a fixed value below the actual input signal which exists at that time. By continuing to reset each time the pre-trip setpoint is reached the plant can be shutdown without causing any unnecessary protective actions. If the input signal rises above the point at which it was last reset,- the variable setpoint logic will cause the setpoint to automatically rise to maintain a fixed value between the input signal and ' setpoint. If the input parameter falls, the setpoint will hold and the operator must again reset the setpoint to l i n U permit tracking. Figure operation of a variable setpoint. 7.2-15 illustrates Each variable setpoint contains a timer which allows a reset to be initiated only typical after some predetermined time interval has elapsed since the 3 last reset. The design also includes the capability of fixed upper and lower limits. E The design also provides a pre-trip variable setpoint which is always related to the trip setpoint by a fixed value. 1 I The actual value of the netpoint is available and may be displayed at the PPS cabinet or remotely via the DPS and operator's module in the control room. Separate reset pushbuttons are provided for each protection channel. B.2 Variable Setpoint with Automatic Rate Limiting This type of variable setpoint permits automatic incrementing and decrementing of the setpoint based upon the action of the bistable input variable. See Figure 7.2-3. The design attempts to maintain a fixed differential between the bistable input and the setpoint. The design includes the ability to adjust the rate at which the setpoint is allowed to change. If the input signal is changing at a l l l Amendment E 7.2-15 December 30, 1988
l CESSAR HIGcuia , 9 :l rate greater than the rate at which the setpoint can change, the differential between the two values eventually becomes 1 zero, creating a condition such that the bistable trips. When the bistable trip occurs, it prevents the setpoint from changing until the bistable trip clears. The design includes the capability of having fixed upper and lower limits. Two forms of the rate limited setpoint are utilized in the system. The first form provides a setpoint which is higher than the input signal, as such it provides protection for signals that should not increase at too rapid a rate. The second form provides a setpoint which is lower than the input signal, as such it provides protection for signals that should not decrease at too rapid a rate. Figure 7.2-3 illustrates typical operation of this type of variable setpoint. The design also provides a variable pre-trip setpoint which is always related to the trip setpoint by a fixed value. The actual value of the setpoint is available and may be displayed at the PPS cabinet or remotely in the control room via the DPS and PPS operator's module. B.3 Variable Setpoint with Diverse Trip Parameter This type of variable setpoint is a function of a parameter that is different than the bistable trip input. Th ' E variable setpoint is preprogrammed as a function of the ' different parameter. The design includes the capability of having fixed upper and lower limits. The design also provides a variable pre-trip setpoint which l is always related to the trip setpoint by a fixed value. ' The actual value of the setpoint is available and may be displayed at the PPS cabinet or remotely in the control room via the DPS and PPS operator's module. 7.2.1.1.3 Logic A. Local Coincidence Logic l There is one Local Coincidence Logic (LCL) associated with each trip bistable logic of each channel. Each local coincidence logic receives four trip signals, one from its O Amendment E 7.2-16 December 30, 1988
~ 1 i CESSAR EMnce o associated bistable logic in the channel and one from each of the equivalent bistable logic located in the other three channels (Figure 7.2-12). The-local coincidence logic also i receives the trip channel bypass status associated with each of the above mentioned bistables (Figure 7.2-13 illustrates distribution of a typical bypass). The function of the local coincidence logic is to generate a coincidence signal whenever two or more like bistables, are in a tripped condition. The LCL takes into consideration the trip bypass input state when determining the coincidence logics state. Designating the protective channels as A, B, C, D, with no trip bypass present, the local coincidence logic will produce a coincidence signal for any of the following trip inputs: AB, AC, AD , BC, BD, CD, ABC, ABD, ACD, BCD, ABCD. These represent all possible two- or more out-of-four trip combinations of the four protective channels. Should a trip bypass be present, the logic will provide a coincidence signal when two or more of the three unbypassed bistables i are in a tripped condition. l l On a system basis, a coincidence signal is generated in all four protective channels whenever a coincidence of two or more like bistables of the four channels are in a tripped i fq state. g In addition to a coincidence signal, each LCL also provides bypass status outputs. The bypass status is provided to verify that a bypass has actually been entered into the E logic either locally or remotely via the operator's module. The bypass status is available for display at the local and remote operators modules and DPS. B. Initiation Circuit There is an initiation circuit in each channel for each PPS protective function (i.e., RPS, CIAS). For the Reactor Protective System, the initiation logic consists of an "OR" circuit (e.g., a coincidence of high log power p. r low pressurizer pressure pr etc., will result in an initiation signal). For ESFAS's the initiation logic also consist of "OR" circuits. The inputs to the initiation logic are the LCL outputs from the appropriate local coincidence logics. The initiation l circuits also contain a time delay (TD). The TD functions ! as a noise and/or transient filter. It accomplishes this l filter action by monitoring the continuous presence of an I input for a minimum period of time. If the signal is h
?
present for the required time, the signal is transmitted to the initiation relay. Test capability is also provided. Amendment E 7.2-17 December 30, 1988
CESSAREnec-O Figure 7.2-14 illustrates the initiation logic applied to the RPS function. There are separate "OR" circuits for l undervoltage and shunt trip initiation. 7.2.1.1.4 Actuated Devices The final actuation logic for the Reactor Protection System is in the power path to the Control Element Drive Mechanisms Control System and is called the Reactor Trip Switchgear System (RTSS). As illustrated in Figure 7.2-12, the initiation relays interface with the shunt trip and undervoltage devices to trip the circuit breakers that make up the Reactor Trip Switchgear System. To completely remove power from the output circuits requires a minimum of two initiation relays (in opposite legs of the circuit) opening their associated circuit breakers. Power input to the RTSS comes from two full-capacity motor-generator sets, so that the loss of either set does not cause a release of the CEAs. Each line passes through two trip circuit breakers (each actuated by a separate initiation circuit) in series so that, although both sides of the branch lines must be deenergized to release the CEAs, there are two separate means of interrupting each side of the line. Upon removal of power to the CEDM power supplies, the CEAs fall into the reactor core by gravity. l Two sets of manual trip switches are provided to open the trip circuit breakers, if desired. The manual trip completely bypasses the trip logic. As can be seen in Figure 7.2-12, both manual trip switches in a set must be actuated to initiate a E > reactor trip. The trip switchgear is housed in separate cabinets from the RPS. In addition to the trip circuit breakers, the cabinet also contains current monitoring devices for testing purposes and pushbuttons on each trip switchgear which allow for manual opening the circuit breaker. 7.2.1.1.5 Bypasses The design provides for two types of bypasses: operating bypasses and bistable trip channel bypasses as listed in Table 7.2-1. The status of any bypass is indicated at the PPS channel cabinet and PPS Remote Operators Module in the main control room. In addition, all operating bypasses and a summary of the bistable E bypasses in each channel are made available for control room indication via the DIAS and DPS. O Amendment E 7.2-18 December 30, 1988 - 1
J CESSAREna m. O 1 1 A. Operating Bypasses Operating bypasses are provided to permit orderly startup and shutdown of the plant and to allow low pcwer testing. The following operating bypasses are provided:
- 1. DNBR/LPD Trip Bypass The DNBR and local power density bypass, which bypasses the low DNBR and high local power density trips.from ,
the CPC, is provided to allow system tests at low power ( when pressurizer pressure may be low or reactor coolant I pumps may be off. The bypass may be manually initiated j if power is below the bypass setpoint and is I automatically removed when the power level increases above the bypass setpoint. E
- 2. Low Pressurizer Pressure Bypass The RPS/ESFAS pressurizer pressure bypass is provided for two conditions:
- a. System tests at low pressure.
i
- b. Heatup and cooldown with shutdown CEAs withdrawn.
The bypass may be manually initiated. if pressurizer-pressure is below the bypass setpoint.
- 3. High Logarithmic Power Level Bypass E The high logarithmic power level bypass is provided to allow the reactor to be brought to the power range ;
during a reactor startup. The bypass may be manually j initiated above the bypass setpoint and is 1 automatically removed when power decreases below the bypass setpoint. L l
- 4. CPC DNBR CWP and LPD CWP Bypass i An automatic bypass is provided for the DNBR CWP and E LPD CWP signals to the CWP logic if the power level is less than 1 percent full power. The high pressurizer pressure pre-trip to the CWP logic is unaffected by this bypass. Local indication of the nuclear instrument bistable used to generate the one percent full power signal is provided on the safety channel nuclear instrument drawer.
O l i 1 Amendment E i 7.2-19 December 30, 1988 ;
CESSAR Emificari:n 1
- 5. CPC RPC Demand Bypass An automatic bypass is provided for the CPC RPC Demand f signal if the power level is less than one percent full power. Local indication of the nuclear instrument bistable used to generate the one percent full power signal is provided on the safety channel nuclear instrument drawer.
- 6. CPC CMI Bypass An automatic bypass is provided for the CPC CMI signal if the power level is less than one percent full power.
Local indication of the nuclear instrument bistable used to generate the one percent full power signal is provided on the safety channel nuclear instrument drawer. B. Bistable Trip Channel Bypass A bistable trip channel bypass prevents a bistable trip from contributing to the initiation of protective action. The bistable bypass converts the local coincidence logic to a l two-out-of-three coincidence. See Section 7.2.1.1.3. There are two methods of initiating a bistable bypass:
- 1. Individual bistable bypasses located on each local and main control room PPS operators module for each bistable trip.
l: This method is used when removing a trip channel input E l from service for maintenance or manual testing. The trip bypass signal is dist- ibuted to the appropriate i LCL's in the four redundant channels via its inter-face / test processor.
- 2. Four individual bistable bypasses (one for each channel) located on each local and main control room PPS operator's module, for each bistable trip.
This method is used when a complete channel becomes l I disabled (such as loss of vital bus) resulting in trips and no bypasses being sent to the LCL's in the l remaining three channels. Each remaining channel's 1 LCLs can be returned to a two-out-of-three condition for coincidence by the operator inserting trip , bypasses, for the disabled channel trips from its own 1 panel. Administrative procedures ensure the trip i J bypassing in the three remaining channels is consistent. Amendment E 7.2-20 December 30, 1988 l l
CESSARHah m n J V 7.2.1.1.6 Interlocks The following interlocks are provided: E A. Bistable Trip Channel Bypass Interlock ) The LCL trip channel bypass logic allows only one (first entered) of the four trip bypass inputs possible to affect I coincidence generations. The coincidence logic becomes J two-out-of-three for the remaining unbypassed bistable l trips. Bypassing of a bistable, associated with a l particular parameter (e.g., high pressurizer pressure), does ) not place any restrictions on the bypassing of other I I bistables (e.g. low pressurizer pressure) or other bistables associated with other parameters. B. Manual Bistable Test Interlock The manual bistable test function in the four redundant PPS cabinets are interlocked via the four trip channel bypasses, so that only one of the four may be selected for manual bistable testing at any one time. l C. Initiation Circuit Test Interlock l Testing of the initiation circuit is restricted to one redundant PPS cabinet at a ' time to prevent spurious l safeguard actuation. This restriction is accomplished by an interlock which prevents test signals from being generated in more than one PPS cabinet at a time. D. Nuclear Instrumentation Test Placement of the linear calibration switch on the Nuclear Instrument (NI) drawer to other than " operate" will cause a channel variable overpower trip. Placement of the logarithmic calibration switch to other than " operate" will cause a channel high logarithmic power trip. In addition to these two trips, placing either of these calibration ; switches, or any other calibration switch on the NI drawer-to other than " operate" will cause a Power Trip Test interlock to generate a low DNBR, high LPD and steam generator low water level RPS bistable trips in that 'E channel, i E. Core Protection Calculator Test The low DNBR and high local power density channel trips.are interlocked such that they both must be bypassed to test a y CPC channel. l Amendment E 7.2-21 December 30, 1988
CESSAREnebu O 7.2.1.1.7 Redundancy Redundant features of the RPS include: A. Four independent channels, from process sensor through and including channel trip bistables. The CEA position input is E from two independent channels. B. Four redundant sets of local coincidence logics, each set E performs a full two-out-of-four trip function. , C. Four initiation circuits, including four control logic paths and four sets of two initiation relays (shunt trip and E undervoltage). D. Two sets of manual trip pushbuttons with either set being sufficient to cause a reactor trip. E. AC power for the system from four separate vital instrument buses. DC power for the trip switchgear circuit breakers control logic is provided from four separate battery systems, as described in Chapter 8. The result of the redundant features is a system that meets the single failure criterion, can be tested during reactor operation, and can be indefinitely shifted to two-out-of-three coincidence E 1cgic. The benefit of a system that includes four independent and redundant channels is that the nystem can be operated, if need be, with up to two channels cu of service (one bypassed and another tripped) and still mee- the single failura criterion. The only operating restrict 2sm while in this condition . (effectively one-out-of-two logic) is that no provision is made I to bypass another channel for periodic testing or maintenance. The system logic must be restored to at least a three operating channel condition prior to removing another channel for maintenance. (See Section 16.3/4.3.1 Technical Specifications on the RPS.) 7.2.1.1.8 Diversity The system is designed to eliminate credible multiple channel failures originating from a common cause. The failure modes of redundant channels and the conditions of operation that are common to them have been considered in the design to assure that - a predictable common failure modo does not exist. The design ' provides reasonable assurance that: O Amendment E 7.2-22 December 30, 1988
CESSAR !!Micari:n l A. The monitored variables provide adequate information during design basis events (design basis events are listed in Sections 7.2.2.1.1 and~7.2.2.1.2). D. The equipment can perform as required. l l C. The interactions of protective actions, control actions and the environmental changes that cause, or are caused by, the design basis events do not prevent the mitigation of the I consequences of the event. D. The system will not be made inoperable by the inadvertent actions of operating and maintenance personnel. E. There are alternate bistable trips available to provide the reactor trip function, should the initial trip function used in the safety analysis be disabled. This is accomplished by distributing the systems protective functions among multiple processors within each of the redundant PPS cabinets, such that a degree of functional diversity is achieved. As depicted on Figure 7.2-12 bistable trip and local coincidence logic functions are not implemented together in the same processor. In addition, the bistable trip functions are further distributed among the bistable processors within a redundant PPS cabinet. The distribution assignment is . based on a review of the safety analysis transients, such that when multiple trips were available to mitigate the transient, they were assigned to separate bistable trip logic processors (up to four) before a second trip was assigned to a processor. This diversity improves the availability of j the system to handle a transient. F. Plant protection is augmented through the use of a separate and diverse Alternate Protection System as described in E Section 7.7.1.1.11. l l G. Both the RPS and ESF-CCS utilize two different design types, thereby eliminating those hardware and software design common causes which may make them both inoperable. H. Miscalibration of redundant instrument channels and trip logic is minimized by not using a single unit to test all four redundant channels. Additionally, appropriate maintenance and test procedures are implemented by the site operator.
' O l Q Amendment E 7.2-23 December 30, 1988
CESSAR EnWICATIEN O I. Incorrect operator action which directly affect the ability of the RPS to function are precluded by designing the man machine interface such that two or more operator actions are required. For example, see the interlock logics and bypasses described in Sections 7.2.1.1.6 and 7.2.1.1.5. E J. Each RTSS circuit breakers has diverse methods of being automatically opened via the shunt trip and undervoltage ' trip devices. In addition, the design is not encumbered with additional components or channels without reasonable assurance that such ; additions are beneficial. 7.2.1.1.9 Testing Provisions are made to permit periodic testing of the complete RPS with the reactor operating at power or when shutdown. These tests cover the trip actions from sensor input through the protective system and the trip circuit breakers. The system test does not interfere with the protective function of the system. The testing system meets the criteria of IEEE Std. 338-1977, E "IEEE Standard Criteria for the Periodic Testing of Nuclear Power Generating Station Class 1E Power and Protection Systems," and is ! consistent with the recommendations of NRC Regulatory Guide 1.22,
" Periodic Testing of Protection System Actuator Functions."
Periodic testing consists of automatic testing and manual testing. The two methods compliment each other and provide for complete testing of the protection system. There are areas of overlap between the two methods so that the entire RPS can be ] tested. The overlap test methods also permit either system to, in part, verify proper functioning of the other. See Figure 7.2-16. Major portions of the Reactor Protection System are monitored and/or tested by the automatic test network. . lose portions of the syctem which are not amenable te automatic testing because they involve actuation of electromechanical devices, or involve devices which are not within the PPS cabinets, can be tested ; manually. The automatic test network is capable of performing E tests during reactor operation. The automatic testing does not degrade the ability of the RPS to perform its intended function. The automatic test network consists of channelized interface and test processors (ITPs), their associated protection system interface circuits, test voltage generation circuits, and test prohibit circuits (the latter prevents malfunctions of the test system from interfering with the normal operation of the safety system). Overlap exists between the individual tests , Amendment E 7.2-24 December 30, .988 L_-__________
CESSARana mn - m U performed by the automatic test network. The automatic test network can test the protection system continuously. Operation of the automatic test network may be verified locally at the PPS cabinet by requesting test results data. The status and a summary of the automatic testing results are available to the operator via the DIAS and DPS. The monitoring and testing performed by the automatic test network are described below. The monitoring tasks performed by the automatic test network are passive in nature; that is, no active test signals are applied to the protection system. The monitoring consists of reading into E the ITPs all of the protection system data that is accessible to the test task. This data is then analyzed to determine if the protection system is operating properly. The analysis consists of: A. Channel to channel comparison of input signals to detect any channel to channel signal discrepancies (e.g., variance between channels exceeds a predetermined limit). Similar checks are done in the DPS. B. Setpoint checks to verify proper setpoint settings. C. Status consistency checks (i.e., determining that a [ operating bypass, if initiated, is entered into all of the proper logic elements). l The individual tests are described briefly below. Overlap between individual tests exists so that the entire RPS can be tested. Frequency of accomplishing these tests is listed in Technical Specification 16.3/4.3.1. 7.2.1.1.9.1 Sensor Check During reactor operation, the measurement channels providing an ; input to the RPS are checked by comparing the outputs of similar l channels and cross-checking with related measurements. The ITP E l provides sensor data to the DPS where a similar check is done. During extended shutdown periods or refueling, these measurement ! channels (where possible) are checked and calibrated against j known standards. j i 7.2.1.1.9.2 Trip Distable Tests A. Automatic Bistable Testing E The automatic test network performs several tests to insure that the bistable logic is operating properly. First, a' status check is performed. The test task reads the input Amendment E ' 7.2-25 December 30, 1988
CESSARHEnc-l 9 signal after it has been converted into digital form by the analog input circuit, and also reads the setpoints (trip and pre-trip). From these readings the test task makes a determination of what the status should be and compares it to the actual status of the bistable logic. If a discrepancy exists, the test task annunciated a test failure and provides a message that describes the failure in more detail. If the bistable logic is not in a tripped state, testing is continued. By applying known test input signals, the test task can determine if the pre-trip and trip functions of the bistable logic are operating properly. To ensure that the test signal will not interfere with a valid trip signal which may be present, the bistable logic is designed to accept the signal which is closest to thet trip setpoint in the trip direction. Thus, the bistable logic function can never be forced to the untripped state by the test task. Additionally, testing of the bistable logic will not produce a system initiation because:
- 1. The test task removes the test signal before the initiation circuit time delay can respond.
- 2. Any test input signal not removed by the automatic test network will be removed by the timing logic built into the bistable trip logic. The actual measurement E channel signal is not affected by this function; its input into the bistable is thus assured at all times. )
I Distable logic function accuracy tests are performed by ] applying a known test sigr.al into the analog input circuit of the bistable and sampling its converted digitized value. l Proper response of the analog to digital converter to these test signals insures that the bistables logic will trip and , pre-trip .iithin an acceptable tolerance of their setpoints. j l B. Manual Bistable Testing l l Manual testing of the bistable logic functions can be performed to verify proper bistable logic functions not tested automatically. The testing is accomplished by varying the input signal up < to or down to the trip setpoint level on one bistable logic ' function at a time. Using a histable selection switch, and the built in digital voltmeter, it is possible to read the bistable input signal. O1 Amendment E 7.2-26 December 30, 1988
CESSARM*Nic-varying the input signal is accomplished by means of a trip test circuit consisting of'. a digital voltmeter, a test circuit, and trip test switch. The test . circuit is interlocked so that it can be used in only one channel at a time, as 'hown in Figure 7.2-17. A switch is provided to select the measurement channel, and a test switch .is provided to apply the test signal. The digital voltmeter indicates the value of the test signal. Each bistable's trip status is provided to verify its proper response. l The interlock assures the manual bistable testing can'only l be used in one channel at a time. The.' interlock is satisfied when trip channel bypasses from . the- 4 protective channels for the selected bistable are true. This places the selected bistables LCLs in 'a two-out-of-three coincidence. Because a test signal can be less conservative than the process input applied during manual bistable testing, the bistable trip output is forced into a tripped state while the momentary trip test switch is active. Deactivating the switch or changing the trip' channel bypass status will remove the test input voltage and forced trip. C. Msnual Testing of Variable Setpoint with Automatic Rate Limiting Manual testing of bistables that utilize this type of setpoint verifies that: E
- 1. The setpoint tracks the input signal both for increasing and decreasing signals.
- 2. For fixed input the setpoint is fixed and within the prescribed tolerance.
- 3. Maximum and minimum setpoint values if applicable are within the prescribed tolerances.
- 4. The setpoint no longer tracks once a bistable trip occurs but remains fixed until the signal returns to untripped levels.
D. Manual Testing of Variable Setpoint with Manual Reset Testing of bistables using this variable setpoint circuitry is accomplished by use of both automatic and manual tests. Automatic testing is limited to a passive check. This check consists of determining if the setpoint is appropriate'for a Amendment E 7.2-27 December 30, 1988 1
CESSAR E%r"lCATl*N O given input signal level (e.g., considering , bistable logic function that trips on a falling signal, the setpoint should not be more than a predetermined increment below the input signal level). The ability of the variable setpoint circuitry to track the input signal can be verified by means of the manual test panel. From the test panel the bistable input signal may be moved in any direction (i.e., toward the trip value or away from the trip value, whereas the automatic test system can only move the input signal level in the direction of a trip). Using this manual capability it is also possible to verify that a specific time interval must elapse between resets to the circuit. To test this, the setpoint is reset; the input is then manually changed. It is then verified that the manual reset has no effect upon the setpoint until the appropriate time interval has elapsed. E. Manual Testing of Variable Setpoint with Diverse Trip Parameter Testing of bistables using a diverse trip process for setpoint generation will be manually tested in two parts. The first part is done when the bistable is selected and tested for normal trip process input variations. Since the variable cetpoint is not controlled during the first part, the second part will test the variable setpoint function when the trip process used for setpoint generation is varied. Bypassing of the bistable is required during both parts of the testing. E 7.2.1.1.9.3 Core Protection Calculator Tests The operation and calculations of the DNBR/LPD Calculators are tested at three overlapping levels. The first level makes use of operator's modules to make redundant channel comparisons. This ; testing verifies the proper operation of the sensors and data { acquisition portion of the DNBR/LPD Calculator. The second level ' is performed with the DNBR/LPD Calculator off line. An interlock is provided to ensure that this testing is done on only one channel at a time. See Section 7.2.1.1.6E. Testing consists of loading test data from a disk into the DNBR/LPD Calculator to test the program / calculations. During the period that the DNBR/LPD Calculator is off line trip signals are sent from the DNBR/LPD Calculator to the PPS. The third level of testing takes place with the DNBR/LPD Calculator on line. With the DNBR/LPD Calculator on line and bistable bypasses present for high LPD and low DNBR, nuclear power is increased at the nuclear instrument until trip signals are generated by the calculator. Presence of the trip signals are verified at the PPS. Amendment E 7.2-28 December 30, 1988 i
~ CESSAR E!!MICATl3N ( 7.2.1.1.9.4 Local Coincidence Logic Testing Testing of the local coincidence logic is done by the automatic test network. One of the tests performed by the automatic test network is a status check. It does so by reading the status of the inputs to the. logic (trips and bypasses). Based upon those inputs, the test task determines what the outputs (coincidence signal and bypass stntus) should be. If there is a discrepancy between the actual outputs and the determined outputs, the test task annunciated a test failure and provides a message that describes the failure in more detail. If there is no discrepancy and conditions are such that the local coincidence logic is not
- generating a coincidence signal, testing of the logic continues.
The additional testing that is done is dependent upon the status of those inputs over which the test task has no control (bistable bypasses, operating bypasses, and bistable trips due to the signal inputs). Based upon the known inputs, the test system will generate all bistable trip combinations that are within its cutrol', recalling that a tripped bistable cannot be forced to the untripped condition by the test task. The outputs of the local coincidence logic are then monitored for correctness. All possible combinations of bistable trips are generated. 7.2.1.1.9.5 RPS Initiation Logic Testing The initiation logic, which consists of an "OR" logic is tested at the same time the local coincidence logic is tested. (see Figure 7.2-14) Each time a coincidence signal is generated, the automatic test task verifies that the signal is propagated through the "OR" logic. Failure of the coincidence signal to E I propagate through the "OR" logic will result in the annunciation of a test failure and a message that describes the failure in i l more detail. l A. Testing of RPS Time Delay and Reactor Trip Circuit Breakers l The RPS time delay ~ and circuit breaker test is a manually initiated test. The test is manually initiated because the test philosophy requires operator involvement in the testing and reclosing of these important reactor trip' devices. The operator can obtain status information from the undervoltage, shunt trip and current monitors ' depicted in Figure 7.2-12 and thus determine the success or failure of the test for both of the diverse methods of tripping the l breaker. O V l Amendment E 7.2-29 December 30, 1988
CESSAR 8annCAT10N l l l 7.2.1.1.9.6 Manual Trip Test e{ i The manual trip feature is tested by depressing one of the four manual trip pushbuttons, observing a trip of a trip breaker, and resetting the breaker prior to depressing the next manual trip pushbutton. Closing of the circuit breaker can be initiated from the PPS operator's module locally or at the main control room. Tne manual initiation switch is a 3-position rotary return to center with a momentary pushbutton. The three positions are: (1) Undervoltage Coil, (2) Shunt Trip Coil and (3) Both. The center position is Both. 7.2.1.1.9.7 Bypass Testing A. Operating Bypass Testing The Operating Bypasses are automatically tested. Testing is both passive and active. The passive check consists of verifying the appropriateness of the bypass, i.e., is the input parameter in the range of values over which the bypass is allowed. The active test, as a part of the bistable logic testing, verifies that the bistable can have an output consistent with the operating bypass status, i.e., if an operating bypass is not present, the bistable can be tripped; with an operating bypass present, the bistable cannot be tripped. The permissive bistable logic from which the operating bypass logic receives the auto-removal signal is also verified. This is accomplished by actively testing the permissive bistable logic in the same manner that the trip bistable logic functions are tested. Whnn testing the permissive bistable it can be verified that when the E auto-removal condition is present, the operating bypass is removed. B. Bistable Trip Channel Bypass Testing A description of testing bistable trip channel bypasses is included as part of the local coincidence logic testing described in Section 7.2.1.1.9.4. 7.2.1.1.9.8 Response Time Tests l Response time testing of the complete Reactor Protective System, ; is accomp]ished by the combined use of portable field installed test equipment and test features provided as part of the PPS i automatic test network. l l l Amendment E , 7.2-30 December 30, 1988 l l l
CESSAR1 Hec-Measurement Channel Response Time Tests, which include portions ) of the system (such as cables and sensors) may be conducted on a E l system basis or an overlapping subsystem basis. j Methods which are used to conduct these tests include:- A. Perturbation and monitoring of plant parameters - either during operation or while shutdown. This method is applicable to RTDs (monitored following a plant. trip),lE j reactor coolant pump speed sensors (monitored following ! turn-off of pump), and CEA position reed switches (monitored ! during CEA motion). B. On-line power spectral density analysis. This method would be applicable to analog sensors. C. Off-line injection of step or ramp changes for RPS inputs. This method would be applicable to sensors (via special pressure test rigs, hot oil baths or hot sand boxes) or electronics and logic (via special electrical test boxes). D. The automatic test network in the course of its normal testing implicitly verifies that the response time of the y O PPS is less than a known upper limit. The upper limit is bounded by the bistable -logic processor execution time (fixed) plus .the coincidence processor execution time (fixed) plus the worst case skew time due to the asynchronous operation of the processor. An independent timer monitors the fixed execution time and provides overruns status. The automatic test network reads this status and will annunciate a failure. E. Operation and monitoring of actuated devices. This method would be applicable to the CEDMs, including their control logic and switchgear. F. System test - from sensor to actuated device - utilizing a ! combination of the above techniques. This method might incorporate, for example, a step input from a test rig to a sensor, measuring total time until CEDMs drop. G. Factory or laboratory tests of removed components. This l method would be applicable to all components. The trip delay times used in the Chapter 15 Safety Analysis for various trips are verified by using the above methods. E Specifically, the methods applicable to each trip are: O Amendment E 7.2-31 December 30, 1988
CESSAR 8!L"lCATCN O (1) High Logarithmic and Variable Overpower Levels use method B, C, D, F cr G. (2) Low DNDR and High Local Power Density use method A, B, C, D, E, F or G. (3) High Pressurizer Pressure, Low Pressurizer Pressure, Low , Steam Generator Water Level, Low Steam Generater Pressure and High Steam Generator Water Level use method B, C, D, E, F or G. The design of the Reactor Protective System is such that connections may conveniently be made for the appropriate test equipment. The hardware design includes test connections on the instrument lines going to pressure and differential pressure transmitters, and test points wired out to convenient connectors or terminal strips. C-E supplies to the site operator the data obtained during factory or laboratory testing so that this may be correlated with this field data. 7.2.1.1.10 Vital Instrument Power Supply The vital instrument power supply requirements are discussed in Chapter 8. E 7.2.1.1.11 System Arrangement RPS components are arranged so as to conform to the separation, independence, and other criteria specified in this chapter. The safety-related components are located to provide access for maintenance, testing and operation as required. The redundant channels and divisions of the PPS, RPS and RTSS , instrumentation and control cabinets are designed to be located I in separate plant control complex locations. These locations conform to Regulatory Guides 1.17 and 1.120 for safety system security and fire protection as described in Sections 7.1.2.16 and 7.1.2.29. The control complex and RPS arrangements are designed to maintain independence between the Main Control Room and Remote Shutdown Panel such that transfer of control can be achieved as described in Sections 7.4.1.1.10 and 7.7.1.3. 7.2.1.2 Resj3n Bases The RPS is designed to assure adequate protection of the fuel, ; fuel cladding, and RCS boundary during Anticipated Operational i' Occurrences. In addition, the system is designed to assist the Amendment E 7.2-32 December 30, 1968
CESSAR !!nificarica N ESP Systems in mitigating the consequences of accidents. To ensure that these design bases are achieved, the reactor must be maintained within the limiting conditions. of operation, as defined in Technical Specification 16.3/4'.3.1 and the limiting safety system settings implemented consistent with Section 16.2.2. The system is designed on the.following bases to assure adequate performance of its protective function: A. .The system is designed in compliance with. the applicable criteria of.the " General Design Criteria for Nuclear Power Plants," Appendix A of 10 CFR 50. E B. -Instrumentation, function, and operation of the system conforms' to the requirements of IEEE Standard 279-1971,
" Criteria for Protective Systems for Nuclear Power-Generating Stations."
C. System testing conforms to the requirements of IEEE Standard 338-1977, " Standard Criteria for Periodic Testing of Nuclear E Power Generating Station Protection Systems." D. The system is designed in consistence with the l recommendations of Regulatory Guide 1.53, " Application of l the Single-Failure Criterion to Nuclear Power Plant Protective Systems," and Regulatory Guide 1.22, " Periodic Testing of Protection System Actuation Functions." E. The system is designed to det' ermine.the following generating station conditions in order to provide adequate protection during Anticipated Operational Occurrences:
- 1. Core power (neutron flux).
- 2. Reactor coolant system pressure.
l l 3. DNBR in the limiting coolant channel in the core. l 4. Peak local power density in the limiting fuel pin in ' the core.
- 5. Steam generator water level.
- 6. Reactor coolant flow. E O
Amendment E 7.2-33 December 30, 1988
CESSAR n%"lCATl!N 1 01 F. The system is designed to determine the following generating station conditions in order to provide mitigation assistance to the ESF during accidents :
- 1. Core power.
- 2. RCS pressure.
- 3. Steam generator pressure.
- 4. Containment pressure.
- 5. Reactor coolant flow.
- 6. Steam Generator Water Level. E
/. DNBR in the limiting coolant channel in the core.
C. The system is designed to monitor all generating station variables that are needed to assure adequate determination of the conditions given in listings E and F above, over the entire range of normal operation and transient conditions. The full power nominal values and the maximum and minimum values that can be sensed for each monitored plant variable are given in Table 7.2-2. The type, number, and location of the sensors provided to monitor these variables are given in Table 7.2-3. H. The system is designed to alert the operator when any monitored plant condition is approaching a condition that would initiate protective action. I. The system is designed so that protective action will not be initiated due to normal operation of the generating station. Nominal full power values of monitored conditions and their corresponding protective action (trip) setpoints are given in Table 7.2-4. The selection of these trip setpoints is such that adequate protection is provided when all sensor and processing time delays and inaccuracies are taken into account. Reactor j trip delay times and analysis setpoints are given in the j Chapter 15 safety analyses. E l 1 The reactor protective system sensor response times, reactor trip delay times, and analysis setpoints used in Chapter 15 are representative of the manner in which the RPS and l associated instrumentation will operate. These quantities i
)
Amendment E l 7.2-34 December 30, 1988 i
1 CESSAR H5Nic.1,s. ' O are used in the transient analysis documented- in Chapter 15. Note that the reactor trip delay times shown in Chapter 15 do not include the sensor response times. E Actual RPS equipment uncertainties, response times and reactor trip-delay times are obtained from calculations and 3 tests performed on the RPS and associated instrumentation. 4 The verified system uncertainties are factored into all~RPS settings and/or setpoints to assure that the system 1 l adequately performs its intended function when the errors ! l and uncertainties combine in an adverse manner. J. All system components are qualified for environmental and seismic conditions in accordance with IEEE Standard 323-1983, and IEEE Standard 344-1987. Compliance is E addressed in Sections 3.10 and 3.11, respectively. In addition, the system is capable of performing its intended function under the most degraded conditions of the energy supply, as addressed in Section 8.3. 7.2.1.3 8v_ stem DrawinQs The RPS MCBDs, signal logics, block diagrams, and' test circuit block diagrams are shown in Figures 7.2-1 through 7.2-30. E 7.2.2 ANALYSIS 8 7.2.2.1 Introduction The RPS is designed to provide the following protective i functions: l A. Initiate automatic protective action to assure that acceptable RCS and fuel design limits are not exceeded during specified Anticipated Operational Occurrences. B. Initiate automatic protective action during accidents to aid the ESF Systems in limiting the consequences of the accidents. A description of the reactor trips provided in the RPS is given in'Section 7.2..l.1.1. Section 7.2.2.2 provides the bases for all the_RPS trips and Table 7.2-4 gives the applicable nominal trip setpoints. Some of the trips in the RPS are single parameter trips (i.e., a trip signal is generated by comparing a single measured variable with a fixed setpoint). The RPS trips that do not fall into this category are as follows: i ( Amendmor.n E 7.2-35 December 30, 1988 l
CESSAR n!'rificaritu O A. Low Pressurizer Pressure Trip This trip employs a setpoint that is determined as a function of the measured pressurizer pressure or that is varied by the operator. B. Low Steam Generator Pressure Trip This trip employs a setpoint that is determined as a function of the measured steam generator pressure or that is varied by the operator. C. Low Steam Generator Water Level Trip This trip employs a variable setpoint that is a function of reactor power. The setpoint will track automatically in an increasing or decreasing direction. A fixed minimum low setpoint is also incorporated. D. High Local Power Density Trip This trip is calculated as a function of several measured variables. E. Low DNBR Trip This trip is calculated as a function of several measured variables. F. Variable Overpower This trip employs a variable setpoint that will track E automatically in an increasing or decreasing direction. Rate of change of an increasing neutron flux power input is limited by a predetermined input to setpoint margin and setpoint tracking rate. A fixed high setpoint is also incorporated. G. Low Reactor Coolant Flow Trip , This trip employs a variable setpoint that will track automatically in an increasing or decreasing direction. A decreasing rate of change of the differential pressure across the primary side of the steam generator input signal is limited by a predetermined input to setpoint margin and setpoint tracking rate. A fixed low setpoint is also incorporated. O Amendment E 7.2-36 December 30, 1988
~ CESSAREMncm2 O The low DNBR and high. local power density trips are provided in the CPCs. All RPS trips are provided with a pre-trip alarm in addition to the trip alarm. Pre-trip alarms are provided to alert the operator to an approach to a trip conditioriand play no part in the safety evaluation of the plant. Each RPS setpoint is chosen to be consistent with the function of the respective trip. The adequacy of all RPS trip setpoints, with the exception of the low DNBR and high local power density trips, is verified through an analysis of the pertinent system transients reported in Chapter 16. These analyses utilice an Analysis Setpoint (assumed trip initiation point) and system delay times associated with , the respective trip functions. The analysis setpoint along with instrument uncertainties provides the basis for the calculation of the final equipment setpoints to-be reported in the Technical Specifications. Limiting trip delay times are given in Chapter 15. The manner by which these delay times and uncertainties will be verified is discussed in Section 7.2.1.2. The adequacy of the low DNBR and high local power density trips was certified by a combination of static and dynamic analyses. These analyses provide assurance that the low DNBR and high local O power density trips function as required and provide the justification for the CPC time response assumed in Chapter 15 safety analyses. This is accomplished by certifying' that algorithms used in these two trips predict results that are conservative with respect to the results obtained from standard design methods, models, and computer codes used in evaluating plant performance. This verification also takes into account all errors and uncertainties associated with these two trips, in addition to trip delay times, and will assure that .the consequences of any Anticipated Operational Occurrences do not include violation of specified acceptable fuel design limits. Examples of the computer codes that will be used in this verification are given in Chapter 15. 7.2.2.1.1 Anticipated Operational Occurrences Anticipated Operational Occurrences that are accommodated by the ; system are those conditions that may occur one or more times during the life of the plant. In particular, the occurrences considered include single component or control system failures resulting in transients which may require protective action. A U 7.2-37
CESSARESAL - O The fuel design and RCPB limits used in the RPS design for Anticipated Operational Occurrence are: A. The DNBR, in the limiting coolant channel in the core, shall not be less than the DNBR safety limit. E B. The peak local power density in the limiting fuel pin in thb core shall not be greater than the peak linear heat rate safety limit. E C. The RCS pressure shall not exceed established pressure boundary limits. The Anticipated Operational Occurrence that were used to determine the system design requirements are: A. Insertion or withdrawal of CEA groups, including: E
- 1. Uncontrolled sequential withdrawal of CEA groups.
- 2. Out of sequence insertion or withdrawal of CEA groups.
- 3. Excessive sequential insertion of CEA groups. E B. Insertion or withdrawal of CEA subgroups, including:
- 1. Uncontrolled insertion or withdrawal of a CEA subgroup.
- 2. Dropping of one CEA subgroup. )
- 3. Misalignment of CEA subgroups comprising a designated CEA group. E C. Insertion of a single CEA, including:
- 1. Uncontrolled insertion of a single CEA.
- 2. A dropped full- or part-length CEA.
- 3. A statically misaligned CEA.
D. Uncontrolled boron dilution. E. Excess heat removal due to secondary system malfunctions. F. Change of forced reactor coolant flow resulting from a loss of electrical power to reactor coolant pumps. O Amendment E 7.2-38 December 30, 1988
s-
- CESSARENFinem i
! i i l G. Inadvertent pressurization or depressurization of RCS resulting .from. anticipated single control system malfunct.ons. H.. Change of normal heat transfer capability between~ steam and ! reactor coolant systems resulting from improper feedwater l flow, a loss ofLexternal load and/or turbine trip,:or a loss of condenser vacuum. E s I I. Complete loss of AC. power to the station. auxiliaries. J. Asymmetric steam generator transients due to instantaneous E closure of one MSIV. K. Uncontrolled axial Xenon oscillations.. L. Depressurization due to.the inadvertent actuation of primary or secondary safety valves. The implementation of CPC initiated CEA motion inhibit and E cutback demand functions has resulted in the reclassification of selected CEA malfunction events to be classed as Accidents. I These events are . included in Section 7.2.2.1.2 as unplanned events for which the RPS will take action. 7.2.2.1.2 Accidents' The accidents for which the system will .take action are those unplanned events under any conditions that may occur once during-the life of several stations and certain combinations of unplanned events and degraded systems that are never expected to occur. The consequences of most of these limiting faults will be limited by the ESF Systems; the RPS will provide action to assist in. limiting these conditions for these accidents. The accidents for which the RPS will provide protective action assistance are: A. RCS pipe rupture. l B. CEA events, including:
- 1. Ejection of any single CEA.
- 2. Uncontrolled withdrawal of single CEA. E
- 3. A single CEA sticking, with the remainder of the CEAs in that group moving.
C. Steam system pipe rupture. E l'O Amendment E 7.2-39 December.30, 1988
CESSAR 8HnnCAT12N O D. Feedwater system pipe rupture. E. Reactor coolant pump shaft seizure. E F. Break in a line from the reactor coolant pressure boundary that penetrates containment. G. A reactor coolant pump sheared shaft. , H. Steam generator tube rupture. l 7.2.2.2 Trip Bases The RPS consists of fifteen trips in each of the four RPS E channels that will initiate the required automatic protective action utilizing a coincidence of two like trip signals. A brief description of the inputs and purpose of each trip is presented in Sections 7.2.2.2.1 through 7.2.2.2.11. 7.2.2.2.1 Variable Overpower Trip A. Input Neutron flux power from the excore neutron flux monitoring system. B. Eurpose e To provide a reactor trip to assist the ESF Systems in the event of an ejected CEA Accidents. 7.2.2.2.2 High Logarithmic Power Level Trip A. Ipout Neutron f1ux power from the excore neutron flux monitoring system. B. Ihlrpose To assure the integrity of the fuel cladding and RCS ; boundary in the event of unplanned criticality from a , shutdown condition, resulting from either dilution of the j soluble boron concentration or uncontrolled withdrawal of l CEAs. In the event that CEAs are in the withdrawn position, ) automatic trip action will be initiated. If all CEAs are I inserted, an alarm is provided to alert the operator to take l appropriate action in the t_ vent of an unplanned criticality. l I Amendment E l 7.2-40 December 30, 1988 i j )
-i CESSAR EnWicarien l
i
.f' N
\
7.2.2.2.3 High Local Power Density Trip i 1 A. Inputs j
- 1. Neutron flux ; power and axial power ' distribution from the excore neutron flux monitoring system.
- 2. Radial peaking factors from CEA position measurement system (reed switch assemblies).
l i
- 3. Thermal power from coolant temperatures, pressure and flow measurements.
- 4. Penalty factors from CEACs for CEA deviation within a subgroup.
- 5. Penalty factors generated within the CPC for subgroup deviation and groups out-of-sequence.
B. Purnose To prevent the linear heat rate (kW/ft) in the limiting fuel pin in the core from exceeding fuel design limits in the event of defined Anticipated Operational Occurrences. 7.2.2.2.4 Low DNDR Trip A. Innuts l 1. Neutron flux power and axial power distribution from l the excore neutron flux monitoring system.
- 2. RCS pressure from pressurizer pressure measurement.
- 3. Thermal power from coolant temperatures, pressure and flow measurements.
- 4. Radial peaking factors from CEA position measurement (raed switch assemblies).
- 5. Reactor coolant mass flow from reactor coolant pump speeds and temperatures.
I L
- 6. Core i temperature from reactor coolant cold leg tempen i .e measurements.
- 7. Penalty factors from CEACs for CEA deviation within a subgroup.
( 7.2-41
i CESSAR EnL"icar 2u 1 O
- 8. Penalty factors generated within the CPC for subgroup deviation and groups out-of-sequence.
B. Purpose To prevent the DNB ratio in the limiting coolant channel in ' the core from exceeding the fuel design limit in the event of defined Anticipated Operational Occurrences. In addition, this trip will provide a reactor trip to assist the ESF Systems in limiting the consequences of the steam line break inside and outside containment, steam generator tube rupture and reactor coolant pump shaft seizure E accidents. 7.2.2.2.5 High Pressurizer Pressure Trip A. Input Reactor coolant pressure from narrow range (1500-2500 psia) pressurizer pressure measurement. B. Purpose To help assure the integrity of the RCS boundary for any defined Anticipated Operational Occurrence that could lead to an overpressurization of the RCS. 7.2.2.2.6 Low Pressurizer Pressure Trip A. Input Reactor coolant pressure from combined high and low range E pressurizer pressure measurements. B. purpose To provide a reactor trip in the event of reduction in system pressure, in addition to the DNBR trip, and to provide a reactor trip to assist the ESF Systems in the event of a LOCA. 7.2.2.2.7 Low Steam Generator Water Level Trips A. lupjjt ( 1 Level of water in each steam generator downcomer region from ) wide range differential pressure measurements. Neutron flux power from the ex-ccre neutron flux monitors for E determination of the variable water level setpoint. i l l Amendment E } 7.2-42 December 30, 1988 l
CESSAR EnWicarieu O ' B. Puroose To provide a reactor trip to assist the ESF systems to assure that there is sufficient time for actuating the emergency feedwater pumps to remove decay heat _ from the reactor in the event of a reduction of steam generator water inventory. 7.2.2.2.8 Low Steam Generator Pressure Trips A. Input- j a Steam pressure in each steam generator. ] B. Purpose To provide a reactor trip to assist the ESF Systems in the event of a steam line break accident. 7.2.2.2.9 High Containment Pressure Trip A. Inp_u_t Pressure inside reactor containment. B. Purpose To assist the ESF Systems by tripping the reactor coincident with the initiation of safety injection caused by - excess i pressure in containment.
]
7.2.2.2.10 High Steam Generator Water Level Trips A. Input Level of water in each steam generator downcomer region from narrow range differential pressure measurements. B. Purpose To assist the ESF Systems by tripping the reactor coincident with initiation of Main Steam Isolation caused by a high steam generator water level. 7.2.2.2.11 Low Reactor Coolant Flow A. Input Pressure differential measured across the steam generator primary side. 7.2-43
CESSAR nMicuiw OI B. Purpose l To provide a reactor trip in the event of a reactor coolant pump sheared shaft. 7.2.2.2.12 Manual Reactor Trip I A. Input J J Two independent sets of trip pushbuttons. E B. Purpose A Manual Reactor Trip is provided to permit the operator to trip the reactor. 7.2.2.3 Desion 7.2.2.3.1 General Design Criteria Appendix A of 10 CFR 50, " General Design Criteria for Nuclear Power Plants," establishes minimum requirements for the principle design criteria for water-cooled nuclear power plants. This section describes how the requirements that are applicable to the RPS are satisfied. Criterion 1 - Quality Standards and Records: Refer to Section 3.1.1 for compliance. Criterion 2 - Design Bases for Protection Against Natural Phenomenon: Refer to Section 3.1.2 for compliance. Criterion 3 - Fire Protection: Refer to Section 3.1.3 for compliance. Criterion 4 - Environmental and Missile Design Bases: Refer to Section 3.1.4 for compliance. Criterion 5 - Sharing of Structures, Systems, and Components: ) l Refer to Section 3.1.5 for compliance. l l 91l Amendment E 7.2-44 December 30, 1988
CESSAR Ennnema i O Criterion 10 - Reactor Design: Refer to Section 3.1.6 for compliance. ., Typical margins between'the' normal operating value ' and the trip setpoint are given on Table 7.2-4. Criterion 12 - Suppression of_ Reactor Power Oscillations: Refer to Section 3.1.8 for compliance. The axial power . distribution is continuously monitored by the RPS and factored into the low DNBR and high LPD trips. This assures that acceptable fuel design limits are ' not , exceeded in the event of axial power ; oscillations. Allowances are made in the trip setpoints for azimuthal power tilts. Criterion 13 - Instrumentation and Control: { Refer to Section 3.1.9 for compliance. Criterion 15 - Reactor Coolant System Design: Refer to Section 3.1.11 for compliance. Criterion 16 - Containment Design: Refer to Section 3.1.12 for compliance. Criterion 19 - Control Room: l Refer to Section 3.1.15 for compliance. RPS E status monitoring and controls necessary for , safe operation of the unit are provided in j the main _ control room via' the DIAS, DPS, CPC Remote Operators Modules and the PPS Remote Operators Modules, q Criterion 20 - Protection System Functions: l Refer to Section 3.1.16 and 7.2.2.1 for E compliance. Criterion 21 - Protection System _ Reliability and_ Testability: Refer to Section 3.1.17 and 7.2.2.3.3 for- E compliance. Amendment E 7.2-45 December 30, 1988
CESSAREE%m lll: Criterion 22 - Protection System Independence: Refer to Sections 3.1.18 and 7.2.2.3.2.F for compliance. Critorion 23 - Protection System Failure Modes: Refer to Sections 3.1.19 and 7.2.2.4 for compliance. Criterion 24 - Separation of Protection and Control Systems: Refer to Sections 3.1.20, 7.2.2.3.2.G and 7.7.1.1.13 for compliance. Criterion 25 - Protection System Requirements for Reactivity Control Malfunctions: Refer to Section 3.1.21 for compliance. Criterion 29 - Protection Against Anticipated Operational occurrences: Refer to Section 3.1.25 for compliance. 7.2.2.3.2 Equipment Design Criteria > IEEE Std. 279-1971 " Criteria for Protection Systems for Nuclear Power Generating Stations," establishes minimum requirements for ; safety-related functional performance and reliability of the RPS. This section describes how the requirements of Section 4 of IEEE Std. 279-1971 are satisfied. The parenthesize data, following headings, correspond to the Section numbers of IEEE Std. 279-1971. A. General Functional Requirement (Section 4.1): j The RPS is designed to limit reactor fuel, fuel cladding, and coolant conditions to levels within plant and fuel design limits. Instrument performance characteristics, response times, and accuracy are selected for compatibility j with and adequacy for the particular function. Trip ! cetpoints are established by analysis of the system parameters Factors such as ] instrument inaccuracies, > bistable trip times, CEA travel times, and circuit breaker trip times are considered in the design of the system. B. Single Failure Criterion (Section 4.2): l The RPS is designed so that any single failure within the system shall not prevent proper protective action at the 7.2-46 l
CESSAR !aWicaris. O system level. No single failure . will defeat more than one of the four protective channels associated with any one, trip function. The wiring in the system is grouped so that no single fault or failure, including either an open or shorted circuit, will negate protective system operation. Signals routed between redundant PPS cabinets utilizes fiber-optic E l cables. Signal conductors and power leads coming into or i going out of each cabinet are. protected and routed separately for each channel of cach system to minimize possible interaction. Single failures considered in the design of the RPS are described in the Failure Modes and Effects Analysis (FMEA) shown on Table 7.2-5. C. Quality Control of Components and Modules (Section 4.3): The systems which function to provide protective action are designed in accordance with the Quality Assurance Program E described in Chapter 17. D. Equipment Qualification (Section 4.4): The RPS meets the equipment requirements described in 1 Sections 3.10, 3.11, 7.1.2.5 and 7.1.2.8. E E. Channel Integrity (Section 4.5): Type testing of components, separation of sensors and channels, and qualification of the cabling by the site operator, are utilized to ensure that the channels will maintain their functional capability required under applicable extremes of environment, power supplied, malfunction and fault conditions. Loss of or damage to any one channel will not prevent the protective action of the RPS. Sensors are connected so that blockage or failure of any one connection does not prevent protective system action. The process transducers located in the containment building are specified and _ rated ' for the intended service. { i Components which must operate during or after an accident are qualified for the most limiting environment for the period of time for which they must maintain their functional capability. Results of type tests are used to verify this. F. Channel Independence (Section 4.6): E Each redundant channel is independent of the other redundant channels. The censors are separated, cabling is routed separately and each redundant channel is located in- a separate cabinet, geographically located in different fire I zones. This minimizes the possibility of a single event E ] Amendment E l 7.2-47 December 30, 1988 , l
CESSAREEMem O1 causing more than one channel's failure. The outputs from these redundant channels are isolated from each other so that a single failure does not cause impairment of the system function. The Reed Switch Position Transmitter signals are sent to separate CEA Calculators. To provide the required input to the CEAC, the signals utilized as inputs are sent through optical isolators (see Figure 7.2-7). Outputs from the redundant channels to non-safety related areas are isolated utilizing fiber-optic cable so that a failure in the non-safety related area does not cause loss of the safety system function. Outputs from the components of the RPS to the control boards are isolated. The signals originating in the RPS which feed the DIAS, DPS and control systems are isolated utilizing fiber optic cable to maintain their channel independence. The compliance of the RPS with the requirements of IEEE 384-1981, "IEEE Standard Criteria for Independence of Class 1E Equipment and Circuits," and Regulatory Guide 1.75,
" Physical Independence of Electric Systems," is discussed in Section 7.1.2.10.
G. Control and Protection System Interaction (Section 4.7):
- 1. Classification of Equipment (Section 4.7.1):
E Protective system functions and control systems that have identical sensor requirements may utilize the same sensors (see the MCBDs for the specific sensors which are shared). The control systems use sensor signal validation logic, as described in Section 7.7.1.1.13, to avoid control protection system interactions. The RPS' DNBR, LPD, and high pressurizer pressure pre-trips provide a CEA Withdrawal Prohibit (CWP) to the CEDMCS. The CPCs provide CEA Motion Inhibit (CMI) and Reactor l Power Cutback Demand signals to the CEDMCS. The MDS monitors margin-to-trip conditions for RPS parameters to establish limiting conditions of operation for load following maneuvers. i Portions of the protective channels used for both i
^
protection and control are classified as part of the, protection system up to and including the isolation ! device used to interface with the control system. l Amendment E 7.2-48 December 30, 1988
CESSAR Eanr"1 CATION
- 2. Isolation Devices (Section 4.7.2):
Control signals from the RPS are isolated using fiber optic cable such that a failure will not affect the protective action of the RPS.
- 3. Single Random Failure (Section 4.7.3):
This criterion is not applicable. Due to signal E validation, the signals which are sent to the control systems cannot cause a control action which could require a protective action.
- 4. Multiple Failures Resulting From a Credible Single Event (Section 4.7.4):
This cannot exist since failures within the protective system can not propagate to the control systems due to isolation devices. H. Derivation of System Input (Section 4.8): Insofar as is practicable, system inputs are derived from signals that are direct measures of the desired variables. Variables that are measured directly include neutron flux, temperatures, and pressures. Level information is derived from appropriate differential pressure measurements. Flow information is derived from steam generator primary sid differential pressure measurements, E reactor coolant pump speed measurement and coolant temperature. I. Capability for Sensor Checks (Section 4.9): RPS sensors are checked by cross-channel comparison. Each channel has a known relationship with the other channels of the same parameter. J. Capability for Test and Calibration (Section 4.10): The RPS design complies with IEEE Std. 338-1977, " Periodic E Testing of Nuclear Power Generating Station Class 1E Power and Protection Systems," and the intent of Regulatory Guide 1.22, " Periodic Testing of Protection System Actuator Functions," as discussed in Section 7.2.2.3.3. K. Channel Bypass or Removal From Operation (Section 4.11): Any one of the four protection channels in the RPS may be tested, calibrated, or repaired without impairing the systems' protective action capability. In the RPS, individual trip channels may be bypassed to create a Amendment E 7.2-49 December 30, 1988 _ _ _ _ _ - _ _ _ - _ _ _ - _ l
CESSAR EnMCAEN O two-out-of-three logic on the remaining channels which maintains the coincidence of two required for trip. The single failure criterion is met during this condition. Testing of each of the two CEA position indication channels can be accomplished in a very brief time. The probability of failure of the other position indication system is acceptably low during such testing periods. L. Operating Bypasses (Section 4.12): Operating bypasses are provided as shown on Table 7.2-1. The operating bypasses are automatically removed when the permissive conditions are not met. The circuitry and . devices which function to remove these inhibits are designed I in accordance with IEEE Std. 279-1971. M. Indication of Bypasses (Section 4.13): 1 Indication of test or bypass conditions, or removal of any channel from service is given via remote operator's modules and DPS. Operating bypasses that are automatically removed at fixed setpoints are alarmed and indicated via remote operator's modules and DPS. N. Access to Means for Bypassing (Section 4.14): Trip channel bypasses from the PPS cabinets are controlled since the equipment rooms have access controlled by means of E key locked doors. Trip channel bypasses from the main control room PPS operator's modules are under the control room operator's cognizance. When the first parameter is I bypassed there is an alarm to indicate which channel is ) being bypassed. The specific parameter or parameters which l are being bypassed are indicated at the PPS cabinet and its remote operator's module. The operating bypasses have audible and visible alarms. The operating bypasses have automatic features which provide a permissive range at which they can be actuated. Should the ! permissive range be exceeded, the bypass will be auto- I matically removed. O. Multiple Setpoints (Section 4.15): Manual reduction of the setpoints for Jow pressurizer pressure and low steam generator pressure trips are used for the controlled reduction of pressurizer pressure and steam generator pressure as discussed in Sections 7.2.1.1.1.6 and 7.2.1.1.1.8. The setpoint reductions are initiated by main Amendment E 7.2-50 December 30, 1988
CESSAR WMem
?%
iv) control board pushbuttons f,or each channel, one pushbutton for the pressurizer pressure and one pushbutton for both steam generator pressures within the one channel. This method of setpoint reduction provides positive assurance that the setpoint is never decreased below the existing pressure by more than a predetermined amount. The variable low water level setpoint for each steam generator automatically tracks reactor power from a minimum low power value to a maximum full power value and vice versa. The variable setpoint is designed with muximum E ceiling and minimum floor values such that sufficient water inventory is available to prevent unwarranted actuation of emergency feedwater following a reactor trip. l The variable overpower trip setpoint tracks the actual reactor power from a minimum value to a high value or vice versa, if the power changes slowly enough. The variable overpower trip setpoint is designed with a maximum rate of decrease or increase. Should the actual power increase at too rapid a rate, it will catch up with the more slowly increasing setpoint and cause a trip. The low reactor coolant flow trip setpoint automatically (mV') tracks below the input variables by a fixed margin for all decreasing inputs with a rate less than the rate limit. The setpoint decreases at a fixed rate for all decreasing input variabic changes greater than the rate limit. Should the input variable decrease at too rapid a rate, it will catch up with the more slowly decreasing setpoint and cause a trip. The setpoint automatically increases as the input variable ir. creases independent of rate. P. Completion of Protective Action Once it is Initiated (Section 4.16): l The system is designed to ensure that protective action (reactor trip) will go to completion once initiated. Operator action is required to clear the trip and return to , l operation. Protective action is initiated when the reactor l; ' trip circuit breakers open. Protective action is completed when the CEAs arrive at their full-in position. Q. Manual Initiation (Section 4.17): A manual trip is effected by depressing either of two sets of trip pushbuttons in the main control room for remotely - tripping the RTSS or using the local pushbuttons on the
/^' RTSS. No single failure will prevent a manual trip. l \
Amendment E 7.2-51 December 30, 1988
CESSAR E%incuia O R. Access to Setpoint Adjustments, Calibration and Test Points (Section 4.18): Keys or built-in features are provided to control setpoints, changes to CPC constants, calibration, and test point adjustments. Access is indicated to the operator. The site E . operator controls access via key locks, administrative procedures, and other means to limit access. I
- S. Identification of Protective Action (Section 4.19)
- ]
i Indications are provided for all protective actions, including identification of channel trips. The breaker status and current indication are available to the operatsr. T. Information Readout (Section 4.20): Means are provided to allow the operator to monitor all trip system inputs, outputs and calculations. The specific displays that are provided for RPS status monitoring are E described in Section 7.5. U. System Repair (Section 4.21): Identification of a defective input channel will be accomplished by observation of system status lights or by tenting as described in Section 7.2.1.1.9. Replacement or repair of components is accomplished with the affected input channel bypassed. The affected trip function then operates in a two-out-of-three trip logic while maintaining the coincidence of two required for trip. V. Identification (Section 4.22): All equipment, including panels, modules, and cables, associated with the trip system will be marked in order to facilitate identification. Interconnecting cabling will be color coded as discussed in Chapter 8. E 7.2.2.3.3 Testing Criteria Conformance to IEEE Std. 338-1977 and the intent of Regulatory Guide 1.22 are discussed in Sections 7.1.2.7 and 7.1.2.17. Test E intervals and their bases are included in the Technical Specifications Section 16.3/4.3.1. A complete channel can be tested without causing a reactor trip and without affecting system operability. Overlap in the RPS channel tests is provided to assure that the entire channel is functional. The testing scheme is discussed in detail in 7.2.1.1.9, " Testing". Amendment E 7.7-52 Decer.Lar 30, 1988 L
CESSAR ME"icamn i O Since operation of the RPS will be infrequent, the system is periodically and routinely tested to verify its operability. . A complete channel can be individually tested without initiating a reactor trip, without violating the single failure criterion, and without inhibiting the operation of the system. The system can be checked from the uensor signal through the circuit breakers of the RTSS. The RPS can be tested during reactor operation. The sencora can be checked by comparison with similar channels or channels that involve related information. Minimum frequencies for checks, calibration, and testing of the RPS instrumentation are given in technical specifications. Overlap in the checking and testing is provided to assure that the entire channel is functional. The use of ground detection at the supply bus, E assures that grounde will be detected. 7.2.2.4 Eailure Modes and Effects Analysis (FMEA) A FMEA for the RPS and ESFAS is provided in Table 7.2-5. The FMEA is for protection systems' sensors, and coincidence and actuating logics. The FMEA was prepared assuming that one set of the redundant channels is bypassed for maintenance. The logic interface for the protection systems is shown on Figure 7.2-19. E 7.2.3 REACTOR PROTECTIVE SYSTEM INTERFACES The interfaces discussed below are specific to the RPS. General interface requirements are discussed in Section 7.1.3. 7.2.3.1 Power Vital instrument power interfaces are discussed in Section 8.3.1. 7.2.3.2 Protection From Natural Phenomena Refer to Section 3.1.2. Class 1E equipment is located so as to be provided with the maximum protection from natural phenomena which are site-specific. E 7.2.3.3 Protection From_ Pipe Failure Refer to Section 7.1.'3.3. 7.2.3.4 Missiles l l Refer to Section 7.1.3.4. Amendment E 7.2-53 December 30, 1988
CESSARELba O i 7.2.3.5 geparation Refer to Section 7.1.3.5. Preamplifiers for the fission chambers shall be mounted outside the containment building., The preamplifiers and cabling shall be provided with physical and electrical separation. 7.2.3.6 IndepSnd_eyce Refer to Section 7.1.3.6. 7.2.3.7 Thermal Limi_tations Refer to Section 7.1.3.7. 7.2.3.8 Monitorina Refer to Section 7.1.3.8. 7.2.3.9 operational / Controls Administrative procedures or other suitable means are used to control changes to CPC constants, adjustments to variable setpoints, and the bypassing of channels which could affect 1 operation. 7.2.3.10 Inspection and Testino Refer to Section 7.1.3.10. 7.2.3.11 Rhomist_ry/ Sampling Refer to Section 7.1.3.11. 7.2.3.12 Materials Not applicable. 7.2.3.13 System Component Arrangement Refer to Section 7.1.3.13. The separation, independence, etc., i criteria specified in Section 7.2.2.3.2 are adhered to. l 7.2.3.14 Radiological Waste l Refer to Section 7.1.3.14. O 7.2-54
CESSAR ilShma O 4 7.2.3.15 OveJoressure Protection Refer to Section 7.1.3.15. i 7.2.3.16 Related, Services Refer to Section 7.1.3.16. 7.2.3.17 Environmental Refer to Section 7.1.2.5. 7.2.3.18 Mechanical Interaction Refer to Section 7.1.2.8. 7.2.4 AUXILIARY PROTECTION SYSTEM The Auxiliary Protection System (APS) augments reactor protection E by utilizing a separate and diverse trip logic from the Reactor Protective System '(RPS) for initiation of reactor trip. The addition of the APS provides a simple, reliable, yet diverse i mechanism which is designed to increase the reliability of initiating reactor trip, as described in Section 7.7. t I O Amendment E 7.2-55 December 30, 1988 E-______________-_____ _ _ _ _ _ _ _ _
CESSAR EEnncui:u O REFERREQE8 FOR SECTION 7.2
- 1. " Functional Design Requirement for CPC," Combustion Engineering, Inc., CEN-305-P; Revision 2-P, May 1988.
- 2. " Functional Design Requirement for CEAC," Combustion Engineering, Inc., CEN-304-P, Revision 2-P, May 1988.
- 3. " Assessment of the Accuracy of PWR Safety System Actuation as Performed by the Core Protection Calculator (CPC),"
Combustion Engineering, Inc., CENPD-170, July 1975, and E Supplement 1, November 1975. O I l i 1 1 O Amendment E 7.2-56 December 30, 1988
y l e nyem onbi a t r w o r gp e e ort e w nu l o .n w s o it l f po o e p rr a. i p t ua l rt o w dt set a w N o s kn - o l d cned l .
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CESSAR Ensinc m. i O TABLE 7.2-2 REACTOR PROTECTIVE SYSTEM MONITORED PLANT VARIABLE RANGES Nominal Monitored Variable Minimum (full Dower) Maximum , Neutron flux power, % lx10-7 100 200 of full power l Cold leg temperature, 'F 465 558 615 Hot leg temperature, *f 525 615 675 Pressurizer Pressure 1,500 2,250 2,500 (high range), psia Pressurizer pressure 0 (c) 1,600 (low range), psia CEA positions full in NA full out . ( Reactor coolant pump 100 1,188 1,200 speed, rpm 0 82 100 l Steam generator water (a) level (wide range), % l Steam generator water 0 55 100 level (narrow range), %(b) E Steam generator pressure, 0 1,070 1,524 psia , Containment pressure, psig -5 0 60 Steam generator primary 0 43 47 ; pressure differential, psid i l HbilS: a. % of the distance between the wide range level instrument nozzles (above the lower nozzle),
- b. % of the distance between the narrow range ~ instrument nozzles (above the lower nozzle),
i- c. The high and low pressurizer pressure sensor ranges are combined electronically within the PPS bistable for wide range e applications. s l % Amendment E December 30, 1988
CESSAR neificari:. O TABLE 7.2-3 REACTOR PROTECTIVE SYSTEM SENSORS Number of Monitored Variable Type Sensors location Neutron flux power fission chamber 12(b) Biological shield Cold leg temperature Precision RTD 8(b) Cold leg piping l Hot leg temperature Precision RTD 8(U) Hot leg piping Pressurizer pressure Pressure transducer _ 4(a)(b) Pressurizer (high range) Pressurizer pressure Pressure transducer 4(b) Pressurizer-(low range) CEA positions Reed switch assemblies 2/CEA(b) Control Element Drive Mechanism Reactor coolant Proximity device 4/p' imp (D) Reactor cool' ant pump pump speed E l Steam generator Differential pressure 8/ steam level transducer generator (a)(c) Steam generators Steam generator Pressure transducer 4/ steam pressure generator (a)(b) Steam generators Containment pressure Pressure transducer 4(a) Containment structure Steam generator Differential pressure 4/ steam Steam generators l i primary differential transducer generator pressure R6fES: a. Common with Engineered Safety Feature Actuation System.
- b. Common with control systems,
- c. Only narrow range common with control systems. g O I 1
Amendment E December 30, 1988 j L__-_______________________ _ _ _ _ _ _ _ _ _ . . _ _ _
'CESSARin hia O
TABLE 7.2-4 REACTOR PROTECTIVE SYSTEM DESIGN INPUTS i Nominal Value Nominal Nominal Margin ' Type full Dower TriD Setooint .TYDe(i) to Trio High logarithmic power level NA 1% power F NA Variable Overpower (Ex-core) 100% power 125% power 25% power 0%/ min RLVSP 10%/ min NA 10%/ min (f) 15% band NA' Low DNBR 1.79(a) .;t 1.19 F $ 0.60 i (Low Pressure floor, psia) (2,250) (1,750) (500) High local power density, s 14.2 (peak) 21 F E 6.8- q kW/ft High pressurizer pressure, 2,250 2425 F 175 Lo ressurizer pressure, psia 2,250 17 c)(e) VSP 550 Low steam g erator water 82 45 RLVSPD 37 level, % Low steam generator 1070 870(c) VSP 200 l pressure, psia E psig (J
"High steam g nerator water55 94 F- 39 level, &
Low reactor coolant flow % 100% (g) RLVSP (g) i Calculated value of DNBR assures trip conservatively considering all sensor and a. processing time delays and inaccuracies. Calculated DNBR will be less than or equal to actual core DNBR.
- b. % of the distance between the wide range level instrument nozzles above the l lower nozzle,
- c. Setpoint can be manually decreased to a fixed increment below existing pressure as pressure is reduced during controlled plant cooldown and is automatically l increased as presscre is increased maintaining a fixed increment. This fixed increment is 400 psia for pressurizer pressure and 200 psia for steam generator pressure. !
- d. % of the distance between the narrow range level instrument nozzles above the !
lower nozzle.
- e. Trip setpoint has a minimum value of 300 psia,
- f. % band is percent above measured excore power . level.
- g. Actual differential pressure values are field determined, during calibration, using fractional setpoints that include all required uncertainty components.
- h. . The nominal setpoint is a variable setpoint programmed as a function of reactor power. The trip setpoint has a minimum value.
- i. Type of setpoint generation; F-fixed, VSP = variable based on trip process with reset; RLVSP-rate limited variable based on trip process; RLVSPD= rate limited E Os variable based on process diverse from trip.
i Amendment E December 30, 1988 l
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\s Amendment E December 30,1988 Jgg DNBRILPD CALCULATOR SYSTEM (CEA CALCULATORS)
SAFETY CHANNELS A B C O 1 1 1 1 FISSION 2 2 2 2 CHAMBERS (3 SECTIONS 3 3 3 3 PER CHANNEL) CONTAINMENT l PRE- PRE- PRE- PRE-AMP AMP AMP AMP l HV HV HV HV POWER POWER POWER POWER SUPPLY SUPPLY SUPPLY SUPPLY LOG LOG LOG LOG POWER POWER POWER POWER (vh RATE RATE RATE RATE l LINEAR LINEAR LINEAR LINEAR POWER POWER POWER POWER TEST TEST TEST TEST CIRCUITS CIRCUITS CIRCUITS CIRCUITS U U U U TO PLAN 7 PROTECTIVE SYSTEM l 1 X 10'7TO 200% FULL POWER l CALMA FILE: i t.CLGONYNOR)SYS80 FIG 725 ! []
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,5 ,- Amendment E II December 30,1988 ggg f STEAM GENERATOR PRIMARY D/P MCBD
CESSAR EHL"icaris. O 7.5 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM 7.
3.1 DESCRIPTION
The safety-related instrumentation and controls of the Engineered Safety Feature Systems (ESF Systems) are those of the Engineered Safety Features Actuation System (ESFAS). The safety-related instrumentation and controls consist of the electrical and mechanical devices and circuitry, from sensors to actuation device input terminals, involved in generating those signals that actuate the required ESF Systems. The ESFAS includes sensors to monitor selected generating station variables. The following actuation signals are generated by the ESFAS when the monitored variable reaches the levels that are indicative.of conditions which require protective action: A. Containment Isolation Actuation Signal (CIAS) B. Containment Spray Actuation Signal (CSAS) C. Main Steam Isolation Signal (MSIS) ft o D. Safety Injection Actuation Signal (SIAS) E E. Emergency Feedwater Actuation Signal (EFAS) The ESF System actuation device circuitry receives actuation signals from the ESFAS or the operator. The ESFAS signals { actuate the ESF Systems equipment. The control' circuitry for the 1 components provides sequencing necessary to provide proper ESF l Systems operation. I The Engineered Safety Feature - Component Control System (ESF-CCS) provides normal control of safety-related plant components, as well as control and actuation of Engineered Safety Feature systems. It is the central controlling system for safety-related plant components. Such components include breaker i and relay operated components (e.g., pumps, fans, heaters and motor operated valves), and solenoid operated components (e.g., pneumatic, electro-pneumatic and direct operated valves). E The Engineered Safety Feature System components are controlled by the ESF-CCS during normal plant operation, and automatically actuated upon receipt of ESFAS initiation signals from the Plant Protection System (PPS). l l l
%d Amendment E 7.3-1 December 30, 1988
CESSAR ME"icari:n 1 i O 7.3.1.1 System Description The actuation system consists of the sensors, logic, and , actuation circuits which monitor selected plant parameters and l provide an actuating signal to each actuated component in the ESF System required to be actuated, if the selected plant parameters reach predetermined setpoints. ESF System functions are distributed among various actuatic- systems. Each actuation E system is identical except that specific inputs and logic (and blocks, where provided) vary from system to system and the actuated devices are different. The overall logic is shown in Figures 7.3-la through 7.3-1d. i f Within the PPS, the Local Coincidence Logic (LCL) is like that shown on Figure 7.2-1. The LCL provides the full two-out-of-four coincidence. Each Local Coinc2dence Logic operates Initiation Logic which controls the initiation relays. The outputs of the initiation relays are directed to the selective two-out-of-four logic in the ESF-CCS where they are logically combined for the given function as shown on Figure 7.3-2. E A. ESF-CCS Configuration Each cabinet contains the logic for ESF train A, train B, train C, and train D equipment (refer to Figure 7.3-3). Each ESF-CCS train is similar, therefore only ! ESF-CCS train A is described. The ESF-CCS train contains mult 'o subsystems (Al through An). Each subsystem consists of processor pair, local and remote multiplexer, and communications interfaces. Several levels of redundancy are provided in each subsystem to ! enhance reliability. Primary and standby processors function cuch that the primary unit actively performs the control functions while the standby unit passively follows (tracks) the actions of the primary unit. Primary and standby processor performance is continuously monitored by a redundancy controller. Control tasks are automatically transferred to the standby unit upon detection of a primary I unit failure and confirmation of standby unit operability. l Local and remote multiplexing is incorporated in the ESF-CCS to reduce and simplify plant wiring. Remote multiplexer are physically located in the main control panels (MCP), the remote shutdown panel (RSP) and ESF-CCS remote multiplexer i cabinets which are located near plant component and l instrumentation interface locations. Fiber-optic cable { provides electrical isolation where required to meet channel ] O( Amendment E ! 7.3-2 December 30, 1988
CESSAR nainemon O independence provisions of IEEE Std. 279-1971. Subsystem multiplexer networks utilize active redundant cabling to maintain multiplexer operability under single cable fault conditions. Exchange of data between each subsystem within an ESF-CCS train is provided by an intratrain communication network. This network utilizes active redundant cables to maintain communication between subsystems under single cable fau.lt conditions. Control hardware failures are annunciated, and modularity is utilized to minimize mean-time-to-repair (MTTR). I Hardware reliability is enhanced by the use of redundancy, modularity, local and remote multiplexing and prudent distribution of power within each ESF-CCS train. These functional distribution practices and ESF-CCS subsystem equipment redundancy provides a " defense-in-depth" approach resulting in a high degree of ESF-CCS reliability. The ESF-CCS is a multiple microprocessor based system. The O ESF-CCS software is developed and tested in accordance with Regulatory Guide 1.152 as described in Section 7.1.2. B. ESF-CCS Logic E In addition to the system level selective two-out-of-four logic for ESF actuation, the ESF-CCS also provides Subgroup Control Logic (SCL) , Component Control Logic (CCL), Selective Group Test Logic (SGT), and Diesel Loading Sequencer (DLS) Logic. DLS logic is described in Section 7.3.1.1.2.3 and SGT logic is described in Section 7.3.1.1.8.6. SCL performs supervisory control of subgroups of components. The CCS also provides Master Transfer Switching (MTS) to disable all Main Control Room controls and enable Remote Shutdown Panel controls. Upon MTS, components are preprogrammed to remain as-is or to go to a predetermined state (e.g., safe shutdown lineup). CCL is the component level logic that monitors the various digital inputs, such as manual on-off demands, interlocks, and automatic subgroup control signals from the McL, and produces digital output signals to control the component (i.e., START /STOP, ON/OFF) through power level interface devices. This logic also generates digital outputs for O status indication. Amendment E 7.3-3 December 30, 1988
CESSAR En@icari:n O C. ESF-CCS Operator Interfaces Operator control functions are performed from the Main Control Panels (MCP), Remote Shutdown Panel (RSP), or from Local Control Switches (LCS). Automatic and manual component control and status indication is provided in the MCR by backlighted momentary pushbutton switches. A description of switch operation and component ; status indication is provided in Section 18.7.1.6, and the ! typical electrical interface for these devices is shown in Figure 7.3-4. These devices interface with the ESF-CCS through remote multiplexer located in the MCPS. A remote ESF-CCS operators module is also provided in the main control room for backup in the event of switch or multiplexer failure. This panel provides component control ' through menu selection using a qualified video display unit. Backlighted momentary pushbutton switches are also provided for the RSP controls identified in Table 7.4-1 to permit control of components required to achieve hot standby conditions when the main control room is uninhabitable. These devices also interface to the ESF-CCS through remote multiplexer located in the RSP. A remote ESF-CCS operators module is provided at the RSP for backup of control switch or multiplexer failure. This remote operators module also provides for control of all CCS components including components necessary to achieve cold shutdown as identified in Table 7.4-2. Transfer of control from the main control room to the RSP is performed by Master Transfer Switches (MTS) located on each ESF-CCS equipment cabinet. ! Fiber-optic cable is used to prevent fault propagation to the ESF-CCS from the main control room or the RSP. l As a " defense-in-depth" measure, Local Control Switches E (LCS) are provided independent from the CCS for components essential to hot shutdown. Only manual control (i.e., ON/OFF, START /STOP, OPEN/CLOSE) is provided through :LCS. LCS are field-wired for direct control of components or motor control center component actuators and are field , located near actuated components in locations such as the ' motor control centers. The LCS may also be used for test and maintenance. O Amendment E 7.3-4 December 30, 1988 L______
CESSAR1HL m, I O V i i Maintenance and test panels are included in ESF-CCS equipment cabinets. This operator interface provides indications for ESF-CCS equipment status and is used for ESF-CCS maintenance, test and diagnostics. The panels-include the MTS for RSP transfer. ESF functions are assigned to individual ' subsystems within each ESF-CCS train (refer to Figure 7.3-3). (For example: _ Consider _ the Safety Injection System (SIS), Containment l Spray System (CSS), Emergency Feedwater System 1 (EFW-1) and ) Emergency Feedwater System 2 (EFW-2) related to steam j generators 1 and. 2, .respectively. SIS and EFW-1 are assigned to ESF--CCS Subsystem 1. CSS and EFW-2 are assigned to Subsystem 2, and so forth). This functional assignment approach limits the effect of a single subsystem failure to i selected ESF functions in a given train. Additional segmentation of functional assignment is applied within each ESF-CCS subsystem. (For example: SIS and EFW-1 components and instrumentation are assigned to separate multiplexer and initiation signals (SIAS and EFAS-1) are assigned to separate input modules within a multiplexer). These practices limit the effect _ of single multiplexer or O module failure to selected ESF functions in the train. system interfaces are also confined within subsystems to minimize reliance on the Intratrain Communication Network ESF for ESF operability. (For example: SIAS initiation signals and SIS component and instrumentation interfaces are confined to Subsystem 1.) Failure of the Intratrain E Communication Network, therefore, will not effect SIS operation. i 7.3.1.1.1 ESFAS Measurement Channels Process measurement channels, similar to those described in Section 7.2.1.1.2.1 are utilized to perform continuous monitoring of each selected generating station variable, provide indication . of operational availability of each sensor to the operator, and I transmit analog signals to bistables within the ESFAS initiating ] logie. All protective parameters are measured with four 1 independent process instrument channels. 1 A typ;ca1 .easurement
' channel is shown in Figure 7.2-4. It consiste of a sensor / transmitter, current loop resistors, loop / power suppty, fiber-cptic isolated outputs for the process control bietems, DPS and DIAS. The DPS and DIAS receive digitized inbrnatJon over data links which are not part of the E process measuremer.e loop.
l l 1 Amendment E l 7.3-5 December 30,'1988 ; l L .--__--__-_-_-____-__.__.-__.m.i.__________m_ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _
CESSAREH L a l O!1 Each measurement channel is separated from other like measure acnt channels to provide physical and electrical separation of the signals to the ESFAS coincidence logic. Cabling is separated E within the cabinets and signals to non-1E systems are isolated. Each channel is supplied from a separate 120 volt vital AC distribution bus. 7.3.1.1.2 Logic 7.3.1.1.2.1 ESFAS Bistable and Coincidence Logic i The ESFAS Bistable Logic co.:.pa res the analog signal from the E sensors with predetermined fixed or variable setpoints (see Figure 7.2-12). If the input signal exceeds the setpoint the bistable produces trip signals which are transmitted to the Local Coincidence Logics (LCLs). The setpoint values are controlled administratively and automatically monitored continuously. The fixed setpoints are adjusted at the PPS cabinet. Access for setpoint adjustment is limited by keylcck with access annunciated by DIAS. The bistable setpoints are capable of being displayed at the PPS cabinet and E DPS CRT displays in the main control room. Some setpoints are externally variable to avoid inadvertent initiation during normal operations such as startup, shutdown, cooldown, and evolutions such as low power testing. The steam generator and pressurizer pressure setpoints can be manually decreased by the operator and will automatically increase as pressure increases. The bistable trip signals are directed to the LCLs (refer to Figure 7.3-16) in all channels such that full two-out-of-four coincidence is provided for each channel. The outputs of the LOLs control the initiation relays which send signals to the Actuation Logic in each ESF-CCS train cabinet. Besides the automatic actuation of the initiation logic by the LCL, the initiation relays can be tripped by remote manual switches. All ESFASs can be manually initiated by the operator from the control room in accordance with procedures. Following initiation, each ESFAS, including latched portions of EFAS, must be manually reset to restore the initiction logic to the E non-actuated state. . l 7.3.1.1.2.2 Actuation Logic The ESFAS actuation and component control logics are physically located in four independent and geographically separate ESF-CCS cabinets. O Amendment E 7.3-6 December 30, 1988 _-__-_-________O
CESSAR1lnh mn O The four initiation circuits in the PPS actuate a selective two-out-of-four logic in the ESF-CCS. In the actuation logic E (refer'to Figure 7.3-2), each signal also setu a latch when the selective two-out-of-four logic actuates to assure that the signal is not automatically reset once it has been initiated. Receipt of two selective ESFAS initiation channel signals will generate the actuation channel signals. This is done l independently in each ESF-CCS cabinet, generating train A and E train B and where required, train C, and train D signals. .The l group component control logic is used to actuate the individual ESF components which are actuated to mitigate the consequences of the occurrence that caused the ESFAS. 7.3.1.1.2.2.1 Component Control Logic This section describes the control logic designs for the five basic types of components to be controlled by the ESF-CCS. A. Solenoid-Operated Valves B. Motor-Operated Valves C. Contactor-Operated Components E D. Circuit Breaker-Operated Components E. Modulating Components 7.3.1.1.2.2.1.1 Solenoid-Operated Valves 7.3.1.1.2.2.1.1.1 Two-State Solenoid Valve Control The CCS executes the control logic necessary to energize the solenoid, as a function of the open/ closed state to which the energized solenoid corresponds (i.e., energize to open valve or energize to close valve). In general, there is one solenoid for direct operating electro-hydraulic . or electro-pneumatic valve l types. Figure 7.3-8a is a typical Functional Control Logic Diagram (FCLD) that depicts the control design for a solenoid-i operated valve. Figure 7.3-8b depicts the generic electrical interface design for a solenoid-operated valve. For valves that i have multiple solenoids with various energize /deenergize l sequencing requirements thet apply to different operating or test l modes, the generic control logic design and electrical interface design is modified appropriately. The following signals are utilized in the control logic: Amendment E 7.3-7 December 30, 1988
~ j l CESSAR nrince l 9Ii I A. Position Status The control logic utilizes "not full open" (NFO) and "nct full closed" (NFC) position signals. These signals'are from j direct indicating limit switches on the process control 1 valve. These signals are used primarily for status indication and interlocking with other components. B. Component Inoperable The "INOP" signal indicates loss of control or motive power at the source or loss of power due to operation of power disconnect switches or any fault protecting devices. In general, the signal is used to reset and prevent setting ; 1 latches in the control logic to ensure that the valve remains in its failure position upon restoration of power. l It is also used to generate inoperable status indication. ; I The "INOP" signal, when used to reset component control logic following a loss of motive or control power, is delayed momentarily to prevent normal switching transients or momentary losses of power from unnecessarily resetting component logic. 7.3.1.1.2.2.1.1.2 Modulating Valves With Solenoid Operators E These are solenoid-operated valves that have electro-pneumatic modulators to allow continuous valve positioning. Figure 7.3-9a is a typical FCLD depicting the generic control design for a modulating valve with a solenoid operator. Figure 7.3-9b depicts the generic electrical interface design. j The following signals are utilized in the control logic in addition to those identified in Section 7.3.1.1.2.2.1.1.1: A. Solenoid Energized , This signal is used for a status light to indicate the energized state of the solenoid. This signal is derived from a limit switch on the solenoid itself. Where this is not available, the signal is derived from a logic element that is representative of solenoid energizaticn. B. Analog Position Continuous valve position indication is provided, where required for human factor engineering reasons (Chapter 18). i i The control design for modulating valves and other modulated components without discrete state operators are discussed in Section 7.3.1.1.2.2.1.5. 1 Amendment E 7.3-8 December 30, 1988 i
CESSARnnince V 7.3.1.1.2.2.1.2 Motor-Operated Valves This section describes the control logic for motor-operated valves (MOVs) that use reversing motor contactors. The CCS , executes the control logic necessary to energize the open and I close contactors. l 7.3.1.1.2.2.1.2.1 Interface Signals Interlocking of the open/close contactors, electrical fault and/or thermal overload protection, and interlocking with limit and torque switches are wired external to the CCS control logic. These are not shown on the FCLDs. Figure 7.3-10a depicts a 1 typical MOV functional interface design. Figure 7.3-10b shows the generic electrical interface design for a motor-operated valve. These figures show the signals that the CCS uses in the control logic. The interface signals are described as follows: A. Component Inoperable The "INOP" signal is the same as that described in Section 7.3.1.1.2.2.1.1.1 and is used for the same purpose. For e MOVs, this signal indicates loss of either motive or control E power. For MOVs, the fault protection that initiates this signal includes thermal overload devices. This signal is generated from voltage monitoring relays within the motor control ce;.ter. The "INOP" signal is delayed momentarily when used to reset component control logic to prevent normal switching transients or momentary losses of power from unnecessarily resetting component logic. B. Contactor Deenergized This signal indicates that the valve motor contactor is deenergized. It is generated from a series combination of the contactor's open and close contacts. This cignal is used to reset latches in the control logic at the end of l valve travel and any time the valve motor is deenergized. These features ensure that the CCS output contacts are j opened after valve travel is stopped, preventing adverse interaction with non-CCS controls (i.e., local control l switches). O b Amendment E 7.3-9 December 30, 1988
CESSAR Knem I O C. Position Status These signals are the same as those for solenoid valves (see Section 7.3.1.1.2.2.1.1.1). All MOVs have discrete state position indicators. Throttling MOVs also have continuous position indication if required for human factors engineering reasons. 7.3.1.1.2.2.1.2.2 Throttling and Full Throw Designs The CCS provides full throw or throttling (or jogging) valve control. Full throw valves are actuated by signals that are latched in the control circuit such that valve travel will continue even if the initiating control signal is removed. All full throw MOVs can be reversed in mid-travel by removal of the initiating control signal and application of a control signal for travel in the opposite direction. Figure 7.3-11 is a typical FCLD depicting the generic design of a full throw motor-operated valve. Throttling MOVs stop traveling when the operator initiated control signal is removed. As such they can be positioned by the operator anywhere from 0-100%. Where throttling MOVs are also controlled by automatic actuation signals, the control response to the automatic signal is always full-throw. Figure 7.3-12 is a typical FCLD depicting the generic design of a throttling motor-operated valve. E 7.3.1.1.2.2.1.2.3 Tcarmal Overload Monitoring The application of thermal overload protection devices in Class 1E motor-operated valve circuits is in compliance with Regulatory , Guide 1.106. Thermal overload protection devices are not used in ' safety-related motor-operated valve circuit. Thermal overload devices are used to provide alarm functions. Figure 7.3-17 l provides a simplified schematic of this design. 7.3.1.1.2.2.1.3 Contactor-Operated Components A typical FCLD depicting the generic control design for a contactor-operated component is depicted in Figure 7.3-13a. The generic electrical interface design is shown in Figure 7.3-13b. The CCS provides the control logic necessary to energize the contactor. Designs for electrical fault and/or thermal overload protection are wired external to the CCS. The interface signals are described as follows: Amendment E 7.3-10 December 30, 1988 _ _ h
CESSARUNnc=w A A. Component Inoperable The "INOP" signal is used for the same purpose as that for the motor-operated valves (see Section 7.3.1.1.2.2.1.2.1). B. Status The CCS obtains the component status signals (i.e., on/off) from the contactor's "a" and "b" auxiliary contacts. These signals are used for status indication and interlocking. 7.3.1.1.2.2.1.4 Circuit Breaker-Operated Components Circuit breakers are used to control most loads requiring voltage greater than 480V AC. Figure 7.3-14a is a typical FCLD depicting the generic control logic necessary to energize the breaker's closing circuit and energize the breaker's trip circuit. The generic design of the electrical interfaces to the closing and trip circuits is shown in Figure 7.3-14b. Electrical fault j protection interfaces and rack-out or test position interlocks I are wired external to the CCS. The following status signals are I used in the electrical portion of the design: ] A. On This signal indicates that the breaker is closed based on the breaker position status contact. The signal is used primarily for status indication. B. Off This signal indicates that the breaker is open based on the E l breaker position status contact. The signal is used primarily for status indication. C. Component Inoperable The "INOP" signal indicates loss of control power to the breaker closing circuit, that the breaker is in an inoperable position (e.g., racked out), or the loss of motive power to the component. The signal is used for status indication and to reset the component control logic. The "1NOP" signal has a momentary time delay to prevent normal switching transients or momentary losses of power from unnecessarily resetting component logic, b O Amendment E 7.3-11 December 30, 1988
i CESSARE!na m O D. Trip Circuit Failure This signal indicates loss of power to the breaker trip circuit or a malfunction in the trip circuit that could prevent the breaker from opening. Malfunctions are detected by current sensing continuity monitoring of the trip coil. l This signal is used primarily for status indication. 7.3.1.1.2.2.1.5 Modulating Components A typical FCLD showing the generic design for a modulating component is depicted on Figure 7.3-15a. The generic electrical design is shown in Figure 7.3-15b. These types of devices include electro-pneumatic (E/P) and electro-hydraulic (E/H) actuated components (pumps or valves) that require only analog signal inputs for continuous control (i.e., no discrete state I controls from pilot solenoids). The following signals are interfaced to the CCS from the component: A. Status
- 1. Valve position:
- a. Not full closed (NFC).
- b. Not full open (NFO).
- c. Analog valve position, where required, based on E j human factors engineering considerations. !
- 2. Pumps:
- a. On.
- b. Off.
- c. Turbine speed.
B. Component Inoperable This signal indicates loss of motive power which renders the component inoperable. The signal is used primarily for status indication. The "INOP" signal, when used to reset component control logic following a loss of motive or control power, is delayed momentarily to prevent normal switching transients or momentary losses of power from unnecessarily resetting component logic. I Amendment E 7.3-12 December 30, 1988
CESSAR EnWicari:n O 7.3.1.1.2.2.2 Group Actuation i Actuation signals, generated by the selective two-out-of-four logic in the ESF-CCS, are directed to actuate groups of ESF l system components required by the ESFAS function. These i components generally consist of solenoid-operated valves, motor-operated valves or motors of pumps. Figures 7.3-8a, 7.3-11 and 7.3-14a show typical ESFAS interlocks in the functional control logic for override of each of these components. Valves and pumps, related to a specific engineered safeguard function, are . grouped within an ESF-CCS train, as shown in Figure 7.3-7, such { that the required component groups. are actuated by the l I appropriate logic. The actual ESFAS' interface exists in the component control logic for each component. 7.3.1.1.2.3 CCB - Diesel Loading Sequencer 1 Diesel generators as described in Section 8.3.1.1.4 are utilized in the System 80+ design as a source of backup electrical power ; to ensure availability of the plant's safety systems. Due to the E large power requirements imposed on the diesel generators, there exists a need to sequentially load them. The System 80+ plant ,, equipment is arranged into several load groups. Load groups are ( energized one at a time by the CCS Diesel Loading Sequencer, thus avoiding instantaneous overloading of the diesel generator. Equipment is energized es quickly as possible to minimize the overall plant disturbance. The Diesel Loading Sequencer is designed assuming plant accidents occur prior to, concurrent with, or any time after the initial LOOP or blackout has occurred. The ESF equipment required in the event of a design basis accident is energized within a i i pre-determined time after the accident has occurred to maintain the plant within its design limits. The equipment required depends on the specific accident. Several load groups of eqe ipment may be needed if multiple ESF systems are needed to accommodate the accident. To minimize diesel generator size and eliminate unnecessary equipment cycling, but still meet concerns of plant safety, the CCS Diesel Load Sequencer design ensures one group at a time loading but has the intelligence to vary the loading sequence in response to changing plant conditions (i.e., initiation of ESF systems). If an ESF system is actuated, the non-accident load sequence is interrupted to load the appropriate ESF system (s). If an accident does not occur, energizing of non-accident equipment is not delayed unnecessarily, since the sequence does ,
, not progress through the steps for the unused accident equipment. l The sequencer is fully testable during on-line plant operation.
[V t I Amendment E 7.3-13 December 30, 1988
CESSARannnc-O Figures 7.3-5 and 7.3-6 are simplified diag *ams of the CCS - Diesel Loading Sequencer (DLS). Figure 7.3-5 depicts the sequencer operation. The DLS consist of the following sections: l A. Sequence Initiation Logic l The Initiation Logic monitors various plant electrical busses to determine when abnormal power conditions exist. When the right combinations of bus abnormalities are present, a Loss of Power signal sets all Sequencer Output Latches (eleven total) , generating Load Shed (Trip) signals i to the necessary plant equipment. A DG Auto Start signal is ! also transmitted to the diesel generator upon Loss of Power, {' SIAS, CSAS or EFAS. When the diesel is ready to accept the first load group (Diesel Ready signal) a DG Circuit Breaker Close signal is transmitted to connect the diesel generator to the plant bus. After the circuit breaker is closed successfully, (Breaker Closed signal) the equipment loading sequence begins. B. Loading Sequence Logic l The basis of the Loading Sequence Logic is a simple eight E step counter (additional steps are added, as necessary which j provides the sequencing control for all non-accident equipment). When the diesel generator breaker is closed the counter advances, one step at a time, with a constant time base interval between each step. The time base interval is determined by a clock pulse which is adjustable in distinct j digital increments. At each step of the counter, one Sequencer output Latch is reset, removing the Load Shed signal from that load group and re-energizing the required plant equipment. During non-accident plant conditions the counter will advance, uninterrupted, to reset eight output latches, re-energizing eight non-accident load groups. C. Priority Interrupt Logic Three priority load groups are designated to handle plant ESF equipment (additional load groups are added, as . necessary). The Priority .iterrupt Logic continuously l monitors ESF actuation signals from the Plant Protection i System. If an ESF actuation occurs, the clock pulse from the Load Sequence Logic (above) is re-directed from the step counter, to reset the Sequencer output Latch for the appropriate priority load group. Hence, the non-accident loading sequence is interrupted and the required ESF load l group is re-energized instead. The time base interval (between each sequence step) is always maintained by the l common clock pulse. l Amendment E 7.3-14 December 30, 1988
l l CESSAR 8P4biu l I
. l The non-accident loading sequence may be interrupted two or three times in the event that Multiple ESF Actuations occur at different times. A priority between ESF load groups is established such that if two or three ESF actuations occur during any one time base interval, the ESF load groups will be sequenced in two or three successive steps and in the established priority order. After the ESF load groups have been energized the non-accident sequence will resume (always maintaining the same time base interval).
The DLS provides the following features: A. Since all load groups are always energized one at a time, diesel. generator size can be minimized. B. Accident loads are always energized in the sequence step immediately following the accident occurrence. Thus, achieving the best availability possible, for accident equipment. C. Since sequence steps are not pre-assigned to accident equipment (which may or may not be needed) no sequence step is wasted. All equipment is enargized in the fastest time i possible. E D. Equipment is load shed one time only. Once a Class 1E Division load group is energized, that group is unaffected by the occurrence of an accident. See 8.3.1.1.4.6 for additional sequencing of permanent non-safety loads when the Alternate AC Source is not available, j E. The DLS testing features, defined in Section 7.3.1.1.8.9, allow complete system check-out while the plant remains on-line. F. When offsite power is lost at some time after the diesel generators are up to rated voltage and speed, and after the required ESF equipment is running following one or more . ESFAS, the following response time requirements are met:' l
- 1. Interrupted ECCS flow to the core can be fully reestablished within 20 seconds.
- 2. Interrupted emergency feedwater flow to the steam generator (s) can be fully reestablished within 20 seconds.
O Amendment E 7.3-15 December 30, 1988
(IEESiSiAlft E!aincanan i i O G. In the event that offsite power is unavailable and the diesel generators are not yet up to rated voltage and speed at the time that an ESFAS is generated, there can be a delay of up to 20 seconds before the diesel generator output E breakers close and power is supplied to the ESF buses. After the generators are supplying the ESF buses, the ESF loads which are appropriate in the particular ESFAS shall be automatically sequenced on. See Section 8.3, Table 8.3.1-4. 7.3.1.1.3 Bypasses E 7.3.1.1.3.1 Bistable Trip Channel Bypass Bypasses are provided, in the PPS, as shown in Table 7.3-1. The trip channel bypass is identical to the RPS trip channel bypass (Section 7.2.1.1.5) and is employed for maint( ance and testing of a channel. 7.3.1.1.3.2 Operating Bypass The low pressurizer pressure bypass as shown in Figure 7.3-la, is provided to allow plant depressurization without initiating protective actions when not desired. The bypass may be initiated manually in each protective channel. However, the bypass cannot be initiated if pressurizer pressure is greater than that shown in Table 7.3-1. Once the bypass is initiated, it is automatically removed when pressurizer pressure increases above the value shown in the table. 7.3.1.1.3.3 Bypasses and Inoperable Status E Auxiliary and supporting systems for the safety-related instrumentation and controls are designed to cause a system level j bypass indication when they are bypassed or deliberately made inoperable. The bypass indication is provided for the , safety-related system which is affected by the bypassing or deliberate inoperability of the auxiliary or supporting system. 7.3.1.1.4 Interlocks The Bistable Trip Channel Bypass Interlocks for ESFAS, located in lE l the PPS, prevent the operator from bypassing more than one trip , channel of a trip parameter at a time. Different trip parameters ! may be bypassed simultaneously, either in the same channel or in ; different channels. This function is shown in Figure 7.2-3. l l During PPS testing, additional interlocks are provided as E I i described in Section 7.2.1.1.6 to prevent disabling more than one redundant protection function at a time or to prevent maintenance ! I i W Amendment E f 7.3-16 December 30, 1988 I l
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CESSAREM&uiu o L] personnel from inadvertently causing unwarranted ESFAS signals. ESF-CCS component control interlocks are shown on the applicable E l component FCLDs. l l 7.3.1.1.5 Redundancy ! There are many redundant features within the ESFAS. There are four independent channels for each parameter from process sensor through and including the initiation circuits located in four PPS channels. Each ESF-CCS train controls one ESF System train, and there are four redundant ESF-CCS trains used to operate four (or two) totally redundant ESF trains. Where redundancy exists at the plant system level, component assignments to redundant ESF-CCS trains are made to maintain that level of design redundancy. E Redundant flow paths are orovided, such as the Safety Injection System, to ensure flow unoer single failure conditions. In this instance, components from each flow path are assigned to independent ESF-CCS trains to maintain flow path availability upon single failure within an ESF-CCS train (i.e., train A and B). In addition, a redundant flow path may contain two valves in [s S series, such as the Emergency Feedwater System or the Containment spray System, to preclude spurious flow path initiation upon single failures. In this instance, each valve is assigned to l 1 l D) e v Amendment E 7.3-16a December 30, 1988
i 1 l O 1 1 THIS PAGE INTENTIONALLY BLANK O. 4 i 1 l l O;
CESSAR !! alum O independent ESF-CCS trains such that a single failure within an ESF-CCS train will not cause spurious flow path initiation. Preventing spurious flow path initiation is accomplished while maintaining independence of redundant ESF flow paths. To achieve this, components in ESF system trains A and B are assigned to ESF-CCS trains C and D, respectively. Refer to mechanical E systems sections for component to train assignments. Overall, the entire ESFAS receives vital AC power from four separate buses and the power for control and operation of separate trains comes from separate buses. The result is a system which meets the single failure criterion and can be tested during operation. The PPS ESFAS can be shifted E to two-out-of-three logic, when a channel is removed for testing or maintenance without affecting system availability. The ESF-CCS utilizes redundant selective two-out-of-four E coincidence logic to actuate ESF components. 7.3.1.1.6 Diversity The system is designed to eliminate credible multiple channel 9 failures originating from a common cause. The failure modes of redundant channels and the conditions of operation that are common to them are analyzed to assure that a predictable common failure mode does not exist. The ESF-CCS is constructed from equipment which is diverse from the Plant Protection System and E the Process-CCS. The design provides assurance that the protective system cannot be made inoperable by the inadvertent actions of operating or maintenance personnel. The design is not encumbered with additional channels or components without reasonable assurance that such additions are beneficial. 7.3.1.1.7 Sequencing Component sequencing methods are discussed in Section , 7.3.1.1.2.3. Component sequencing requirements are provided in C Chader 8. 7.3.1.1.8 Testing Provisions are made to permit periodic testing of the complete ESFAS. These tests cover the trip actions from sensor input through the protection system and actuation devices. The system test does not interfere with the protective function of the system. Overlap between individual tests exists so that the G entire ESFAS can be tested. Amendment E 7.3-17 December 30, 1988
CESSAR EnMemon j l l O The testing system meets the criteria of IEEE Std. 338-1977, "IEEE Standard Criteria for the Periodic Testing of Nuclear Power Generating Station Class 1E Power and Protection Systems," and the intent of Regulatory Guide 1.22, " Periodic Testing of Protection System Actuator Functions." The frequency of testing is given in Technical Specifications Section 16.4.3.2. E 7.3.1.1.8.1 Sensor Checks During reactor operation, the measurement channels providing an input to the ESFAS are checked by the methods described in Section 7.2.1.1.9.1. E 7.3.1.1.8.2 Trip Bistable Test Testing of the ESFAS trip bistables, located in the PPS, is accomplished as described in Section 7.2.1.1.9.2. Testing of ESF-CCS bistable functions used for process control setpoints and interlocks is provided as follows. The DPS continuously monitors setpoints and provides alarms upon excessive setpoint deviations between channels. ESF-CCS bistable > trip accuracy and interlock performance is also periodically l verified during performance of the selective group testing ; described in Section 7.3.1.1.8.6. This is accomplished through manual perturbation of he digitized interlocking parameter from the remote operators' module in the main control room. Analog to digital conversion accuracy is also periodically verified at the remote operators' module during sensor testing. The overlap of testing defined above results in complete verification of ESF-CCS ! bistable trip accuracy and interlock performance, j l 7.3.1.1.8.3 Local Coincidence Logic Test ; l Testing of the ESPAS local coincidence logic, located in the PPS, is accomplished as described in Section 7.2.1.1.9.4. 7.3.1.1.8.4 Initiation Logic Tests l The initiation logic for each ESFAS is automatically tested by the PPS test function to determine its ability to generate an initiation signal. Testing begins by interrogation of status of the input signals to the logic and the state of the output. The ; test function determines what the output of the logic should be, ! based upon the input signals. Should there be a discrepancy ! between the actual output and the output determined by the test function, the test function will annunciate the discrepancy and Amendment E ! 7.3-18 December 30, 1988
CESSAR nai"lCATION t
\
provide a message to identify the error. If there is no discrepancy, testing of the ' logic continues. The additional testing that will be done is dependent upon the status of those inputs to the logic over which the test function has no control (e.g., . genuine coincidence signals). Based upon the known , inputs, the test function will generate all combinations of input ! I signals and monitor the output of.the logic for correctness. A l genuine coincidence signal or other genuine signal cannot be changed by the test function. j Testing of these functions is limited to one channel at a time to avoid the possibility of actuating any equipment during test. [ This testing is done in conjunction with the ESFAS initiation l i relay testing described below. The 'ESF-CCS actuation logic is a selective two-out-of-four circuit controlled by the outputs of the initiation relays from the four PPS channels. Since the initiation relays are within the control of the PPS, it is possible to test them automatically. Before the automatic test function applies any signals to the system, it determines the status of the initiation circuit outputs. It then makes a determination of what the y status of the actuation logic feedback signals should be. The " O actuation logic feedback signals, obtained from the actuation trains (refer to Figure 7.3-16), represent the state of the initiation relay outputs. If there is a difference between the q E actual output and the output that should exist, the condition is j both annunciated and a message is provided on demand. If l conditions are correct, the tesc system generates an initiation l signal which propagates through to the ESF actuation trains. The .; I test function monitors the ESF-CCS actuation logic circuit s feedback signals to determine proper operation. If a fault is ! l detected it is annunciated and a message is provided on demand. The initiation relay test is only performed in one PPS channel at a time. An interlock among the PPS channels ensures that only " one channel at a time can be tested. Additionally the interlock verifies that the opposite leg of the actuation circuit is not already enabled. This interlock provides assurance that testing cannot result in inadvertent actuation. 7.3.1.1.8.5 Actuating Logic Test The ESF-CCS actuation trains receive short duration initiation signals (test signals) from the PPS. These signals are processed in the ESF-CCS and returned to the PPS for detection of [ initiation signal failure or the loss of an actuation signal to a i subgroup (refer to Figures 7.3-7 and 7.3-16). Sequentially, the I O Amendment E 7.3-19 December 30, 1988 l _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _
2 I CESSAREMMema ! O PPS transmits short duration initiation signals, AA, CA, BA and DA, for each ESFAS signal. (Note, that for initiation signal designations, first character represents PPS originating channel, . and second character represents ESF-CCS destination train.) ! The PPS processes the returned test signal for both the presence of an actuation signal when there should be one, and the absence of an actuation signal when there should not be one. The absence of a desired actuation signal or the presence of an unwanted actuation signal is detected at the time an abnormal or failed condition occurs. When an actuation channel is manually actuated at the ESF-CCS (e.g. for latch testing), a discrepancy between the PPS initiation signals and the state of the actuation channel , is automatically detected. 7.3.1.1.8.6 Selective Group Test ESFAS selective group testing is performed by an operator in the main control room. This testing, as shown in Figure 7.3-7, overlaps the PPS automatic testing of the ESF-CCS selective two-out-of-four coincidence logic and includes complete testing of the ESFAS through to the actuation of the components. The components for each ESFAS are grouped. Testing is conducted one group at a time, thus preventing the complete undesired actuation of an ESF system during testing. Since this testing causes ccmponents to actuate, an ESFAS signal from the PPS will not be E impeded and the ESF system will proceed to full actuation. The operator, using a written procedure, performs the following actions when making a selective group test. A. Determines if the group test can be performed based on the plant conditions and lineup. B. Selects the component group to be tested. C. Depresses a test pushbutton, latching the test group selection and initiating a "Stop-and-Think" time delay. D. Places the test group components and other related components in a test lineup (via component control switches). E. A " Test Enabled" light will illuminate after the "Stop-and-Think" time delay. The operator then initiates the actuation of the group components to their ESFAS required state. F. Confirms that the group components have actuated to the ESFAS required state for the group being tested (via component control switch indicators). Amendment E 7.3-20 December 30, 1988
CESSAR 8HMemor I
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G. Places components back to their initial lineup via component control switches). The Stop-and-Think interlock is provided in the ESF-CCS. This feature enables the test actuation logic (Step E above) for a fixed period after the group to be tested is latched (Step C above). Each time a new group is selected the time ' delay is reset preventing further testing. The operator must re-initiate the delay for subsequent testing. The DPS CRT Displays can be used as an operational aid during the Selective Group Testing described above. l The operator may use the DPS to: A. Store the initial state (position) of each component in the test group prior to placing the components in a test lineup. E B. Confirm that the operator has place'1 the components in the correct test lineup. C. Confirm that the group components have actuated to the ESFAS required state for the group being tested. D. Confirm that the components have been returned to the initial state (position) after the test has been completed. This DPS application program is referred to as Computer Aided Testing (COMAT). The COMAT signals from the ESF-CCS are transmitted to the DPS via fiber-optic data link (refer to Figure j 7.3-3. The DPS is used to aid the operator in monitoring the i manual selective group testing. No interlock or control signals ! are transmitted from the DPS to the ESF-CCS. Selective group testing may be performed without COMAT therefore DPS availability is not required for performance of selective group testing. 7.3.1.1.8.7 Bypass Tests System bypasses in the PPS, as itemized in Table 7.3-1, are tested on a channel basis as described in Section 7.2.1.1.9.7. 7.3.1.1.8.8 Response Time Tests Required Response Time Tests for the ESFAS are identified in Technical Specifications Section 16.4.3.2. i 1 i a Amendment E 7.3-21 December.30, 1988 w__-______-____
CESSARnaincm2 O The design of the ESFAS is such that connections may be made for any of a variety of methods as described in Section 7.2.1.1.9.8 that may be used by the site operator. The hardware design includes test connections on instrument lines for pressure and differential pressure transmitters, and conveniently available test points. 7.3.1.1.8.9 Diesel Load Sequencer Tests l The DLS incorporates design features, shown in Figure 7.3-6, d which allow complete on-line testing. During normal operation I all output control signals are disabled, allowing all logic j functions to be tested without disturbing plant equipment. The j outputs become enabled automatically, anytime a valid Initiation ! Logic input signal is received. In this manner, testing may be { conducted without impeding proper Sequencer operation in the j event of an actual black-out condition. Three distinct test l phases are employed to assure maximum system reliability. ) A. Phase 1 - Automatic Testing l The Automatic Test Phase provides continuous cycling of the E j Loading Sequence Logic which consists of the sequence i counter, time base interval and all output latches. The i latches are sequentially set and reset by the counter at a I rate controlled by the time base interval. A failure of a l latch to operate in the correct sequence or within the l correct time is automatically detected at the time the ! failure occurs. Alarm output signals and front panel ! indicators are provided to diagnose the failure. B. Phase 2 - Input Testing All DLS external inputs are checked independent of Logic Testing. During this test actual Initiation Logic input signals are generated from the sensors. Front panel indicators allow verification that all signals are being communicated properly to the Initiation Logic. Since these signals are considered (by the DLS) to be valid inputs, the automatic output enabling logic, described above, is blocked during this testing. After completion of the test the block is removed. With the control outputs remaining blocked, the second phase of testing verifies power operation of the Loading Sequence Logic and the Priority Interrupt Logic. Front panel controls allow simulating all required inputs to initiate the non-accident sequence. Other controls permit introduction of simulated accident signals at any point in Amendment E 7.3-22 December 30, 1988
CESSAR 880lCAT13N l k the non-accident sequence. Any accident scenario may be simulated to verify that the correct loading sequence occurs. Front panel indicators display all Load Shed output signals. C. Phase 3 - Load Shed Testing The final test phase involves actual load shedding and re-energizing plant loads. Each load group is further sub-divided into test groups which may contain from one to all components in the Load Group. Load Shed signals ) are simulated aeparately for each test group in conjunction j with the CCS - Selective Group Testing. As for ESF Actuation testing, described in Section 7.3.1.1.8.6, the Computer Aided Test program (COMAT) in the DPS is used as an operator aid. The equipment is actually tripped and E re-energized, but since one group is tested at a time, the overall plant disturbance is minimal. 7.3.1.1.9 Vital Instrument Power Supply The vital instrument power supply requirements are discussed in p Section 7.1.3, and in Chapter 8. l E, U 7.3.1.1.10 Actuated Systems The ESF Systems are maintained in a standby mode during normal operations. Actuating signals, generated by the ESFAS are provided to assure that the ESF Systens provide the required l protective actions. The following descriptions of the instrumentation and controls of the ESF Systems is applicable to each ESF System. Table 7.3-2 presents the Design Basis Events J (DBE) which require specific ESF System action. Table 7.3-3 presents the monitored variables required for ESF System actuation. The variables and their ranges are shown on Table 7.3-6. 7.3.1.1.10.1 Containment Isolation System Section 6.2.4 contains a description of the Containment Isolation System. The actuation system is composed of redundant trains A i and B. The instrumentation and controls of the two trains are I physically and electrically separate and independent as discussed above such that the loss of one train will not impair the safety function. The Containment Isolation System instrumentation and controls are l designed for operation during all phases of plant operation. l However, the system is removed from service prior to containment l l l l Amendment E l 7.3-23 December 30, 1988 l
l CESSAR nainc-O leak checking at refueling intervals in order to prevent The removal from service is .I undesired system actuation. l accomplished in accordance with procedures prepared by the site operator. The containment Isolation System is automatically actuated by a CIAS from the ESFAS. ! 7.3.1.1.10.2 Containment Spray System to Section 6.5, " Containment Spray System," for a Refer description of the Containment Spray System (CSS). The CSS is actuated by a CSAS. The actuation system is composed of redundant trains A and B. E The instrumentation and controls of each train are physically and electrically separate and independent. Each train is a 100% capacity system, therefore, the CSS can sustain the loss of an entire train and still provide its required protective action. The CSS instrumentation and controls are designed to operate l under all plant conditions. The CSAS is removed from service prior to the containment leak , test at refueling intervals in order to prevent undesired system i actuation. The removal from service is accomplished in accordance with procedures prepared by the site operator. 7.3.1.1.10.3 Main Steam Isolation System Refer to Section 10.3, " Main Steam Supply System," for a description of the Main Steam Isolation System. Refer to Section 10.4.7, " Condensate and Feedwater System," for a description of the Main Feedwater Isolation System. Refer to Section 10.4.8,
" Steam Generator Blowdown System," for a description of the Blowdown Isolation System. Interface requirements for the Main Steam Isolation System are provided in Section 5.1.4.
l The actuation system is composed of redundant trains A and B. ! The instrumentation and controls of the valves in train A are j physically and electrically separate and independent of the 1 instrumentation and control of the valves of train B. The separation and independence are such that a failure of one train will not impair the protective action. The Main Steam Isolation Valves (MSIVs), MSIV Bypass Valves, Main E Feedwater Isolation Valves (MFIV) and the isolation valves for the blowdown lines are actuated by an MSIS. l These valves effectively isolate the steam generators from the rest of the main steam and feed systems. Amendment E 7.3-24 December 30, 1988 l
CESSAR nainema (( ' A variable steam generator pressure setpoint is implemented to allow controlled pressure reductions, such as shutdown depressurization, without initiating an MSIS. The pressure ! setpoint will track the pressure up until it reaches its normal ! setpoint value. l 7.3.1.1.10.4 Safety Injection System Refer to Section 6.3, " Safety Injection System," for a description of the Safety Injection System (SIS). The SIS is actuated by an SIAS. Interface requirements for the Safety Injection System are provided in Section 6.3.13. The actuation system is composed of redundant trains A, B, C and D. The instrumentation and controls of each train are physically and electrically separate and independent. Each train E is a 50% capacity system, therefore the SIS can sustain the loss of an entire train and still provide its required protective i action. The SIS instrumentation and controls are designed to ! operate under all plant conditions. The low pressurizer pressure setpoint can be decreased as described in Section 7.2.1.1.1.6 to avoid inadvertent operation during startup and shutdown. As pressurizer pressure increases, V the setpoint will follow up to its normal value. The SIAS is removed from service during containment leak checking at refueling intervals to prevent undesired system operation. The removal from service is accomplished in accordance with procedures prepared by the site operator. I 7.3.1.1.10.5 Emergency Feedwater System [ E Refer to Section 10.4.9, " Emergency Feedwater System," for a description of the Emergency Feedwater System (EFWS). The EFWS is actuated by an EFAS-1 for Steam Generator 1 and an EFAS-2 for Steam Generator 2. The EFWS is also actuated by the Auxiliary ; Protection System (APS), described in Section 7.7. Interface requirements for the Emergency Feedwater System are provided in Section 10.4.9. The ESF actuation system is composed of redundant trains A, B, C, and D. The instrumentation and controls of each train are physically and electrically separate and independent. Each train is a 100% capacity system, therefore the EFWS can sustain the loss of an entire train and still provide its required protective action. The EFWS instrumentation and controls are designed to operate under all plant conditions. O
'V i i
I Amendment E 7.3-25 December 30, 1988
CESSARn h ms Ol on a low steam generator level, the EFAS signal starts the EFW l pumps and opens the EFW isolation valves and flow control valves causing full flow system actuation. The actuation signal which opens the valves will clear automatically when normal steam I generator level is restored. Upon clearing of the valve actuation signal, the valves will remain in their open position, however the plant operator can manually control (i.e., reduce) flow, as defined in Section 10.4.9, otherwise, maximum flow will continue. If steam generator water level again falls below the low steam generator water level setpoint after the valve actuation signal clears, the EFAS signal will reactuate again causing full flow system actuation. To prevent steam generator overfill, a high steam generator level interlock is provided by the ESF-CCS to automatically close the isolation valves. This interlock is active only when EFAS valve actuation is not active. This interlock also protects against steam generator overfill due to erroneous operation of the EFW E system by the operator or the APS. 7.3.1.2 Design Bases The design bases of the ESF Systems are discussed in Chapter 6. The ESFAS is designed to provide initiating signals for ESF components which require automatic actuation following the design bases events shown on Table 7.3-2. The systems are designed in compliance with the applicable criteria of the NRC, " General Design Criteria for Nuclear Power Plants," Appendix A, 10 CFR 50. System testing conforms to the requirements of IEEE Std. 338-1977, " Standard Criteria for Periodic Testing of Nuclear Power Generating Station Protection Systems," and the intent of Regulatory Guide 1.22, " Periodic Testing of Protection System Actuation Functions." Specific design criteria for the ESFAS are detailed in IEEE Std. 279-1971, " Criteria for Protection Systems for Nuclear Power Generating Stations," Section 3. The following is a discussion of the specific items in IEEE Std. 279-1971 and their implementation. ! l The generating station conditions requiring actuation of the i ESFAS are listed on Table 7.3-2, which also shows which system i will actuate for each event. The monitored variables required j for ESF System protective action are listed on Table 7.3-3, which also shows which signals are generated by the variable. The number and location of the sensors required to monitor the variables are listed in Table 7.3-4. The normal operating , ranges, actuation setpoints, the nominal full power value, and ) the margin between the last two are listed on Table 7.3-5. The ranges of the ESFAS variables are listed on Table 7.3-6. Amendment E 7.3-26 December 30, 1988 { )
CESSAR E.%"lCATION The ESFAS is designed with consideration given to unusual events which could degrade system performance. System components are qualified for the environmental conditions discussed in.Section E 3.11 and the seismic conditions discussed in Section 3.10. A single failure within the system will not prevent proper protective action at the system level. The single failure criterion is discussed in Section 7.3.2.3.2. The ESFAS minimum response times are specified in the Technical Specifications and appear in Table 3.3-8 therein. The accuracies of the ESFAS measurement channels are given as the ALLOWED VARIATION on Table 3.3-4 of the Technical Specifications. The total ranges of ESPAS variables are provided in Table 7.3-6. 7.3.1.3 System Drawings The typical MCBDs, functional logics and typical control circuits E are shown in the figures following this section. 7.3.1.4 ESFAS Supportina Systems The systems required to support the ESFAS are discussed in Section 7.4. The electrical power distribution is discussed in O Section 8.3. 7.3.2 ANALYSIS 7.3.2.1 Introduction The ESFAS is designed to provide protection against the Design Basis Events listed on Table 7.3-2. The ESF Systems that are actuated are discussed in Chapter 6, along with their design bases and evaluations. The signals which will cause each ESFAS are listed on Table 7.3-3. The bases are discussed in Section 7.3.1.2. The actuation setpoints are given on Table 7.3-5. Most ESPAS signals are single parameter, fixed setpoint actuations. The ESFAS that do not fall into this category are: A. Low pressurizer pressure - can be decreased to 200 psi below the existing pressurizer pressure by.the operator. B. Low steam generator pressure - can be decreased to 200 psi l below the existing steam generator pressure by the operator. 2 These resets are controlled by administrative procedures provided by the site operator. i Amendment E l 7.3-27 December 30, 1988
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CESSAR n%"icari:n O Additionally, several ESFAS can be actuated by more than one parameter. That is, different parameters can cause the same ESFAS. The ESFAS which fall into this category are: A. SIAS by either low pressurizer pressure or high containment pressure. 1 B. CIAS by receiving the SIAS for that channel so that it j actuates on low pressurizer pressure or high containment ; J pressure. C. MSIS by high steam generator water level in either steam l generator, low steam generator pressure in either steam j generator, or high containment pressure. E j Each ESFAS setpoint is selected to be consistent with the function of the respective ESF System requirements. The setpoints are selected to provide ESF actuation in sufficient the time to provide the necessary actions to mitigate consequences of the Design Basis Events which caused the ESFAS. The adequacy of all ESFAS trip setpoints is verified through an analysis of the pertinent system transients reported in Chapter
- 15. These analyses utilize an Analysis Setpoint (assumed trip initiation point) and system delay times associated with the respective trip functions. The Analysis Setpoint along with instrument uncertainties provides the basis for the calculation of the final equipment setpoints to be reported in the Technical Specifications. Limiting trip delay times are given in Chapter
- 15. The manner by which these delay times and uncertainties will be verified is discussed in Section 7.2.1.2.
7.3.2.1.1 Design Bases Events (DBE) The DBE conditions for which the system will take action are those unplanned events under conditions that may occur once during the life of several nuclear generating stations, and certain combinations of unplanned events and degraded systems that are never expected to occur during the life of all nuclear power plants. The consequences of these events should be limited by the ESP Systems. The ESF Systems have a major responsibility to mitigate the consequences of the events listed below. This l includes minimizing fuel damage and subsequent release of fission products or other related ef fcGts. The accidents for which the ESFAS actuates are: A. RCS pipe rupture, including a double ended rupture. B. Steam system pipe rupture. E Amendment E j 7.3-28 December 30, 1988
CESSAR EnnnCATl*N
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C. Feedwater system pipe rupture. D. Steam generator tube rupture. E E. Break in a line from the reactor pressure coolant boundary that penetrates containment. F. Single CEA Ejection. The ESFAS will also act to mitigate the consequences of Anticipated operational occurrences as follows: A. Excess heat removal due to secondary system malfunctions. B. Inadvertent pressurization or depressurization of the RCS. C. Change in normal heat transfer capability between steam and reactor coolant systems, including:
- 1. Improper main feedwater flow
- 2. Loss of external load
? D. Complete loss of AC power to the station auxiliaries.
E. Depressurization due to the inadvertent opening of a ! pressurizer safety or relief valve. l 7.3.2.2 Actuation Bases The ESFAS consists of five signals based on five parameters. Each ESFAS has manual actuation switches on the main control panels. MSIS also has manual actuation switches at the remote shutdown panel. ! 7.3.2.2.1 Safety Injection Actuation Signal (SIAS) I A. Input Pressurizer pressure, containment pressure, or manual pushbuttons. The pressure signals are shared with the RPS. B. Function The SIAS actuates the components necessary to inject borated water into the reactor coolant system and actuates components for emergency cooling. SIAS is also initiated by a loss of power to two channels. , O Amendment E 7.3-29 December 30, 1988
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O 7.3.2.2.2 Containment Spray Actuation Signal (CSAS) , I A. Input i Containment pressure signals or manual pushbuttons. B. Function The CSAS actuates the Containment Spray System. CSAS is also initiated by a loss of power to two channels. E 7.3.2.2.3 Containment Isolation Actuation Signal (CIAS) A. Input Pressurizer pressure, containment pressure, or manual i pushbuttons. The pressurizer and containment pressure signals are provided via the SIAS. B. Function The CIAS actuates the isolation of lines penetrating the containment. CIAS is also initiated by a loss of power to i two channels. 7.3.2.2.4 Main Steam Isolation Signal (MSIS) A. Input Pressure from each steam generator, containment pressure, level from each steam generator, or manual pushbuttons. , d B. Function ] i The MSIS is provided to actuate the isolation of each steam j generator. MSIS is also initiated by a loss of power to two channels. 7.3.2.2.5 Emergency Feedwater Actuation Signal (EFAS) l A. Input Level from each steam generator or manual switches. E \ l Function
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B. l The EFAS actuates emergency feedwater on low water level to l the steam generator (s). EFAS is also initiated by a loss cf power to two channels. Amendment E 7.3-30 December 30, 1988
CESSAR !!nhiu lO L Actuation function EFAS-1 pertains to Steam Generator 1 and E EFAS-2 actuation function pertains to Steam Generator 2. 7.3.2.3 Desian 7.3.2.3.1 Ger.eral Design Criteria Appendix A, 10 CFR 50, " General Design Criteria for Nuclear Power Plants," established minimum requirements for the principle ~ design criter.ia for water cooled nuclear power plants. This section describes the requirements that are applicable to the ESFAS. Most references will be to Section 3.1 where the criteria are first SAdressed. Section 7.2.2.3.1 will be referenced if other comments from the RPS are applicable. Criterion 1 - Quality Standards and Records: Refer to Section 3.1.1 for compliance. Criterion 2 - Design Bases for Protection Against Natural Phenomena: Refer to Section 3.1.2 for compliance. Criterion 3 - Fire Protection: l l Refer to Section 3.1.3 for compliance. ! l Criterion 5 - Environmental and Missile Design Bases: Refer to Section 3.1.4 for compliance. 1 Criterion 13 - Instrumentation and Control: i Refer to Section 3.1.9 for compliance. ' Variables monitored are those' which affect ESF Systems. Criterion 16 - Containment Design: Refer to Section 3.1.12 for compliance. 1 l Criterion 20 - Protection System Functions: !
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Refer to Section 3.1.16 for compl.*ance. Criterion 21 - Protection System Reliability and Testability: Refer to Section 3.1.17 for compliance. l Amendment E 7.3-31 December 30, 1988 _ _ - - . _ _ - - - - - - - - - _ _ J
CESSAR MAOicarica O Criterion 22 - Protection System Independence: Refer to Section 3.1.18 for compliance. Criterion 23 - Protection System Failure Modes: Refer to Section 3.1.19 for compliance. From the PPS cabinet the signals are sent to four ESF-CCS train cabinets. In each cabinet is the selective actuation logic for each train. There is no interconnection between ESF-CCS cabinets or the trains they actuate so that each train is completely E independent. Criterion 24 - Separation of Protection and Control Systems: Refer to Section 3.1.20 for compliar.co. j Criteria 34, 35, 37, 38, 40, 41, 43, 44 and 46: Refer to Sections 3.1.30, 31, 33, 34, 36, 37, 39, 40 and 42 for compliance. The ESFAS provides the actuation which meets the requirements of IEEE Std. 279-1971 and IEEE Std. 338-1977. The single failure E ' criterion is met for all ESFAS. The ESFAS is fully testable. Those components which cannot be tested during power operations are tested when the plant is shutdown. 7.3.2.3.2 Equipment Design Criteria Many of the design criteria for protection systems are discussed in Section 7.1.2. IEEE Std. 279-1971, " Criteria for protection Systems for Nuclear Power Generating Stationc," establishes l minimum requirements for safety-related functional performance and reliability of the ESFAS. This section describes how the requirements of Section 4 of IEEE Std. 279-1971 are satisfied. The following heading numbers correspond to the Section numbers of IEEE Std. 279-1971. A. General Functional Requirements (Section 4.1): The ESFAS is designed to actuate the appropriate ESF < Systems, when required, to mitigate the consequences of the I specified Design Basis Events. Instrument performance characteristics, response times, and accuracies are selected for compatibility with, and at 'quacy for, the particular function. Actuation setpoints are established by analysis of the RCS parameters, steam generator parameters and Amendment E 7.3-32 December 30, 1988
CESSAREnnem. o O containment pressure. Factors- such as instrument inaccuracies, bistable trip delay times, valve travel times and L;mp starting times, are considered in establishing'the ! margin between the actuation setpoints and the. safety l limits.-- In addition, the possible loss of AC power and the time required to start standby power and to sequence loads must also be considered. The final determination of all of these times is the site operator's responsibility. The time E response of the sensors or protection systems are evaluated for abnormal conditions. Since all uncertainty factors are considered as cumulative for the derivation of these' times, the actual response time may be more rapid. However, even at the maximum times, the system provides conservative protection. B. ' Single Failure Criterion (Section 4.2): The ESFAS is designed so that any single failure within the system will not prevent proper protective action at the system level. No single failure will defeat more than one of the four protective channels associated with any one trip function. ! / The effects of single faults in the - RPS are discussed in Section 7.2.2.3.2. A similar analysis is applicable to that portion of the ESFAS located in the PPS cabinet. The initiating signal from the PPS goes to four separate ESF-CCS E train cabinets. Each cabinet contains the actuation circuitry for each train, therefore, a failure in one cabinet cannot affect the circuitry and actuated equipment of the other cabinets. Single faults of initiation or actuation buses have no E effect, as a selective two-out-of-four logic in required for j actuation. 1 Single faults of the actuation (or control) circuitry will j ' cause, at worst, only a failure of a component, group of components, or actuation of a system within one of the redundant actuation trains; actuation of the remaining E , redund'nt train components is sufficient for the protective action, j C. Qualit/ Control of Components and Modules (Section 4.3): The system is designed in accordance with the Quality E Assurance Program described in Section 17.0. O l Amendment E I 7.3-32 December 30, 1988 ) 1
CESSAREn=c-O. D. Equipment Qualification (Section 4.4): The ESFAS equipment is qualified in accordance with the methodology discussed in Sections 3.10 and 3.11. E. Channel Integrity (Section 4. 5) : i Type Msting of components, separation of sensors and channels, and qualification of cabling are utilized to ensure that the channels will maintain their functional capability required under applicable extremes of environment, power supplied, malfunction, and DBE conditions. Loss or damage of any one path will not prevent the protective action of the ESFAS. Sensors are piped using materials of comparable quality to the systems to which they are attached so that, in the unlikely event of blockage or failure of any one connection, protective action is not prevented. The process sensors located in the containment building are specified and rated for the intended service. Components which must oparate during or after DBEs are rated for the expected post-event environment. Results of type , tests are used to verify these ratings. F. Channel Independence (Section 4.6): , The location of the sensors, for the ESFAS, and the points at which the sensing lines are connected to the process loop have been selected to provide physical separation of the channels within the system, thereby precluding a situation in which a single event could remove or negate a protective action. The routing of cables frcm protection system transmitters is arranged so that the cables are separated from each other, and from power cabling, to minimize the likelihood of common event failures. This includes separation of the containment penetration areas. The i initiation paths are located in four PPS cabinets and the ! actuation devices are fed from the four ESF-CCS train E cabinets. Geographical separation and electrical isolation between these cabinets minimize the possibility cf a common mode failure. The output from these redundant channels are isolated from each other so that loss of a channel does not cause loss of the system. The signals from the ESFAS which supply the DPS E and DIAS are isolated via fiber-optic cabla. The criteria for separation and physical independence of channels are based on the need for decoupling the effects of i Amendment E 7.3-34 December 30, 1988
CESSARtuinc-DBE consequences and power supply transients, and for reducing the likelihood ~of channel interaction during testing or in the event of a channel malfunction. i G. Control and Protection System Interaction (Section.4.7):
- 1. Classification of Equipment:
No portion of the ESFAS is used for both protective and control functions except sensor input signals. as described in Section 7.7.
- 2. Isolation Devices: E Signals sent from the 'ESFAS to the DPS and DIAS are isolated via fiber-optic cable such that a failure in these areas will not affect the protective action of the ESFAS.
- 3. Single Random Failure:
This criterion is' not applicable since there are no channels used for both control and protection except sensor input signals as described in Section- 7.7. E ( Therefore a single random failure can only occur. in either a control or a protection channel.
- 4. Multiple Failures Resulting from a Credible Single Evente l
This cannot exist, because control and protection channels have nothing in common, except the use of protection sensors. Protection sensors provide E fiber-optic isolated signals to the control systems for signal validation and control. Protection sensor failure effects are discussed in Section 7.7. l H. Derivation of Signal Inpt- (Section 4.8): l Insofar as possible, in,* .s are derived from signals that are direct measurements t." the desired variable. Directly measured variables include pressurizer, containment, and steam generator pressures. The steam generator levels are derived from differential pressure signals. E I. Capability for Sensor Checks (Section 4.9): l ESFAS sensors are checked by methods described in Section 7.7 including cross-channel comparison. Each channel has'a known relationship with the other channels of the same parameter. Amendment E-7.3-35 December 30, 1988-
CESSARn h a O J. Capability for Test and Calibration (Section 4.10) : , 1 i The ESFAS design complies with IEEE Std. 338 1977, " Standard E Criteria for the Periodic Testing of Nuclear Power Generating Station Protection System Actuation Functions," as discussed in Section 7.3.2.3.3. K. Channel Bypass or Removal from Operation (Section 4.11): Any one of the four protection channels in the ESFAS may be tested, calibrated or repaired without detrimental effect on the system. Individual actuation channels (i.e., pressurizer pressure, containment pressure, steam generator level) may be bypassed to create a two-out-of-three logic while maintaining the coincidence of two on the remaining channels. The single failure criterion is met during this condition. L. Operating Bypasses (Section 4.12): Operating bypass is provided as shown on Table 7.3-1. The operating bypass is automatically removed when the permissive condition is not met. The circuitry and devices which function to remove this inhibit are designed in accordance with IEEE Std. 279-1971. i M. Indication of Bypasses (Section 4.12): Indication of test or bypass conditions, or removal of any channel from service is given by the DIAS and DPS. The E operating bypass that is automatically removed at a fixed setpoint, is alarmed and indicated. N. Access to Means for Bypassing (Section 4.13): i Trip channel bypasses have controlled access. When the I first parameter is bypassed there is an audible and visible ; alarm to indicate the bypass. The specific parameter or E parameters which are being bypassed are indicated in the respective channel by lights at the PPS cabinet and its remote operators' module. The operating bypasses also have audible and visible alarms. The operating bypasses have automatic festures which provide , a permissive level at which they can be actuated and a j second level at which they are automatically removed. i l O I Amendment E 7.3-36 December 30, 1988 I 4
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O. Multiple Setpoints (Section 4.15): Manual reduction of the setpoints for low pressurizer and low steam generator pressures are used for the controlled i reduction of pressures as discussed in Sections 7.3.1.1.10.3 { and 7.3.1.1.10.4. The setpoint reductions are initiated by main control board pushbuttons for each channel, one l pushbutton for the pressurizer pressure and one pushbutton for both steam generator pressures within the.one channel. ] j Operation of the pushbutton will- reduce the pressure actuation setpoint a selected increment below the existing system pressure. As the pressurizer or steam generator pressure increases the actuation setpoint will increase automatically with 'the pressure, maintaining a fixed increment, until the setpoint reaches its normal actuation i setpoint value. l P. Completion of Protective Action .Once It. is Initiated (Section 4.16): The ESFAS is designed to ensure that protective action will go to completion once initiated. Actuation of an.ESFAS can l be cleared'by the operator manually resetting . the ESFAS at l O the ESF-CCS remote coerators' module. is A protective action initiated when 'the -selective two-out-of-four logic reaches the proper coincidence of two state. A protective E l action is completed when all of the appropriate ESF' actuated components have assumed the proper state for their ESF function. The EFAS valves are not locked into its actuation l but the pumps are locked in. EFAS is designed to cycle l based on the steam generator level signal. E Q. Manual Initiation (Section 4.17):}}