ML20247H417
| ML20247H417 | |
| Person / Time | |
|---|---|
| Site: | 05200002, 05000470 |
| Issue date: | 03/30/1989 |
| From: | ABB COMBUSTION ENGINEERING NUCLEAR FUEL (FORMERLY |
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| Shared Package | |
| ML20247G537 | List:
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| References | |
| NUDOCS 8904040456 | |
| Download: ML20247H417 (597) | |
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v i CHAPTER 15 l l l ACCIDENT ANLAYSES l gy
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I' l 1 l Chapter 15 and its appendices are completely replaced in Amendemnt No. 7.
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Due to the effort required to revise the format from the original submittal, previous amendments were submitted as interim documents. Therefore, )f. S
, revision lines are not shown on the revised pages.
,J U Amendment No. 7
, f4 arch 31, 1982 8904040456 890330 PDR ADOCK 05000470 PDR K
1 Ol l i t ! THIS PAGE INTENTIONALLY BLAtlK. i I n, ei t; i l
(Sheet 1of12) [] EFFECTIVE PAGE LISTING V CHAPTER 15 1 Table of Contents Page Amendment l 1 7 ii 7 iii 7 iv 7 v 8 vi 7 vii 7 viii 7 ix 7 x 7 t xi 7 xii 7 xiii 7 xiv 7 xv 7 xvi 7 xvii 7 xviii 7 xix 7 (Vn) xx xxi 7 7 xxii 7 xxiii 7 xxiv 7 xxv 7 xxvi 7 xxvii 7 xxviii 7 xxix 7 xxx 7 : i xxxi 7 Text 8 Page Amendment 15.0-1 7 15.0-2 7 15.0-3 7 15.0-4 10 15.0-5 7 15.0-6 7 15.0-7 7 15.0-8 7
/ 15.0-9 7 15.0-10 7 15.0-11 7 ;
15.0-12 7 i Amendment No. 10 i June 28, 1985 , J
(Sheet 2 of 12) l l EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 i Text (Cont'd) Page Amendment 15.1-1 7 15.1-2 7 15.1-3 7 15.1-4 7 15.1-5 7 15.1-6 7 15.1-7 10 , 15.1-8 10 15.1-9 7 15.1-10 9 15.1-11 7 15.1-12 10 15.1-13 10 j 15.1-14 10 j 15.1-15 10 15.1-16 10 15.1-17 9 j Gt l 15.2-1 7 15.2-2 7 0 15.2-3 7 1 15.2-4 7 15.2-5 10 15.2-6 10 15.2-7 7 15.2-8 7 15.2-9 7 15.2-10 7 15.3-1 7 15.3-2 7 15.3-3 7 15.3-4 7 15.3-5 7 15.3-6 8 15.3-7 8 15.3-8 8 15.3-9 8 15.3-10 8 15.3-11 8 15.3-12 8 15.3-13 8 15.3-14 8 15.3-15 8 15.3-16 8 15.3-17 8 i Amendment No. 10 June 28, 1985
(Sheet 3 of 12) O / EFFECTIVEPAGELISTING(Cont'd.) CHAPTER 15 Text (ContY} Page Amendment 15.4-1 7 l 15.4-2 7 15.4-3 10 15.4-4 7 15.4-5 7 15.4-6 10 15.4-7 7 15.4-8 7 15.4-9 7 15.4-10 7 15.4-11 7 15.4-12 7 15.4-13 7 15.4-14 7 15.4-15 7 15.4-16 7 15.4-17 7 15.4-18 7 15.4-19 7 v 15.4-20 10 15.4-21 7 15.4-22 7 15.5-1 7 15.5-2 7 15.5-3 7 15.5-4 7 15.5-5 7 15.5-6 10 l l 15.6-1 7 ; 15.6-2 7 15.6-3 7 15.6-4 7 15.6-5 7 15.6-6 7 15.6-7 10 15.6-8 7 15.6-9 7 15.6-10 7 15.6-11 10 15.6-12 7 15.6-13 7 Amendment No. 10 June 28, 1985
(Sheet 4 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 1 Text (Cont'd) J l Page Amendment l 15.6-14 7 15.6-15 7 15.6-16 7 15.6-17 7 15.6-18 10 ; 15.6-19 7 j 15.6-20 7 l 15.6-21 7 ' 15.7-1 7 ; 15.7-2 7 l 15.7-3 7 Tables Table No. Amendment 15.0-1 7 15.0-2 7 15.0-3 7 15.0-4 10 15.0-5 10 15.0-6 7 15.1.4-1 10 15.1.4-2 10 15.1.4-3 7 l 15.1.5-1 10 1 15.1.5-2 10 15.1.5-3 10 15.1.5-4 10 15.1.5-5 10 ' 15.1.5-6 7 15.1.5-7 7 15.1.5-8 7 15.1.5-9 7 15.1.5-10 9 15.1.5-11 (Sheet 1) 9 15.1.5-11 (Sheets 2 and 3) 7 15.2.3-1 (Sheets 1 and 2) 10 15.2.3-2 7 j 15.2.3-3 7 ] 15.2.3-4 7 l l Amendment No. 10 I June 28, 1985 l
- q (Sheet 5 of 12)
(Jn) R FFFECTI'fE PAGF LISTING (Cnnt'd.) CHAPTER 15 Tables Table No. Amendment 15.3.1-1 10 15.3.1-2 7 15.3.1-3 7 15.3.1-4 7 15.3.3-1 (Sheets 1-3) 10 15.3.3-2 8 15.3.3-3 8 15.3.3-4 8 15.3.3-5 8 15.3.3-6 8 15.3.3-7 8 15.4.1-1 10 15.4.1-2 7 15.4.1-3 7
, 15.4.1-4 10 h 15.4.2-1 15.4.2-2 10 7
15.4.2-3 7 15.4.2-4 7 15.4.3-1 7 15.4.3-2 7 15.4.3-3 7
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15.4.6-1 7 15.4.8-1 (Sheets 1 and 2) 10 , 15.4.8-2 7 l' 15.4.8-3 7 ( 15.4.8-4 7 15.4.8-5 7 15.4.8-6 7 15.4.8-7 7 15,4.8-8 7 15.5.2-1 10 15.5.2-2 7 15.5.2-3 7 15.6.2-1 7 15.6.2-2 7 b 15.6.2-3 7 l 15.6.2-4 7 l 15.6.2-5 7 , 1 Amendment No. 10 : June 28, 1985 i I
n (Sheet 6 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 - Tables I Table No. Amendme_n_t 15.6.3-1 (Sheets 1 and 2) 10 15.6.3-2 7 15.6.3-3 7 15.6.3-4 7 15.6.3-5 7 15.6.3-6 (Sheets 1 and 2) 10 15.6.3-7 7 15.6.3-8 7 15.6.3-9 7 15.6.3-10 7 15.6.5-1 7 15.7.4-1 7 Figures Figure No. Amendment 15.0-1 (sheets A,B,C) 7 15.0-2 9 15.1.4-1.1 7 15.1.4-1.2 7 15.1.4-1.3 7 15.1.4-1.4 7 15.1.4-1.5A 7 15.1.4-1.5B 7 15.1.4-1.6 7 15.1.4-1.7 7 15.1.4-1.C 7 15.1.4-1.9 7 15.1.4-1.10 7 15.1.4-1.11 7 15.1.4-1.12 7 15.1.4-1.13 7 15.1.4-1.14 7 15.1.4-1.15 7 15.1.4-2.1 7 15.1.4-2.2 7 15.1.4-2.3 7 15.1.4-2.4 7 15.1.4-2.5A 7 15.1.4-2.5B 7 , 15.1.4-2.6 7 Amendment No. 10 June 28, 1985 _a
(Sheet 7of12) p x EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures Figure No. Amendment l 15.1.4-2.7 7
'15.1.4-2.8 7 15.1.4-2.9 7 ,
15.1.4-2.10 7 15.1.4-2.11 7 15.1.4-2.12 7 15.1.4-2.13 '7 15.1.4-2.14 7 15.1.4-2.15 7 15.1.5-1.1 7 15.1.5-1.2 7 15.1.5-1.3 7 15.1.5-1.4 7 15.1.5-1.5A 7 15.1.5-1.5B 7 15.1.5-1.6 7 15.1.5-1.7 7 l O 15.1.5-1.8 15.1.5-1.9 15.1.5-1.10 7 7 7 15.1.5-1.11 7 15.1.5-1.12 7 15.1.5-1.13 7 15.1.5-1.14 7 15.1.5-1.15 7 15.1.5-1.16 7 1 15.1.5-2.1 7 15.1.5-2.2 7 15.1.5-2.3 7 15.1.5-2.4 7 15.1.5-2.5A 7 15.1.5-?.5B 7 15.1.5-2.6 7 15.1.5-2.7 7 15.1.5-2.8 7 15.1.5-2.9 7 15.1.5-2.10 7 15.1.5-2.11 7 15.1.5-2 12 7 15.1.5-2.13 7 15.1.5-2.14 7 15.1.5-2,15 7 l Amendment No. 10 June 28, 1985
(Sheet 8 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 ! l Figures Figure No. Amendment 15.1.5-3.1 7 15.1.5-3.2 7 15.1.5-3.3 7 J 15.1.5-3.4 7 1 15.1.5-3.5A 7 15.1.5-3.5B 7 15.1.5-3.6 7 15.1.5-3.7 7 15.1.5-3.8 7 15.1.5-3.9 7 15.1.5-3.10 7 15.1.5-3.11 7 15.1.5-3.12 7 15.1.5-3.13 7 15.1.5-3.14 7 15.1.5-3.15 7 15.1.5-4.1 7 ) 15.1.5-4.2 7 ) 15.1.5-4.3 7 ) 15.1.5-4.4 7 15.1.5-4.5A 7 15.1.5-4.5B 7 15.1.5-4.6 7 15.1.5-4.7 7 15.1.5-4.8 7 15.1.5-4.9 7 15.1.5-4.10 7 15.1.5-4.11 7 I 15.1.5-4.12 7 15.1.5-4.13 7 15.1.5-4.14 7 15.1.5-4.15 7 l 15.1.5-5.1 9 15.1.5-5.2 9 15.1.5-5.3 9 15.1.5-5.4 9 15.1.5-0.5 9 15.1.5-5.6 9 15.1.5-5.7 9 15.1.5-5.8 9 15.1.5-5.9 9 Amendment No. 10 June 28, 1985
(Sheet 9 of 12) n EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures Figure No. Amendment 15.2.3-1 (sheet A) 10 (sheets B,C) 7 j 15.2.3-2 7 15.2.3-3 7 15.2.3-4 7 15.2.3-5 7 15.2.3-6 7 15.2.3-7 7 15.2.3-8 7 l 15.2.3-9 7 15.2.3-10 7 15.2.3-11 7 15.2.3-12 7 15.2.3-13 7 15.2.3-14 7 15.3.1-1 (sheet A) 10 (sheets B,C,D) 7 15.3.1-2 7 ( 15.3.1-3 7 15.3.1-4 7 15.3.1-5 7 15.3.1-6 7 15.3.1-7 7 15.3.1-8 7 15.3.1-9 7 i 15.3.3-1(sheetA) 10 (sheets B.C.D) 8 15.3.3-2 7 15.3.3-3 7 15.3.3-4 7 15.3.3-5 7 15.3.3-6 7 15.3.3-7 7 15.3.3-8 7 15.3.3-9 8 15.3.3-10 7 15.4.1-1 (sheets A,B,C) 7 15.4.1-2 7 15.4.1-3 7 15.4.1-4 7 15.4.1-5 7
/q 15.4.1-6 7 Vi 15.4.1-7 15.4.1-8 7
7 Amendment No. 10 June 28, 1985
(Sheet 10 of 12) ] EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures l Figure No. Amendment 15.4.2-1 (sheets A,B,C,D) 7 15.4.2-2 7 4 15.4.2-3 7 l 7 l 15.4.2-4 1 15.4.2-5 7 15.4.2-6 7 15.4.2-7 7 15.4.2-8 7 1 15.4.2-9 7 ' 15.4.2-10 7 15.4.2-11 7 15.4.2-12 7 4 15.4.3-2 7 15.4.3-3 7
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15.4.3-4 7 15.4.3-5 7 15.4.3-6 7 , 15.4.3-7 7 1 15.4.3-8 7 15.4.3-9 7 15.4.3-10 7 15.4.3-11 7 15.4.3-12 7 15.4.3-13 7 15.4.6-1 7 15.4.7-1 7 15.4.8-1(SheetsA.C) 10 (Sheets B,0,E,F) 7 15.4.8-2 7 15.4.8-3 7 15.4.8-4 7 15.4.8-5 7 15.4.8-6 7 15.4.8-7 7 15.4.8-8 e 15.4.8-9 7 15.4.8-10 7 15.4.8-11 7 15.4.8-12 7 l, 15.4.8-13 7 15.5.2-1 (sheets A,B,C.D) 7 15.5.2-2 7 l 4 Amendment No. 10 - June 28, 1985 ] l
EFFECTIVE PAGE LISTING (Cont'd.) (h ' CHAPTER 15 Figuras Figure No. Amendment 15.5.2-3 7 15.5.2-4 7 -! 15.5.2-5 7 15.5.2-6 7 15.5.2-7 7 15.5.2-8 7 15.5.2-9 7 15.5.2-10 7 15.5.2-11 7 15.6.2-1 (sheets A,B,C) 7 15.6.2-2 7 15.6.2-3 7 15.6.2-4 7 15.6.2-5 7 15.6.2-6 7 15.6.2-7 7 15.6.2-8 7 15.6.2-9 7 l' O
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15.6.2-10 15.6.2-11 15.6.2-12 7 7 7 15.6.2-13 7 l 15.6.2-14 7 15.6.3-1(sheetA) 10 (sheets B,C,0) 7 15.6.3-2 7 15.6.3-3 7 . 15.6.3-4 7 15.6.3-5 7 15.6.3-6 7 15.6.3-7 7 15.6.3-8 7 15.6.3-9 7 15.6.3-10 7 l 15.6.3-11 7 l 15.6.3-12 7 l 1 15.6.3-13 7 15.6.'3-14 7 15.6.3-15 7 , 15.6.3-16 7 15.6.3-17 7 , 15.6.3-18(sheetA) 10 : ( 15.6.3-19 (sheets B C.D) 7 7 l l Amendment No. 10 June 28, 1985
(Sheet 12 of 12) EFFECTIVEPAGELISTING(Cont'd.) CHAPTER 15 Figures Figure No. Amendment 15.6.3-20 7 15.6.3-21 7 15.6.3-22 7 15.6.3-23 7 ] 15.6.3-24 7 15.6.3-25 7 } 15.6.3-26 7 l J 15.6.3-27 7 j 15.6.3-28 7 1 15.6.3-29 7 1 15.6.3-30 7 15.6.3-31 7 - 15.6.3-32 7 l 15.6.3-33 7 ! 15.6.3-34 7 ! O Amendment No. 10 June 28, 1985
'ABLE OF CONTENTS Chapter 15 Section Subject Page No.
- 15. _
ACCIDENT ANALYSES 15.0 ORGANIZATION AND METHODOLOGY 15.0-1 15.0.1 CLASSIFICATION OF TRANSIENTS AND ACCIDENTS 15.0 1 15.0.1.1 Format and Content 15.0-1 15.0.1.2 Event Categories 15.0-1 15.0.1.3 Event Frequencies 15.0-1 15.0.1.4 Events and Event Combinations 15.0-2 15.0.1.5 Section Numberpg 15.0-2 15.0.1.6 Sequence of Events Analysis 15.0-2 15.0.2 SYSTEMS OPERATION 15.0-4 15.0.3 CORE AND SYSTEM PERFORMANCE 15.0-5 O 15.0.3.1 Mathematical Model 15.0-5 Q 15.0.3.1.1 Loss of Flow Analysis Method 15.0-5 15.0.3.1.2 CEA Ejection Analysis Method 15.0-5 l 15.0.3.1.3 CESEC Computer Program 15.0-5 15.0.3.1.4 C0AST Computer Program 15.0-6 15.0.3.1.5 STRIKIN-II Computer Program 15.0-6 1 15.0.3.1.6 TORC Computer Program 15.0-7 15.0.3.1.7 Reactor Physics Computer Programs 15.0-7 15.0.3.2 Initial Condition 15.0-7 15.0.3.3 Input Parameters 15.0-7 15.0.3.3.1 Doppler Coefficient 15.0-7 15.0.3.3.2 Moderator Temperature Coefficient 15.0-8 l t l Shutdown CEA Reactivity 15.0-8 15.0.3.3.3 l U Amendment No. 7 j March 31,1982 i a
TAB.LE OF CONTENTS (Continued) Chapter 15 ' Section Subject Page No. 15.0.3.3.4 Effective Delayed Neutron Fraction 15.0-9 15.0.3.3.5 Decay Heat Generation Rate 15.0-9 15.0.4 RADIOLOGICAL CONSEQUENCES 15.0-9 15.1 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 15.1-1 15.1.1 DECREASE IN FEEDWATER TEMEPRATURE 15.1.1 15.1.1.1 Identification of Event and Causes 15.1-1 15.1.1.2 Sequence of Events and System Operations 15.1-1 15.1.1,3 Analysis of Effects and Consequences 15.1-1 15.1.1.4 Conclusions 15.1-1 15.1.2 INCREASE IN FEEDWATER FLOW 15.1-2 15.1.2.1 Identification of Event and Causes 15.1-2 15.1.2.2 Sequence of Events and System Operations 15.1-2 15.1.2.3 Analysis of Effects and Consequences 15.1-2 15.1.2.4 Conclusions 15.1-2 15.1.3 INCREASED MAIN STEAM FLOW 15.1-3 15.1.3.1 Identification of Event and Causes 15.1-3 15.1.3.2 Sequence of Events and System Operations 15.1-3 15.1.3.3 Analysis of Effects and Consequences 15.1-3 15.1.3.4 Conclusions 15.1-3 15.1.4 INADVERTENT OPENING OFA STEAM GENERATOR RELIEF OR SAFETY VALVE 15.1-4 13.1.4.1 Identification of Event and Causes 15.1-4 15.1.4.2 Sequence of Events and System Operations 15.1-4 15.1.4.3 Analysis of Effects and Consequences 15.1-6 15.1.4.4 Conclusions 15.1-8 Amendment No. 7 ii March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 Section Subject Page No. 15.1.5 STEAM SYSTEM PIPING FAILURES INSIDE RND OUTSIDE CONTAINMENT 15.1-10 q 15.1.5.1 Identification of Event and Causes 15.1-10 15.1.5.2 Sequence of Events and System Operations 15.1-11 15.1.5.3 Analysis of Effects and Consequences 15.1-12 1 15.1.5.4 Conclusions 15.1-16 l 15.2 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 15.2-1 l l , 15.2.1 LOSS OF EXTERNAL LOAD 15.2-1 l l 15.2.1.1 Identification of Event and Causes 15.2-1 15.2.1.2 Sequence of Events and System Operations 15.2-1 l 15.2.1.3 Analysis of Effects and Consequences 15.2-1 1 15.2.1.4 Conclusions 15.2-1 15.?.2 TURBINE TRIP 15.2-2 15.2.2.1 Identification of Event and Causes 15.2-2 15.2,2.2 Sequence of Events and System Operations 15.2-2 15.2.2.3 Analysis of Effects and Consequences 15.2-2 15.2.2.4 Conclusions 15.2-2 15.2.3 LOSS OF CONDENSER VACUUM 15.2-3 1 15.2.3.1 Identification of Event and Causes 15.2-3 15.2.3.2 Sequence of Events and System Operations 15.2-3 15.2.3.3 Analysis of Effects and Consequences 15.2-5 15.2.3.4 Conclusions 15.2-6 15.2.4 MAIN STEAM ISOLATION VALVE CLOSURE 15.2-7 15.2.4.1 Identification of Event and Causes 15.2-7 ("N
\ 15.2.4.2 Sequence of Events and System Operations 15.2-7
... Amendment No. 7
'II March 31, 1982
TABLE OF CONTENTS (Continued) l Chapter 15 Section Subject Page No. 15.2.4.3 Analysis of Effects and Consequences 15.2-7 15.2.4.4 Conclusions 15.2-7 1 15.2.5 STEAM PRESSURE REGULATOR FAILURE 15.2-7
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15.2.6 LOSS OF NON-EMERGENCY A-C POWER TO THE STATION j AUXILIARIES 15.2-8 ) 15.2.6.1 Identification of Event and Causes 15.2-8 15.2.6.2 Seauence of Events and System Operations 15.2-8 15.2.6.3 Analysis of Effects and Consequences 15.2-8 15.2.6.4 Conclusions 15.2-9 15.2.7 LOSS OF NORMAL FEEDWATER FLOW 15.2-9 15.2.7.1 Identification of Event and Causes 15.2-9 15.2.7.2 Sequence of Events and System Operations 15.2-9 15.2.7.3 Analysis of Effects and Consequences 15.2-9 15.2.7.4 Conclusions 15.2-10 15.2.8 FEEDWATER SYSTEM PIPE BREAKS 15.2-10 15.3 DECREASE IN REACTOR COOLANT FLOW RATE 15.3-1 15.3.1 TOTAL LOSS OF REACTOR COOLANT FLOW 15.3-1 15.3.1.1 Identification of Event and Causes 15.3-1 15.3.1.2 Sequence of Events and System Operations 15.3-2 15.3.1.3 Analysis of Effects and Consequences 15.3-4 15.3.1.4 Conclusions 15.3-5 15.3.2 FLOW CONTROLLER MALFUNCTION CAUSING FLOW C0ASTDOWN 15.3-6 ) I 15.3.3 SINGLE REACTOR COOLANT PUMP ROTOR SElZURE WITH 1 LOSS OF 0FFSITE POWER 15.3-6 15.3.3.1 Identification of Event and Causes 15.3-6 9{il iv Amendment. No. 7 March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 v Section Subject Page No. 15.3.3.2 Sequence of Events and System Operations 15.3-7 15.3.3.3 Analysis of Effects and Consequences 15.3-11 15.3.3.4 Conclusions 15.3-15 15.3.4 REACTOR COOLANT PUMP SHAFT BREAK WITH LOSS OF 0FFSITE POWER 15.3-16 8 15.3.4.1 Identification of Event and Causes 15.3-16 l 15.3.4.2 Sequence of Events and System Operations 15.3-16 15.3.4.3 Analysis of Effects and Consequences 15.3-16 15.3.4.4 Conclusions 15.3-17 15.4 REACTIVITY AND POWER DISTRIBUTION ANOMALIES 15.4-1 15.4.1 UNCONTROLLED CONTROL ELEMENT ASSEMBLY WITHDRAWAL l FROM A SUBCRITICAL OR LOW POWER CONDITION 15.4-1 f\ U / 15.4.1 1 Identification of Event and Causes 15.4-1 15.4.1.2 Sequence of Events and System Operations 15.4-1 15.4.1.3 Analysis of Effects and Consequences 15.4-2 15.4.1.4 Conclusions 15.4-3 15.4.2 UNCONTROLLED CONTROL ELEMENT ASSEMBLY WITHDRAWAL AT POWER 15.4-4 15.4.2.1 Identification of Event and Causes 15.4-4 15.4.2.2 Sequence of Events and System Operations 15.4-4 15.4.2.3 Analysis of Effects and Consequences 15.4-5 15.4.2.4 Conclusions 15.4-6 15.4.3 SINGLE FULL LENGTH CONTROL ELEMENT ASSEMBLY DROP 15.4-7 15.4.3.1 Identification of Event and Causes 15.4-7 15.4.3.2 Sequence of Events and System Operations 15.4-7 15.4.3.3 Analysis of Effects and Consequenc g 15.4-7 y Amendment Number 8 May 10,1983
l TABLE OF CONTENTS (Continued) Chapter 15 Sec tion Subject Page No. 15.4.3.4 Conclusions 15.4-9 16.4.4 START UP OF AN INACTIVE REACTOR COOLANT PUMP 15.4-10 15.4.4.1 Identification of Event and Causes 15.a-10 15.4.4.2 Sequence of Events and System Operations 15.4-10 15.4.4.3 Analysis of Effects and Consequences 15.4-10 15.4.4.4 Conclusions 15.4-10 15.4.5 FLOW CONTROLLER MALFUNCTION CAUSING AN INCREASE IN BWR CORE FLOW 15.4-11 15.4.6 INADVERTENT DEB 0 RATION 15.4-11 15.4.6.1 Identification of Event and Causes 15.4-11 15.4.6.7 Sequence of Events and System Operations 15.4-12 15.4.6.3 Analysis of Effects and Consequences 15.4-12 15.4.6.4 Conclusions 15.4-14 15.4.7 INADVERTENT LOADING OF A FUEL ASSEMBLY INTO THE IMPROPER POSITION 15.4-15 15.4.7.1 Identification of Event and Causes 15.4-15 15.4.7.2 Sequence of Events and System Operations 15.4-15 15.4.7.3 Analysis of Effects and Consequences 15.4-16 15.4.7.4 Conclusions 15.4-16 15.4.8 CONTROL ELEMENT ASSEMBLY (CEA) EJECTION 15.4-17 15.4.8.1 Identification of Event and Causes 15.4-17 15.4.8.2 Sequence of Events and System Operations 15.4-17 15.4.8.3 Analysis of Effects and Consequences 15.4-19 15.4.8.4 Conclusions 15.4-21 15.5 INCREASE IN RCS INVENTORY 15.5-1 vi Amendment No. 7 March 31,1982
' 's TABLE OF CONTENTS (Continued) l
)
Chapter 15 Section Subject Page No. 15.5.1 INADVERTENT OPERATION OF THE ECCS 15.5-1 15.5.1.1 Identification of Event and Causes 15.5-1 15.5.1.2 Sequence of Events and System Operations 15.5-1 15.5.1.3 Analysis of Effects and Consequences 15.5-1 15.5.1.4 Conclusions 15.5-1 15.5.2 CVCS MALFUNCTION-PRESSURIZER LEVEL CONTROL SYSTEM MALFUNCTION WITH LOSS OF 0FFSITE POWER 15.5 1 i 15.5.2.1 Identification of Event and Causes 15.5-1 15.5.2.2 Sequence of Events and System Operations 15.5-3 15.5.2.3 Analysis of Effects and Consequences 15.5-5
<-- 15.5.2.4 Conclusions 15.5-6 15.6 15.6-1 DECREASE IN REACTOR COOLANT SYSTEM INVENT 0RY l
15.6.1 INADVERTENT OPENING 0F A PRESSURIZER SAFETY / RELIEF VALVE 15.6-1 i 15.6.2 DOUBLE-ENDED BREAK OF A LETDOWN LINE OUTSIDE CONTAINMENT 15.6-2 15.6.2.1 Identification of Event and Causes 15.6-2 15.6.2.2 Sequence of Events and System Operations 15.6-2 15.6.2.3 Analysis of Effects and Consequences 15.6-4 15.6.2.4 Conclusions 15.6-6 15.6.3 STEAM GENERATOR TUBE RUPTURE 15.6-7 15.6.3.1 Steam Generator Tube Rupture Without a Loss of Offsite Power 15.6-7 15.6.3.1.1 Identification of Event and Causes 15.6-7 15.6.3.1.2 Sequence of Events and System 15.6-7 Operations ( 15.6.3.1.3 Analysis of Effects and Consequences 15.6-9 yjj Amendment No. 7 March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 Section Subject Page No. 15.6.3.1.4 Conclusions 15.6-14 15.6.3.2 Steam Generator Tube Rupture With a Loss of Offsite Power 15.6-15 15.6.3.2.1 Identification of Event and Causes 15.6-15 15.6.3.2.2 Sequence of Events and System 15.6-15 Operations 15.6.3.2.3 Analysis of Effects and Consequences 15.6-17 15.6.3.2.4 Conclusions 15.6-20 15.6.5 LOSS-0F-COOLANT ACCIDENT (LOCA) 15.6-21 15.6.5.1 Identification of Causes 15.6-21 15.6.5.2 Analysis of Events and Consequences 15.6-21 15.7 RADI0 ACTIVE MATERIAL RELEASED FROM A SYSTEM OR COMPONENT 15.7-1 l 15.7.1 WASTE GAS SYSTEM FAILURE 15.7.2 RADI0 ACTIVE LIQUID WASTE SYSTEM LEAK OR FAILURE 15.7.3 RADIOACTIVE RELEASE DUE TO LIQUID CONTAINING TANK FAILURE 15.7-1 15.7.4 FUEL HANDLING ACCIDENT 15.7-1 15.7.4.1 Identification of Event and Causes 15.7-1 15.7.4.2 Sequence of Events and System Operations 15.7-1 15.7.4.3 Analysis of Effects and Consequences 15.7-1 , l 1 15.7.4.4 Conclusions 15.7-3 l
)
O viii Amendment No. 7 March 31,1982 l
v p LIST OF TABLES \ Chapter 15 Table Subject 15.0.1 (Intentionally Blank) 15.0.2 Chapter 15 Subsection Designation 15.0.3 (Intentionally Blank) 15.0.4 Reactor Protection System Trips Used in the Safety Analysis 15.0.5 Initial Conditions 15.0.6 Single Failures 15.1.4-1 Sequence of Events fer Full Power Inadvertent Opening of a Steam Generator Atmospheric Dump Valve (10SGADV) 15.1.4-2 Sequence of Events for Full Power Inar vertent Opening of a Steam Generator Atmospheric Dump Valve with Loss of Offsite Power after Turbine Trip (10SGADV + LOP) p 15.1.4-3 Assumptions and Initial Conditions for Full Power Inadvertent 8 i Opening of an Atmospheric Dump Valve (IOSGADV and 10SGADV + U LOP) 15.1.5-1 Sequence of Events for a large Steam Line Break During Full Power Operation with Concurrent Loss of Offsite Power (SLBFPLOP) 15.1.5-2 Sequence of Events for a large Stean. Line Break During Full Power Operation with Offsite Power Available (SLBFP) 15.1.5-3 Sequence of Events for a large Steam Line Break During Zero Power Operation with Offsite Power Available (SLBFP) 15.1.5-4 Sequence of Events for a Large Steam Line Break During Zero Power Operation with Offsite Power Available (SLBZP) 15.1.5-5 Sequence of Events for a Small Steam Line Break Outr 'de Containment During Full Power Operation with Offsite Power Avaiiable (SSLBFP) 15.1.5-6 Assumptions and Initial Conditions for a Large Steam Line Break During Full Power Operation with Concurrent Loss of Offsite Power (SLBFPLOP) O ix Amendment No. 7 March 31, 1982
m - LIST OF TABLES (Continued) Chapter 15 i Subject Table 15.1.5-7 Assumptionsand Initial Conditions for a Large Steam Line Break During Full Power Operation with Offsite Power Available (SLBFP) 15.1.5-8 Assumptions and Initial Conditions for a Large Steam Line Break During Zero Power Operation with Concurrent Loss of Offsite Power (SLBZPLOP and SLBZPLOPD) 15.1.5-9 Assumptions and Initial Conditions for a Large Steam Line Break During Zero Power with Offsite Power Available (SLBZP) 15.1.5-10 Assumptions and Initial Conditions for a Small Steam Line Break Outside Containment During Full Power Operation with Offsite Power Available (SSLBFP) 15.1.5-11 Parameters used in Evaluating the Radiological Consequences of Steam Line Breaks Outside Containment Upstream of MSIV 15.2.3-1 Sequance ot events for the LOCV 15.2.3-2 Disposi t. ion of hormally Operating Systems for LOCV 15.2.3-3 Utilization of Safety System for LOCV 15.2.3-4 Assumed Initial Conditions for LOCV 15.3.1-1 Sequence of Events for Total Loss of Reactor Coolant Flow 15.3.1-2 Disposition of Normally Operating Systems for the Total Loss of Reactor Coolant Flow 15.3.1-3 Utilization of Safety Systems for the Total loss of Reactor Coolant Flow 15.3.1-4 Assumed Initial Conditions for Total Loss of Reactor Coolant Fl ow 15.3.3-1 Sequence of Events for the Single Reactor Coolant Pump Rotor Seizure with loss of Offsite Power Resulting from Turbine Trip 15.3.3-2 Disposition of Normally Operating Systems for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 9 x Amendment No. 7 March 31,1982
w LIST OF TABLES (Continued) Chapter 15 Table Subject 15.3.3-3 Utilization of Safety Systems for the Sinale Reactor Coolant Pump Trip Seizure with Loss of Offsite Power Resulting from Turbine Rotor 3 15.3.3-4 Assumed Initial Conditions for the Single Reactor Coolant Pump Rotor Trip Seizure with Loss of Offsite Power Resulting from Turbine 15.3.3-5 Parameters Used in Evaluating the Radiological Consequences of a ( Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-6 Secondary System Mass Release to the Atmosphere for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Event 15.3.3-7 E 5 Radiological Consequences of a Postulated Single Reactor Coolant Pump Turbine Rotor Trip Seizure with Loss of Offsite Power Resulting from O 15.4.1-1 Sequence of Events for the Sequential CEA Withdrawal Event 15.4.1-2 Disposition of Normally Operating Systems for the Sequential CEA Withdrawal at Low Power 15.4.1-3 Utilization of Safety Systems for the Sequential CEA Withdrawal at Low Power 15.4.1-4 Assumption and Initial Condition for the Low Power CEA Withdrawal Analysis 15.4.2-1 Sequence of Events for the Sequential CEA Withdrawal Event 15.4.2-2 Disposition of Herma11y Operating Systems for the Sequential CEA Withdrawal at Full Power 15.4.2-3 Utilization of Safety Systems for the Sequential CEA Withdrawal at Full Power 15.4.2-4 Assumptions and Initial Conditions for the Sequential CEA Withdrawal Analysis 15.4.3-1 Sequence of Events for the Single Full Length CEA Drop Event 15.4.3-2 Disposition Length of thrmally CEA Drop Operating Systems for the Single Full xi Amendment No. 7 March 31, 1982
LIST OF TABLES (Continued) Chapter 15 Tabl e Subject 15.4.3-3 Assumptions and Initial Conditions for the Single Full Length Central Element Assembly Drop 15.4.6-1 Assumption for the Inadvertent Deboration Analysis 15.4.8-1 Sequence of Events for the CEA Ejection Event 15.4.8-2 Disposition of Normally Operating Systems for the CEA Ejection Event 15.4.8-3 Utilization of Safety Systems for the CEA Ejection Event 15.4.8-4 Initial Reactor States Considered for the CEA Ejection Event 15.4.8-5 Assumption used for the CEA Ejection Analysis Full Power Beginning of Cycle Initial Conditions. 15.4.8-6 Parameters used in Evaluating the Radiological Consequences of a CEA Ejection 15.4.8-7 Secondary System Mass Release to the Atmosphere 15.4.8-8 Radiological Consequences of a Postulated CEA Ejection Event 15.5.2-1 Sequence of Events for the PLCS Malfunction with a Loss of Offsite Power at Turbine Trip 15.5.2-2 Disposition of Normally Operating Systems for the PLCS l Malfunction with Loss of Off-Site Power l 15.5.2-3 Utilization of Safety Systems for the PLCS Malfunction with Loss of Off-Site Power 15.6.2 1 Alarms that will be Actuated for the Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Control Valve Event 15.6.2-2 Sequence of Events for a Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Control Valve 15.6.2-3 Disposition of Normally Operating Systems for the Double Ended Break of a Letdown Line, Outside Containment, Upstream of the J Letdown Control Yalves Amend:..ent No. 7 xii March 31, 1982
m [ LIST OF TABLES (Continued) U Jhapter 15 Table Subject 15.3.3-3 Utilization of Safety Systems for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-4 Assumed Initial Conditions for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-5 Parameters Used in Evaluating the Radiological Consequences of a Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-6 Secondary System Mass Release to the Atmosphere for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Event 15.3.3-7 Radiological Consequences of a Postulated Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from 1 Turbine Trip 1' 15.4.1-1 Sequence of Events for the Sequential CEA Withdrawal Event < 15.4.1-2 Disposition of Normally Operating Systems for the Sequential CEA Withdrawal at Low Power 15.4.1-3 Utilization of Safety Systems for the Sequential CEA Withdrawal ; at Low Power i 15.4.1-4 Assumption and Initial Condition for the Low Power CEA Withdrawal Analysis f 15.4.2-1 Sequence of Events for the Sequential CEA Withdrawal Event 15.4.2-2 Disposition of Horma11y Operating Systems for the Sequential CEA Withdrawal at Full Power 15.4.2-3 Utilization of Safety Systems for the Sequential CEA Withdrawal I j at Full Power 15.4.2-4 Assumptions and Initial Conditions for the Sequential CEA , Withdrawal Analysis ' l 15.4.3-1 Sequence of Events for the Single Full Length CEA Drop Event 15.4.3-2 Dispositick of Normally Operating Systems for the Single Full l Length CEA Drop xi Amendment No. 7 March 31, 1982
LIST OF TABLES (Continued) Chapter 15 Table Subject 15.4.3-3 Assumptions and Initial Conditions for the Single Full Length Central Element Assembly Drop 15.4.6-1 Assumption for the Inadvertent Deboration Analysis 15.4.8-1 Sequence of Events for the CEA Ejection Event 15.4.8-2 Disposition of Normally Operating Systems for the CEA Ejection Event 15.4.8-3 Utilization of Safety Systems for the CEA Ejection Event 15.4.8-4 Initial Reactor States Considered for the CEA Ejection Event 15.4.8-5 Assumption used for the CEA Ejection Analysis Full Power Beginning of Cycle Initial Conditions. 15.4.8-6 Parameters used in Evaluating the P, radiological Consequences of a CEA Ejection 15.4.8-7 Secondary System Mass Release to the Atmosphere 15.4.8-8 Radio 1r,gical Consequences of a Postulated CEA Ejection Event 15.5.2-1 Sequence of Events for the PLCS Malfunction with a Loss of Offsite Power at Turbine Trip 15.5.2-2 Disposition of Normally Operating Systems for the PLCS Malfunction with Loss of Off-Site Power 15.5.2-3 Utilization of Safety Systems for the PLCS Malfunction with Loss of Off-Site Power 15.6.2-1 Alarms that will be Actuated for the Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Control Valve Event 15.6.2-2 Sequence of Events for a Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Control Valve 15.6.2-3 Disposition of Norpially Operating Systems for the Double Ended Break of a Letdown Line, Outside Containment, Upstr:eam of the Letdown Control Valves , xii Amendment No. 7 March 31, 1982
v
. LIST OF TABLES (Continued)
V Chapter 15 Table Subject 15.6.2-4 Utilization of Safety Systems for the Double Ended Break of a Letdown Line, Outside Containment, Upstream of the Letdown Control Valves j 15.6.2-5 Assumed Input Parameters and Initial Conditions for the Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Line Control Valve 15.6.3-1 Sequence of Events for the Steam Generator Tube Rupture l 15.6.3-2 Disposition of Normally Operating Systems for the Steam Generator ! Tube Rupture 15.6.3-3 Utilization of Safety Systems for the Steam Generator Tube l Rupture 15.6.3-4 Assumption and Initial Conditions for the Steam Generator Tube Rupture 15.6.3-5 Radiological Consequences of the Steam Generator Tube Rupture 15.6.3-6 Sequence of Events for the Steam Generator Tube Rupture with a Loss of Offsite Power 15.6.3-7 Disposition of Normally Operating Systems for the Steam Generatur Tube Rupture with a loss of Offsite Power 15.6.3-8 Utilization of Safety Systems for the Steam Generator Tube Rupture with a Loss of Offsite Power 15.6.3-9 Assumption and Initial Conditions for the Steam Generator Tube i Rupture with a Loss of Offsite Power 15.6.3-10 Radiological Consequences of a Steam Generator Tube Rupture with a Loss of Offsite Power 15.6.5-1 System 80 Radio Iodine and Noble Gas Activity Inventory in Containmer t Atmosphere 15.7.4-1 Parameters used in Evaluating the Radiological Consequences of a Fuel Handling Accident O Amendment No. 7 xiii March 31,1982
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1.IST OF FIGURES Chapter 15 d ure Sub.iec t 15.0-1A Sequence of Events-Symbols, Acronyms, and Definitions 15.n-18 Sequence of Events-Symbols, Acronyms, and Definitions 15.0-1C Sequence of Events-Symbols, Acronyms, and Definitions 15.1.4-1.1 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Core Power vs Time 15.1.4-1.2 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Core Average Heat Flux vs Time 15.1.4-1.3 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) RCS Pressure vs Time 15.1.4-1.4 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Reactor Coolant Flow Rate vs Time 15.1.4-1.5A Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Reactor Coolant Temperature ( A) vs Time 15.1.4-1.5B Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Reactor Coolant Temperature (B) vs Time 15.1.4-1.6 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Pressurizer Water Volume vs Time 15.1.4-1.7 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Steam Generator Pressures vs Time 15.1.4-1.8 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Steam Flow Rate to Atmosphere vs Time 15.1.4-1.9 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Steam Generator Steam Flow Rate vs Time 15.1.4-1.10 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Feedwater Flow Rates vs Time 15.1.4-1.11 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Feedwater Enthalpy vs Time 15.1.4-1.12 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Steam Generator Mass Inventories vs Time 15.1.4-1.13 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Steam Flow to Atmosphere vs Time xiv Amendment No. 7 March 31, 1982
i LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.1.4-1.14 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Volume Above Hot Leg vs Time
~15.1.4-1.15 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV)
Minimum DNBR vs Time l 15.1.4-2.1 10SGADV with Loss of Offsite Power after Turbine Trip i Core Power vs Time-15.1.4-2.2 IOSGADV with Loss of Offsite Power after Turbine Trip Core Average Heat Flux vs Time l 15.1.4-2.3 10SGADV with Loss of Offsite Power'after Turbine Trip RCS Pressure vs Time 15.1.4-2.4 10SGADV with Loss of Offsite Power after Turbine Trip Reactor Coolant Flow Rate vs Time
, 15.1.4-2.5A 10SGADV with Loss of Offsite Power after Turbine Trip
( Reactor Coolant Temperature ( A) vs Time 1 15.1.4-2.5B 10SGADV with Loss of Offsite Power after Turbine Trip Reactor Coolant Temperature (B) vs Time l 15.1.4-2.6 10SGADV with Loss of Offsite Power af ter Turbine Trip Pressurizer Water Volume vs Time 15.1.4-2.7 10SGADV with Loss of Offsite Power after Turbine Trip Steam Generator Pressures vs Time 15.1.4-2.8 10SGADV with Loss of Offsite Power after Turbine Trip Steam Flow to Atmosphere vs Time 15.1.4-2.9 10SGADV with Loss of Offsite Power after Turbine Trio Steam :enerator Steam Flow Rate vs Time i 15.1.4-2.10 10SGADV with Loss of Offsite Power after Turbine Trip Feedwater Flow Rates vs Time 15.1.4-2.11 10SGADV with Loss of Offsite Power af ter Turbine Trip Feedwater Enthalpy vs Time 15.1.4-2.12 10SGADV with Loss of Offsite Power after Turbine Trip ; Steam Generator Mass Inventories vs Time xv Amendment No. 7 March 31, 1982 !
l LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.1.4-2.13 10SGADV with Loss of Offsite Power after Turbine Trip Steam Flow to Atmosphere vs Time 15.1.4-2.14 10SGADV with Loss of Offsite Power after Turbine Trip Reactor Vessel Liquid Volume vs Time 15.1.4-2.15 10SGADV with Loss of Offsite Power after Turbine Trip Minimum DNBR vs Time 15.1.5-1.1 Full Power Large Steam Line Break. with Concurrent loss of Offsite Power Core Power vs Time 15.1.5-1.2 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Core Heat Flux vs Time 15.1. 5J . 3 Full Power Large Steam Line Break with Concurrent loss of Offsite i Power RCS Pressure vs Time 15.1.5-1.4 Full Power Large Steam Line Break with Concurrent loss of Offsite Power Reactor Coolant Flow Rate vs Time 15.1.5-1.5A Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Temperature (A) vs Time 15.1.5-1.5B Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Temperature (B) vs Time 15.1.5-1.6 Ft.'l Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactivity Changes vs Time 15.1.5-1.7 Full Power Large Steam Line Break with Concurrent loss of Offsite Power Pressurizer Water Volume vs Tine 15.1.5-1.8 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Steam Generator Pressures vs Time O xvi Amendment No. 7 March 31,1982
LIST OF FIGURES (Continued) ;
, Chapter 15 Figure Subject 15,1.5-1.9 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power ,
Steam Generator Blowdown Rates vs Time j 15.1.5-1.10 Full Power Large Steam Line Break with Concurrent Loss of Offsite 1 Power Feedwater rlow Rates vs Time 15.1.5-1.11 Full Pov.er Larp Steam Line Break with Concurrent Loss of Offsite Power Feedwater Enthalpy vs Time i 15.1.5-1.12 P 11 Power Large Steam Line Break with Concurrent loss of Offsite Power Steam Generator Mass Inventories vs Time 15.1.5-1.13 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Integrated Steam Mass Release Thru Break vs Time
- 15.1.5-1.14 Full Power Large Steam Line Break with Concurrent loss of Offsite p Power Safety Injection Flow vs Time 1
16.1.5-1.16 Full Power Large Steam Line Break with Concurrent loss of Offsite j Power Reactor Vessel Liquid Volume vs Time 15.1.5-1.16 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Minimum Post-Trip DNBR vs Time l 15.1.5-2.1 Full Power 'Large Steam Line Break with Offsite Power Available Core Power vs Time 15.1.5-2.2 Full Power Large Steam Line 'B eak with Offsite Power Available Core Hnat flux vs Time 15.1.5-2.3 Full Power Large Steam i.ine Break with Offsite Power Available RCS Pressure vs Time 15.1.5-2 A Full Power Large Steam Line Break with Offsite Power Available , Reactor Coolant Flow Ra'-.s vs Time i 15.1.5-2.5A Full Power large Steam Line Break with Offsite Power Available l ,m Reactor Coolant Temperatures ( A) vs Time , Amendment No. 7 "i March 31, 1982 l l l L--________-__-.__--_.___--__---
i I LIST OF FIGURES (Continued) Chapter 15 Fiaure Subiect 15.1.5-2.FB Full Power Large Steam Line Break with Offsite Power Available Reactor Coolant Temperatures (B) vs Time 15.1.5-2.6 Full Power Large Steam Line Break with Offsite Power Available Reactivity Changes vs Time 15.1.5-2.7 Full Power Large Steam Line Break with Offsite Power Available Pressurizer Water Volume vs Tirae 15.1.5-2.8 Full Power Large Steam Line Break with Offsite Power Available Steam Generator Pressures vs Tiine ] 15.1.5-2.9 Full Power Large Steam Line Break with Offsite Power Available Steam Generator Blowdown Rates vs Time i 15.1.5-2.10 Full Power Large Steam Line Break with Offsite Power Available Feedwater Flow Rates vs Time 15.1.5-2.11 Full Power Large Steam Line Break with Offsite Power Available Feedwater Enthalpy vs Time 15.1.5-2.12 Full Pov er Large Steam Lin' Break with Offsite Power Available Steam Generator Liqu' Mass vs Time 15.1.5-2.13 Full Power Large Steam Lin Break with Offsite Porr Available Integrated Steam kelease vs Time 15.1.5-2.14 Full Power Large Steam Line Break with Offsite Power Available Safety Injection Flow vs Time 15.1.5-2.15 Full Power Laroe Steam Line Break with Offsite Power Available Reactor Vessel Liquid Volume vs ilme 15.1.5-3.1 Zero Power Large Steam Line Break with Concurrent loss of Offsite Power l Core Power vs Timo l I 15.1.5-3.2 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Core Heat Flux vs Time 15.1.5-3.3 Zero Power Large Steam Line Break with Concurrent Loss of Offsite i Power ' RCS Pressure vs Time l O' l xviii Amendment No. 7 March 31, 1982 l > 1 ____o
v 6 O LIST OF FIGUPES_ (Continued) \ 0,. apter 15 Figure Subject 15.1.5-3.4 Zero Power Large Steam Line Break with Concurrent Loss of Offsite ; Power i Reactor Coolant Flow Rate vs Time 15.1.5-3.5A Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power J Reactor Coolant Temperatures ( A) vs Time l l 15.1.5-3.5B Zero Power Large Steam Line Break with Concurrent loss of Offsite l Power i Reactor Coolant Temperatures (B) vs Time l l 15.1.5-3.6 Zero Power Large Steam Line Break with Concurrent Loss of Offsite l Power I Reactivity Changes vs Time 15.1.5-3.7 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Pressurizer Water Volume vs Time O Q 15.1.5-3.8 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power l Steam Generator Pressures vs Time 15.1.5-3.9 Zero Power large Steam Line Break with Concurrent Loss of Offsite Power Steam Generator Blowdown Rates vs Time 15.1.5-3.10 Zero Power Large Steam Line Break with Concurrent loss of Offsite Power Feedwater Flow Rates vs Time 15.1.5-3.11 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Feedwater Enthalpy vs Time 15.1.5-3.12 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Steam Gene -*or Mass Inventor es vs Time 15.1.5-3.13 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Integrated Steam Mass Release Thru Break vs Time ,m 15.1.5-3.14 Zero Power Large Steam Line Break with Concurrent Loss of Offsite V) [ Power Safety Injection Flow vs Time xix Amendment No. 7 March 31, 1982
LIST OF FIGURES (Continued) ] Chapter 15 Figure Subject 15.1.5-3.15 Zero Power Large Steam Line Break with Concurrent loss of Offsite Power Reactor Vessel Liquid Volume vs Time 15.1.5-4.1 Zero Power Large Steam Line Break with Offsite Power Available Core Power vs Time 15.1.5-4.2 Zero Power Large Steam Line Break with Offsite Power Available Core Heat Flux vs Time 15.1.5-4.3 Zero Power Large Steam Line Break with Offsite Power Available ! RCS Pressure vs Time 15.1.5-4.4 Zero Power Large Steam Line Break with Offsite Power Available j Reactor Coolant Flow Rate vs Time 1 15.1.5-4.5A Zero P6ner Large Steam Line Break with Offsite Power Available Reactor Coolant Temperatures ( A) vs Time 15.1.5-4.5B Zero Power Large Steam Line Break with Offsite Power Available Reactor Coolant Temperatures (B) vs Time 15.1.5-4.6 Zero Power Large Steam Line Break with Offsite Power Available Reactivity Changes vs Time 15.1.5-4.7 Zero Power Large Steam Line Break with Offsite Power Available Pressurizer Water Volume vs Time 15.1.5 4.8 Zero Power Large Steam Line Break with Offsite Power Available , Steam Generator Pressures vs Time 1 15.1.5-4.9 Zero Power Large Steam Line Break with Offsite Power Available Steam Generator Blowdown Rates vs Time 15.1.5-4.10 Zero Power Large Steam Line Break with Offsite Power Available , Feedwater Flow Rates vs Time l l 15.1.5-4.11 Zero Power Large Steam Line Break with Offsite Power Available l Feedwater Enthalpy vs Time l l 15.1.5-4.12 Zero Power Large Steam Line Break with Offsite Power Available , Steam Generator Liquid Mass vs Time 15.1.5 4.13 Zero Power Large Steam Line Break with Offsite Power Available Integrated Steam Release vs Time 15.1.5-4.14 Zero Power Large Steam Line Break wito Offsite Power Available Safety Injection Flow u Time xx Amendment No. 7 March 31, 1982
v LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.1.5-4.15 Zero Power Large Steam Line Break with Offsite Power Available Reactor Vessel Liquid Volume vs Time 15.1.5-5.1 Full Power Small Steam Line Break with AC Power Available Core Power vs Time 15.1.5-5.2 Full Power Small Steam Line Break with AC Power Available Core Heat Flux vs Time 15.1.5-5.3 Full Power Small Steam Line Break with AC Power Available RCS Pressure vs Time 15.1.5-5.4 Full Power Small Steam Line Break with AC Power Available Core Flow Rate vs Time 15.1.5-5.5 Full Power Small Steam Line Break with AC Power Available Reactor Coolant Temperature vs Time 15.1.5-5.6 Full Power Small Steam Line Break with AC Power Available
-s Reactivity Changes vs Time 15.1.5-5.7 Full Power Small Steam Line Break with AC Power Available l Steam Generator Blowdown Rates vs Time l 15.1.5-5.8 Full Power Small Steam Line Break with AC Power Available Peactor Vessel Liquid Volume vs Time l 15.1.5-5.9 Full Power Small Steam Line Break with AC Power Available l DNBR vs Time 15.2.3-1A Sequence of Events Diagram for LOCV ,
15.2.3-1B Sequence of Events Diagram for LOCV i 15.2.3-1C Sequence of Events Diagram for LOCV l l 15.2.3-2 Loss Of Condenser Vacuum Core Power vs Time 15.2.3-3 Loss Of Condenser Vacuum Core Average Heat Flux vs Time 15.2.3-4 Loss Of Condenser Vacuum Reactivity vs Time 15.2.3-5 Loss Of Condenser Vacuum RCS Pressure vs Time 15.2.3-6 Loss Of Condenser Vacuum RCS Pressure vs Time s xxi Amendment No. 7 March 31, 1982 l l l
LIST OF FIGURES (Continued) ! Chapter 15 F_iqure Subject 15.2.3-7 Less Of Condenser Vacuum Core Average Coolant Temperature vs Time 15.2.3-8 Loss Of Condenser Vacuum Pressurizer Water Volume vs Time 15.2.3-9 Loss Of Condenser Vacuum Steam Generator Water Level vs Time 15.2.3-10 Loss Of Condenser Vacuum Stream Generator Pressure vs Time I 15.2.3-11 Loss Of Condenser Vacuum Steam Generator Pressure vs Time 15.2.3-12 Loss Of Condenser Vacuum Feedwater Flow vs Time 15.2.3-13 Loss Of Condenser Vacuum Total Steam Flow vs Time 15.2.3-14 Loss Of Condenser Vacuum Minimum DNBR vs Time 15.3.1-1A Sequence of Events Diagram for Total Loss of Reactor Coolant Flow 15.3.1-1B Sequence of Events Diagram for Total Loss of Reactor Coolant Flow 15.3.1-1C Sequence of Events Diagram for Total Loss of Reactor Coolant Flow 15.3.1-10 Sequence of Events Diagram for Total Loss of Reactor Coolant Flow 15.3.1-2 Total Loss of Reactor Coolant Flow Core Power vs Time 15.3.1-3 Total loss of Reactor Coolant Flow Core Average Heat Flux vs Time 15.3.1 4 Total Loss of Reactor Coolant Flow RCS Pressure vs Time 15.3.1-5 Total Loss of Reactor Coolant Flow Core Average Coolant Temperatures vs Time 15.3.1-6 Total Loss of Reactor Loolant Flow Reactivity vs Time 15.3.1-7 Total Loss of Reactor Coolant Flow Core Flow Fraction vs Time 15.3.1-8 Total Loss of Reactor Coolant Flow Right Hand & Left Hand Steam Generater Pressures vs Time 15.3.1-9 Total Loss of Reactor Coolant Flow CE-1 Minimum DNBR vs Time xxii Auendment No. 7 March 31,1982
q
)
i LIST OF FIGURES (Continued)
/ Chapter 15 \
Figure Subject 15.3.3-1A Sequence of Events Diagram for Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-1B Sequence of Events Diagram for Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-1C Sequence of Events Diagram for Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-10 Sequence of Events Diagram for Single Reactor Coolant Pump Rotor I Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-2 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Core Power vs Time 15.3.3-3 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Core Average. Heat Flux vs Time 15.3.3-4 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite O Power Resulting from Turbine Trip V RCS Pressure vs Time 15.3.3-5 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Core Average Coolant Temperature vs Time i 15.3.3-6 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Reactivity vs Time 15.3.3-7 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Core Flow Fraction vs Time 15.3.3-8 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Steam Generator Pressure vs Time 15.3.3-9 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip CE-1 Minimum DNBR vs Time 15.3.3-10 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite l Power Resulting from Turbine Trip ! p Steam Generatcrs Water Mass vs Time N Amendment No. 7 xxiii March 31,1982
l LIST OF FIGURES (Continued) , Chapter 15 Figure Subject 15.4.1-1A Sequence of Events for Uncontrolled Control Element Assembly Withdrawal from a Subcritical or Low Power Condition 15.4.1-1B Sequence of Events for Uncontrolled Control Element Assembly Withdrawal from a Subcritical or Low Power Condition 15.4.1-1C Seauence of Events for Uncontrolled Control Element Assembly Withdrawal from a Subcritical or Low Power Condition 15.4.1-2 Sequential CEA Withdrawal at Low Power Core Power vs Time 15.4.1-3 Sequential CEA Withdrawal at Low Power ; I Core Average Heat Flux vs Time 15.4.1 4 Sequential CEA Withdrawal at Low Power Reactor Coolant System Pressure vs Time 15.4.1-5 Sequential CEA Withdrawal at Low Power Minimum DNBR vs Time 15.4.1-6 Sequential CEA Withdrawal at Low Power Core Average Coolant Temperatures vs Time 15.4.1-7 Sequential CEA Withdrawal at Low Power Steam Generator Pressure vs Time 15.4.1-8 Sequential CEA Withdrawal at Low Power Linear Heat Generation Rate vs Time 15.4.2-1A Sequence of Event's Diagram for Uncontrolled Control Element Assembly Withdrawal at Power 15.4.2-1B Sequence of Events Diagram for Uncontrolled Control Element Assembly Withdrawal at Power 15.4.2-1C Sequence of Events Diagram for Uncontrolled Control Element i Assembly Withdrawal at Power 15.4.2-1D Sequence of Events Diagram for Uncontrolled Control Element ' Assembly Withdrawal at Power 15.4.2-2 Sequential CEA Withdrawal at Power Core Power vs Time i 15.4.2-3 Sequential CEA Withdrawal at Power Core Average Heat Flux vs Time ! xxiv Amendment No. 7 March 31, 1982
R i i LIST OF FIGtJRES (Continued)
/) i V Chapter 15 Figure Subject i 15.4.2-4 Sequential CEA Withdrawal at Power Reactor Coolant System Pressure vs Time 15.4.2-5 Sequential CEA Withdrawal at Power Minimum DNBR vs Time 15.4.2-6 Sequential CEA Withdrawal at Power Core Average Coolant Temperatures vs Time 15.4.2-7 Sequential CEA Withdrawal at Power Steam Generator Pressure vs Time i 15.4.2-8 Sequential CEA Withdrawal at Power Peak Linear Heat Generator Rate 15.A.?-9 Sequential CEA Withdrawal at Power Feedwater Enthalpy vs Time 15.4.2-10 Sequent #al CEA Withdrawal at Power Feedwater Flow vs Time O) y 15.4.2-11 Sequential CEA Withdrawal at Power l
Main Steam Safety Valve Flow vs Time 15.4.2-12 Senumtial CEA Withdrawal at Power
'otal Steam Flow vs Time 1
15.4.3-2 Sing e Full Length CEA Crop Core Power vs Time 15.4.3-3 Single Full Length CEA Drop I Core Average Heat Flux vs Time 15.4.3-4 Single Full Length CEA Drop Hot Channel Heat Flux vs Time 15.4.3-5 Single Full Length CEA Dro, Pressurizer Pressure vs Time 15.4.3-6 Single Full Length CEA Drop Minimum DNBR vs Time 15.4.3-7 Single Full Length CEA Drop Core Average Coolant Temperatures vs Time f f 15.4.3-8 Single Full Length CEA Drop
\- Steam Generator Water level vs Time xxv Amendment No. 7 March 31,1982 L__ _ _ - - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - -
m i LIST OF FIGURES (Continued) Chapter 15 Fi gu_re Subject 15.4.3-9 Single Full Length CEA Drop Steam Generator Pressure vs Tine 15.4.3-10 Single Full Length CEA Drop Total Steam Flow vs Time 15.4.3-11 Single Full Length CEA Drop Feedwater Flow vs Time 15.4.3-12 Single Full Length CEA Drop Feedwater Enthalpy vs Time 15.4.3-13 Single Full Length CEA Drop Linear Heat Generation Rate vs Time 15.4.6-1 Sequence of Events Diagram for Inadvertent Deboration 15.4.7-1 P anar Average Power Distribution Corresponding to Maximum i F Produced by a Fuel Assembly Misloading that is V detectable During Startup at 80C 15.4.8-1A Sequence of Events Diagram for CEA Ejection with Loss of Offsite Power 15.4.8-1B Sequence of Events Diagram for CEA Ejection with Loss of Offsite j Power 15.4.8-1C Sequence of Events Diagram for CEA Ejection with Loss of Offsite Power ] 1 15.4.8-1D Sequence of Events Diagram for CEA Ejection with Loss of Offsite Power 15.4.8-1E Sequence of Events Diagram for CEA Ejection with Loss of Offsite ) Power l 15.4.8-1F Sequence of Events Diagram for CEA Ejection with Loss of Offsite i Power l 15.4.8-2 CEA Ejection - Core Power vs Time
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15.4.8-3 CEA Ejection - Peak Core Power Density vs Time 15.4.8-4 CEA Ejection - Core Average Heat Flux vs Time Amendment No. 7 xxvi March 31, 1982
-v - LIST OF FIGURES (Continued) Chapter 15 Figure Subject
'V 15.4.8-5 CEA Ejection - Peak Hot Channel Heat Flux' vs Time 15.4.8-6 CEA Ejection - Hot and Average Channel. Fuel and Clad Temperature vs Time l 15.4.8-7 CEA Ejection - Reactivity vs Time 15.4.8-8 C'EA Ejection - RCS and Pressurizer Pressure vs Time 15.4.8-9 CEA Ejection - RCS and Pressurizer Pressure vs Time 15.4.8-10 CEA Ejection - Pressurizer Pressure vs Time 15.4.8-11 CEA Ejection - Steam Generator Pressure vs Time l 15.4.8-12 CEA Ejection - Steam Generator Pressure vs Time 15.4.8-13 CEA Ejection - Main Steam Safety Valve Flow vs Time 15.5.2-1A Sequence of Events Diagram for Pressurizer Level Control System l Malfunction with Loss of Offsite Power Following the Turbine Trip l
15.5.2-1B Sequence of Events Diagram for Pressurizer Level Control System l Malfunction with Loss of Offsite Power Following the Turbine Trip : 15.5.2-1C Sequence of Events Diagram for Pressurizer Level _ Control System Malfunction with Loss of Offsite Power Following _the Turbine Trip 15.5.2-10 Sequence of Events Diagram for Pressurizer Level Control System Malfunction with Loss of Offsite Power Following the Turbine Trip i 15.5.2-2 PLCS Malfunction with Loss of Offsite Power d Core Power vs Time i 15.5.2-3 PLCS Malfunction with Loss of Offsite Power Core Average Heat Flux vs Time 15.5.2-4 PLCS Malfunction with Loss of Offsite Power i Pressurizer Pressure vs Time 15.5.2-5 PLCS Malfunction with Loss of Offsite Power Core Average Coolant Temperature vs Time 15.5.2-6 PLCS Malfunction with Loss of Offsite Power Pressurizer Water Volume vs Time 15.5.2-7 PLCS Malfunction with Loss of Offsite Power Steam Generator Water Level vs Time 15.5.2-8 PLCS Malfunction with Loss of Offsite Power D Steam Generator Pressure vs Time , 15.5.2-9 PLCS Malfunction with Loss of Offsite Power Total Steam Flow vs Time Amendment No. 7 xxvii March 31,1982
1 i LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.5.2-10 PLCS Malfunction with Loss of Offsite Power Feedwater Flow vs Time 15.5.2-11 PLCS Malfunction with Loss of Offsite Power Feedwater Enthalpy vs Time 15.6.2-1A Sequence of Events Diagram for Double-Ended Letdown Line Break, Outside Containment, Upstream of Letdown Control Valve 15.6.2-1B Sequence of Events Diagram for Double-Ended Letdown Line ~ Break, Outside Containment, Upstream of Letdown Control Valve 15.6.2-1C Sequence of Events Diagram 'or Double-Ended Letdown Line Break, Outside Containment, Upstream of Letdown Control Valve 15.6.2-2 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Core Power vs Time 15.6.2-3 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Core Average Heat Flux vs Time 15.6.2-4 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Pressurizer Pressure vs Time 15.6.2-5 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Core Coolant Temperatures vs Time 15.6.2-6 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Steam Generator Pressure vs Tine 15.6.2-7 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Integrated Primary Coolant Discharge vs Time 15.6.2-8 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Pressurizer Water Level vs Time ] 1 15.6.2-9 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Reactor Coolant System Inventory vs Time i 15.6.2-10 Letdown Line Break, Outside Containment, Upstream of Letdown Line l Control Valve Steam Generator Water Level vs Time Amendment No. 7
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v LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.6.2-11 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Total Steam Flow vs Time 15.6.2-12 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Feedwater Flow vs Time 15.6.2-13 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Feedwater Enthalpy vs Time 15.6.2-14 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Minimum DNBR vs Time 15.6.3-1A Sequence of Events Diagram for Steam Generator Tube Rupture 15.6.3-18 Sequence of Events Diagram for Steam Generator Tube Rupture 15.6.3-1C Sequence of Events Diagram for Steam Generator Tube Rupture 1 15.6.3-1D Sequence of Events Diagram for Steam Generator Tube Rupture 15.6.3-2 Steam Generator Tube Rupture without Loss of Offsite Power Core Power vs Time 15.6.3-3 Steam Generator Tube Rupture without Loss of Offsite Power Core Heat Flux vs Time i i 15.6.3-4 Steam Generator Tube Rupture without Loss of Offsite Power RCS Pressure vs Time i l 15.6.3-5 Steam Generator Tube Rupture without Loss of Offsite Power RCS Temperatures vs Time l 15.6.3-6 Steam Generator Tube Rupture without loss of Offsite Power '. Pressurizer Water Volume vs Time i 15.6.3-7 Steam Generator Tube Rupture without Loss of Offsite Power Steam Generator Pressure vs Time 15.6.3-8 Steam Generator Tube Rupture without Loss of Offsite Power Total Steam Flow vs Time ' O E 15.6.3-9 Steam Generator Tube Rupture without Loss of Offsite Power O Feedwater Flow vs Time "i* Amendment No. 7 March 31, 1982
l l' LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.6.3-10 Steam Generator Tube Rupture without Loss of Offsite Power Feedwater Enthalpy vs Time 15.6.3-11 Steam Generator Tube Rupture without Loss of Offsite Power Steam Generator Liquid Mass vs Time 15.6.3-12 Steam Generator Tube Rupture without Loss of Offsite Power Main Steam Safety Valve Integrated Flow vs Time 15.6.3-13 Steam Generator Tube Rupture without Loss of Offsite Power RCS Inventory vs Time 15.6.3-14 Steam Generator Tube Rupture without loss of Offsite Power Tube Leak Rate vs Time 15.6.3-15 Steam Generator Tube Rupture without Loss of Offsite Power Integrated Leak F1ow vs Time 15.6.3-16 Steam Generator Tube Rupture without Loss of Offsite Power Liquid Volume Above Top of Hot leg vs Time 15.6.3-17 Steam Generator Tube Rupture without loss of Offsite Power Minimum DNBR vs Time 15.6.3-18A Sequence of Events Diagram for Steam Generator Tube Rupture with Loss of Offsite Power on Reactor Trip 15.6.3-18B Sequence of Events Diagram for Steam Generator Tube Rupture with loss of Offsite Power on Reactor Trip 15.6.3-18C Sequence of Events Diagram for Steam Generator Tube Rupture with Loss of Offsite Power on Reactor Trip 15.6.3-18D Sequence of Events Diagram for Steam Generator Tube Rupture with Loss of Offsite Power on Reactor Trip i 15.6.3-19 Steam Generator Tube Rupture without loss of Offsite Power Core Power vs Time 15.6.3-20 Steam Generator Tube Rupture without loss of Offsite Power Core Heat Flux vs Time 15.6.3-21 Steam Generator Tube Rupture without Loss of Offsite Power RCS Pressure vs Time 15.6.3-22 Steam Generator Tube Rupture without loss of Offsite Power Core Coolant Temperature vs Time Amendment No. 7
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LIST OF FIGURES (Continued) Chapter 15 Figure Subject ! l i 15.6.3-23 Steam Generator Tube Rupture without Loss of Offsite Power Pressurizer Water Volume vs Time 15.6.3-24 Steam Generator Tube Rupture without Loss of Offsite Power Steam Generator Pressure vs Time 1 15.6.3-25 Steam Generator Tube Rupture without Loss of Offsite Power Total Steam Flow Per Steam Generator vs Time 15.6.3-26 Steam Generator Tube Rupture without Loss of Offsite Power Feedwater Flow Per Steam Generator vs Time 15.6.3-27 Steam Generator Tube Rupture without Loss of Offsite Power Feedwater Enthalpy vs Time 15.6.3-28 Steam Generator Tube Rupture without Loss cf Offsite Power Steam Generator Mass vs Time 15.6.3-29 Steam Generator Tube Rupture without Loss of Offsite Power l MSSV Integrated Flow Per Steam Generator vs Time ' l ' 15.6.3-30 Steam Generator Tube Rupture without Loss of Offsite Power Reactor Coolant System Inventory vs Time 15.6.3-31 Steam Generator Tube Rupture without Loss of Offsite Power Tube Leak Rate vs Time 15.6.3-32 Steam Generator Tube Rupture without Loss of Offsite Power Integrated Leak Flow vs Time 15.6.3-33 Steam Generator Tube Rupture without Loss of Offsite Power Liquid Volume Above Top of Hot Legs vs Time 15.6.3-34 Steam Generator Tube Rupture without Loss of Offsite Power Minimum DNBR vs Time l l C\ O \ i
*i Amendment No. 7 March 31, 1982
m i O THIS PAGE INTENTIONALLY BLANK, 9 O l
- 15. ACCIDENT ANALYSES 15.0 ORGANIZATION AND METHODOLOGY This chapter presents analytical evaluations of the Nuclear Steam Supply System (NSS$) response to postulated disturbances in process variables and to postulated malfunctions or failures of equipment. Such incidents (or events) are postulated and their consequences analyzed despite the many precautions which are taken in the design, construction, quality assurance, and plant operation to prevent their occurrence. The effects of these incidents are examined to determine their consequences and to evaluate the capability built into the plant to control or accommodate such failures and situations.
15.0.1 CLASSIFICATION OF TRANSIENTS AND ACCIDENTS 15.0.1.1 Format and Content This chapter is structured according to the format and content suggested by Reference 1 and required by Reference 26. 15.0.1.2 Event Categories Each postulated initiating event has been assigned to one of the following categories;
- a. Increased Heat Removal by Secondary System,
- b. Decreased Heat Removal by Secondary System,
- c. Decreased Reactor Coolant Flow,
- d. Reactivity and Power Distribution Anomalies,
- e. Increase in RCS Inventory,
- f. Decrease in RCS Inventory,
- g. Radioactive Release from a Subsystem or Component, or
- h. Anticipated Transients Without Scram ( ATWS).
1 Definition of an arcropriate evaluation basis and acceptance criteria does l not presently exist for ATWS, therefore, these events are not addressed in this chapter. The assignment of an initiating event to one of these eight categories is made according to Reference 26. 15.0.1.3 Event Frequencies Reference 26 subjectively classifies initiating events in the following qualitative frequency groups: O 15.0-1 Amendment No. 7 March 31, 1982
A. Moderate Frequency Events B. Infrequent Events C. Accidents l 15.0.1.4 Events and Event Combinations i The events and event combinations in this chapter are those identified by Reference 26, and are presented with respect to the event specific acceptance q criteria specified therein. For each applicable acceptance criterion in an : event category, only the limiting event or event combination is presented in f analytical detail. Qualitative discussions are provided for all other events I or event combinations explaining why they are not limiting. j j For event combinations which require consideration of a single failure, the limiting failure is selected from those listed in Table 15.0-6. Only low probability dependent failures (e.g., loss of offsite power following turbine ! trip) and independent pre-existing failures are considered credible and 1 included in the table. Pre-existing failures are equipment failures existir.g prior to the event initiation which are not revealed until called upon during the event (e.g., a failure of an emergency feedwater pump). High probability dependent occurrences are always included in the event analysis, if they have ' an adverse impact (e.g., loss of main feedwater pumps following a loss of electric power). 15.0.1.5 Section Numbering The incidents analyzed in this chapter are presented in sections in accordance with Reference 26 and are numbered as described in Table 15.0-2, 15.0.1.6 Sequence of Events Analysis The purpose of the Sequence of Events and Systems Operation section provided for each limiting event in this chapter is to provide:
- 1. "The step-by-step sequence of events from event initiation to the final i stabilized condition,
- 2. The extent to which normally operating plant instrumentation and controls are assumed to function,
- 3. The extent to which plant and reactor protection systems are required to function,
- 4. The credit taken for the functioning of normally operating plant systems, (and)
- 5. The operation of engineered safety systems that is required, (1)" as well as (
O Amendment No. 7 - 15.0-2 March 31, 1982 I
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- 6. "A summary of a systematic functional analysis of components required for each event analyzed in Chapter 15. The summary should be shown in the form of simple block diagrams beginning with' the event, branching out to the various possible protection sequences for each safety action required to s mitigate the consequences of the event (e.g., core cooling, containment isolaion, pressure relief, scram, etc.), and ending with an identification of the specific safety actions being provided. (24)"
A detailed Sequence of Events Analysis (SEA) has been performed for each limiting event for which detailed results are presented in this chapter. SEA has been specifically omitted for those events which, though representing limiting events for their category do not result in the actuation of safety systems or for which a detailed, quantitative analysis was not presented. The results of the analysis are presented in the form o' three tables and a figure , for each event. The first table in each Sequence or Events and Systems l Operation section (15.X.Y-1) presents a chronological list of events which l occur during the transient and the time at which they occur, from the initiation of the event to the achievement of cold shutdown conditions. The second table (15.X.Y-2) is a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient. The results of the SEA are summarized in the Sequence of Events Diagram (SED) and in a third table (15.X.Y-3) which specifies the reactor protection and engineered safety feature systems' which are actuated, to accomplish safety functions, during the course of the transient. The SED together with the chronological list of events and the SEA symbol and acronym drawing (Figure 15.0.-1) may be used to trace the actuation and interaction of the systems used to mitigate the consequences of each event. l The SED is a block diagram, composed of several success paths which define a set of safety actions leading from the initiating event to the accomplishment of a specific safety function. All of the safety functions used in the SED's are defined in Figure 15.0-1. A success path may be composed of two branches, one indicated by a solid line, describing the Sequence of Events which occur in the transient analysis and the other, indicated by a dotted line, describing an alternative or back-up path to a given means of accomplishing a safety function. An alternate dotted path is specified if the analysis assumed the action of a non-safety system in achieving a particular safety function. Non-safety systems are indicated by an "NS" in the upper right-hand corner of the system block. The redundancy of a system or component is indicated by a fraction (e.g.,1/2, 2/4) placed beneath the system block. The numerator specifies the number of trains or components required to perform the action and the denominator specifies the number of trains or components available. In cases where no alternate path exists and a single system or component is included in a success path, the symbol "S.F." will be used to indicate that no single active failure will prevent the accomplishment of the safety action. Components or systems which require no active initiation or actuation to perform their function are considered to be passive and are marked as such with ,- a "P" in the lower left-hand corner of the system block. The absence of a l passive label implies that.a component is considered to be active and must be actively initiated to perform its function. O Amendment No. 7 15.0-3 March 31, 1982
Manual operations performed on a given system or component are indicated by placing an "M" in the lower left-hand corner of the system block. When a manual action is required, the sensed variables necessary to perform the action are shown as inputs and the location of the input signal is shown above the input signal circle. The system setpoint values assumed in the transient analysis, e.g., trip signal setpoints, will be noted along the success path. Time delays or the time required to perform an action are shown as a number with square brackets. All events presented in Sequence of Events Diagrams (SED) in this chapter are shown from event initiation to achievement of the Cold Shutdown operating mode (see Chapter 16). Not all events require that the plant be taken to Cold Shutdown. The SED's only demonstrate that for any event presented here it is possible to take them to Cold Shutdown by means of the safety actions indicated. 15.0.2 SYSTEMS OPERATION During the course of any event various systems may be called upon to function. Some of these systems are described in Chapter 7 and include those electrical, instrumentation, and control systems designed to perform a safety function (i.e., those systems which must operate during an event to mitigate the consequences) and those systems not required to perform a safety function (see Sections 7.? through 7.6 and 7.7, respectively). The Reactor Protection System (RPS) is described in Section 7.2. Table 15.0-4 lists the RPS trips for which credit is taken in the analyses discussed in this section, including the setpoints and the trip delay times associated with each trip. The analyses take into consideration the response times of actuated devices after the value of the monitored parameter at the sensor equals or exceeds the trip setpoint. The reactor protective system response time is the sum of the sensor response time and the reactor trip delay time. The sensor response time is defined as the time frem when the value of the monitored parameter at the sensor equals 10 or exceeds the reactor protective system trip setpoint until the sensor outpr equals or exceeds the trip setpoint. The sensor response is modeled by using ! a transfer function for the particular sensor used. The reactor trip delay I time (Table 15.0-4) is defined as the elapsed time from the time the sensor j output equals or exceeds the trip setpoint to the time the reactor trip I breakers are fully cpen. The interval between trip breaker opening and the time at which the magnetic flux of the Control Element Assembly (CEA) holding coils has decayed enough to allow CEA motion is conservatively assumed to be 0.34 seconds. Finally, a conservative value of 3.66 seconds is assumed for CEA insertion, defined as the elapsed time from the beginning of CEA motion to the time of 90% insertion 4 of the CEAs in the reactor core. j The Engineered Safety Feature Actuation Systems (ESFAS) and electrical, instrumentation, and control systems required for safe shutdown are described in Sections 7.3 and 7.4, respectively. The manner in which these systems function during events is discussed in each event description. The instrumentation which is required to be available to the operator in order to assist him in evaluating the nature of the event and determining requfred ; action is described in Section 7.5. The use of this instrumentation by the operator is discussed in each event description. 15.0-4 Amendment No. 10 l June 28, 1985
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p Other systems called upon to function are described in Chapters 6, 9, and in
;v) the Applicants SAR. The utilization of these systems is described in the Sequence of Events section of each presentation.
Systems which may but are not required to perform safety functions are described in Section 7.7. These include various control systems and the Core Operating Limit Supervisory System (COLSS). In general, normal automatic operation of these control systems is assumed unless lack of operation would ! make the consequences of the event more adverse. In such cases, the particular j control system is assumed to be inoperative, in the manual mode, until the time of operator action. 15.0.3 CORE AND SYSTEM PERFORMANCE 15.0.3.1 Mathematical Model The Nuclear Steam Supply System (NSSS) response to various events was simulated using digital computer programs and analytical methods most of which are documented in Reference 2 and have been approved for use by the NRC by l Reference 3. l 15.0.3.1.1 Loss of Flow Analysis Method 1 The method used to analyze events which are initiated by failures which cause a decrease in reactor coolant flowrate is discussed in Appendix 15A. 15.0.3.1.2 CEA Ejection Analysis Method b]
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The method used for analysis of the reactivity and power distribution anomalies initiated by a CEA ejection (Section 15.4.5) is documented in Reference 16, Topical Report CENPD-190A, which was approved by the NRC for reference in license applications on June 10, 1976. 15.0.3.1.3 CESEC Computer Program The CESEC 11 computer program is used to simulate the NSSS (unless specified otherwise for an event). CESEC 11 is a version of CESEC which incorporates the ATWS model modifications documented in Reference 8 through 12 and includes additional improvements which extend the range of applicability of the models. The CESEC computer code is documented in Reference 7. CESEC 11 computes key system parameters during a transient including core neat flux, pressures, temperatures, and valve actions. A partial list of the l dynamic functions included in this NSSS simulation includes: point kinetics I neutron behavior, Doppier and moderator reactivity feedback, boron and CEA reactivity effects, multi-node average and hot channel reactor core thermal hydraulics, reactor coolant pressurization and mass transport, reactor coolant system safety valve behavior, steam generation, steam generator water level, turbine bypass, main steam safety and turbine admission valve behavior, as well as alarm, control, protection, and engineered safety feature systems. The steam turbines, condensers and their associated controls are not included in . p the simulation. Steam generator feedwater enthalpy and flowrate are provided as input to CESEC II. 15.0-5 Amendmerit No. 7 March 31, 1982
- - - - - - - - - - _ - - - - - _J
During the course of execution, CESEC II obtains steady-state and transient solutions to the set of equations that mathematically describe the physical models of the subsystems mentioned above. Simultaneous numerical integration of a set of nonlinear, first-order differential equations with time-varying coefficients is carried out by means of a simultaneous solution. As the time variable evolves, edits of the principal systems parameters are printed at prospecified intervals. An extensive library of the thermodynamic properties of uranium dioxide, water, and zircaloy is incorporated into this program. Through the use of CESEC-II, symmetric and asymmetric plant response over a wide range of operating conditions can be determined. The CESEC-III version of CESEC used in some of the analyses explicitly models the steam void formation and collapse in the upper head region of the reactor vessel and is documented in Reference 27. Other improvements to this version of CESEC include: a more detailed thermalhydraulic model which explicitly simulates the mixing in the reactor vessel from asymmetric transients, an RCS flow model which calculates the time dependent reactor coolant mass flow rate in each loop, a wall heat model, 3-D reactivity feedback model, a safety injection tank model, and a primary-to-secondary heat transfer model which calculates the heat transfer for each generator node rather than for a steam generator as a whole. 15.0.3.1.4 C0AST Computer Program The C0AST computer program is used to calculate the reactor coolant flow coastdown transient for any combination of active and inactive pumps and forward or reverse flow in hot or cold legs. The program is described in Reference 13 and was referenced in Reference 2. The equations of conservation of momentum are written for each of the flow paths of the C0AST model assuming unsteady one-dimensional flow of an incompressible fluid. The equation of conservation of mass is written for the appropriate nodal points. Pressure losses due to friction, and geometric losses are assumed propor tional to the flow velocity squared. Pump dynamics are modeled using a head-flow curve for a pump at full speed and using four-quadrant curves, which are parametric diagrams of pump head and torque on 4 coordinates of speed versus flow, for a pump at other than full speed. l 15.0.3.1.5 STRIKIN-II Computer Program The STRIKIN-II computer program is used to simulate the heat conduction within reactor fuel rods and its associated surface heat transfer. The STRIKIN-II program is described in Reference 14. The STRIKIN-II computer program provides a single, or dual, closed channel model of a core flow channel to calculate the clad and fuel temperatures for an average or hot fuel rod, and the extent of the zirconium water reaction for a cylindrical geometry fuel rod. STRIKIN-II includes: ; A. Incorporation of all major reactivity feedback mechanisms ' B. A maximum of six delayed neutron groups l l 15.0-6 Amendment No. 7 March 31, 1982
v i i C. Both axial (maximum of 20) and radial (maximum of 20) segmentation of the 'l b V fuel element i D. Control rod scram initiation on high neutron power. l l 15.0.3.1.6 TORC Computer Program The TORC computer program is used to simulate the fluid conditions within the ! reactor core and to calculate fuel pin DNBR. The TORC program is described in i l l References 18 and 21 and was refererced in Reference 2. l l 15.0.3.1.7 Reactor Physics Computer Frograms J Numerous computer programs are used to produce the input reactor physics parameters required by the NSSS simulation and reactor core programs previously 1 described. These reactor physics computer programs are described in Chapter 4. l; 15.0.3.2 Initial Conditions The events discussed in this chapter have been analyzed over a range of initial values for the principal process variables. The ranges were chosen to encompass all steady state operational confi3 urations (with the exception nf part loop operation). Analysis over a range of initial conditions is compatible with the monitoring l function performed by the COLSS which is described in Section 7.7 and the O flexibility of plant operation which the COLSS allows. This flexibility is - produced by allowing parameter trade-offs by monitoring the prinicipal process V variables, synthesizing the margin to fuel thermal design limits, and displaying to the reactor operator the core power operating limit. The required margin to DNB incorporated in COLSS is currently established by the total loss of forced reactor coolant flow as described in Appendix 15A. The ; required margin to DNB is based on the total loss of forced reactor coolant flow since this initiating event produces the most rapid loss of margin to DNB l before reactor trip and the maximum loss of margin to DNB after reactor trip. The peak linear heat generation rate incorporated in COLSS is established by the loss of coolant accident (LOCA). The range of values of each of the prinicipal process variables that was considered in analyses of events discussed in this chapter is listed in Table 10."-5. 15.0.3.3 Input Parameters The parameters used in the analyses are consistent with those listed in the preceding section and are primarily based on first-core values. 15.0.3.3.1 Doppler Coefficient The effective fuel temperature coefficient of reactivity (Doppler Coefficient) as shown in Section 4.3 is multiplied by a weighting factor to conservatively-account for higher feedback effects in the higher power density portions of the core and to account for uncertainties in determining the actual fuel , temperature reactivity effects. The Doppler weighting factor, which is ' O Amendment No. 7 15.0-7 March 31, 1982 l
specified for each analysis, is 0.85 for cases where a less negative Doppler feedback prrduces more adverse results and 1.15 for cases where a more negative Doppler feedback produces more adverse results. The effective fuel temperature correlation is discussed in Section 4.3. This correlation relates the effective fuel temperature, which is used to correlate Doppler reactivity, to the core power. 15.0.3.3.2 Moderator Temperature Coefficient The events analyzed in this Chapter model moderator reactivity as a function of moderator temperature instead of a moderator temperature coefficient. This method is used in order to more accurately calculate reactivity feedbacks due to the large moderator temperature variations which may occur during these events. The moderator temperature coefficients corresponding to these moderator reactiv =594*F) range from 0.0*10-{ty Ap functions at ngminal
/F to -3.5*10 Ap /F. full power conditions (TThese values include aiTeuncer and bound the expected moderator temperature coefficients for all first cycle burnups, power levels, CEA configurations, and boron concentrations.
The most conservative, allowable value for the moderator temperature coefficient is assumed for each individual analysis. 15.0.3.3.3 Shutdown CEA Reactivity The shutdown reactivity is dependent on the CEA worth available on reactor trip, the axial power distribution, the position of the regulating CEAs, and the time in core lite. For transient analyses other than CEA ejection and Increase in Heat Removal (Sections 15.1), conservative. CEA worths of 10.0 percent and 6.4 percent op were used for hot full power (HFP) and hot zero power (HZP), respectively. For CEA ejection events a conservative value of 3.81 percent Ap was used for HFP and conditions. The foregoing values include uncertainties, the most reactive CEA stuck in the fully withdrawn position, and the effect of cooldown to HZP temperature conditions (Sub-section 4.3.2.4.3). For Section 15.1 analyses at full power, a conservative CEA worth of 8.8 percent was used. This value is appropriate for end of equilibrium core, self-generated plutonium re-cycle (SGR) and includes uncertainties and the penalties appropriate to HFP as indicated in Table 4.3-7. For Section 15.1 events initiated from HZP, a conservative CEA worth of 6.0 percent was sufficient to preclude significant post-trip return-to-power. This value ; covers uncertainties, the most reactive CEA stuck in the fully withdrawn ! position, and the penalties appropriate to HZP as indicated in Table 4.3.6. ' The power dependent insertion limit (PDIL) which will be included in the Technical Specifications assures that these worths are available upon reactor trip. The shutdown reactivity worth versus position curve which is employed in the Chapter 15 analyses, except where noted in individual discussions of events, is shown in Figure 15.0-2. This shutdown worth versus position curve was calculated assuming a more conservative rate of negative reactivity insertion than is expected to occur during the majority of operations, including power 15.0-8 Amendment No. 7 l March 31, 1982
v 3 l maneuvering. Accordingly, it is a conservative representation of shutdown p reactivity insertion rates for reactor trips which occur as a result of the , events analyzed. 15.0.3.3.4 Effective Delayed Neutron Fraction The effective neutron lifetime and delayed neutron fraction are functions of fuel burnup. For each analysis, the values of the neutron lifetime and the ) delayed neutron fraction are selected consistent with the time in life analyzed. 15.0.3.3.5 Decay Heat Generation Rate Analyses assume decay heat generation based upon an infinite reactor operation at the initial core power level identified for each event. 15.0.4 RADIOLOGICAL CONSEQUENCES Several of the events discussed are accompanied by the release of steam or liquid from the reactor coolant system or main steam system. The methodology and inportant input parameters used to assess the radiological consequences of , these releases are discussed below. The CESEC computer code (described in Section 15.0.3.1.3), in combination with hand calculations, were used to determine the mass and energy releases as i a function of time. These data are then used as input to the calculation of j pI radiological release to the atmosphere for determining thyroid and whole body doses at the exclusion area boundry, (d The assumptions used for calculating radiological releases to the atmosphere follow.
- 1. The initial primary system activity level is based on the maximum activity in the reactor coolant due to continuous full power operation with 1%
fai 10-}edfuel. Thisdose Curies /lbm activity level corresponds equivalent I-131. to a concentration of 2.09 x
- 2. The initial secondary system activity level is equal to 4.54 x 10-5 Ci/lbm dose equivalent I-131.
- 3. Primary-to-secondary steam generator tube leakage is included in the calculation of activity releases to atmosphere from the steam generators.
The " technical specification leakage" discussed in the analyses of Chapter 15 is a 1 gpm primary-to-secondary tube leak. l 4. Events for which Reference 26 requires consideration of " iodine spiking" the following are used: A. For iodine spiking generated by the event, the iodine appearance rate is increased by a factor of 500. p B. For an abnormally high iodine concentration due to a previous iodine spike, a reactor coolant activity of 2.72 X 10~2 Ci/lbm dose l 6 V) equivalent I-131 is assumed. 1 15.0-9 Amendment No. 7 March 31, 1982
The dose at the site exclusion area boundary (EAB) is calculated as follows:
- 1. Multiply the total primary system mass release by the prnary system activity level and divide by the appropriate Decontamination Factor (DF).
This gives the total number of dose equivalent I-131 curies released from the primary system.
- 2. For the applicable secondary system releases, multiply the total secondary system mass release by the secondary system activity level and divide by the appropriate DF to obtain the equivalent 1-131 curies released to the envi ronment.
- 3. The ories of dose equivalent I-131 released to the environment can be converted to a thyroid dose by multiplying by the following factors:
- a. Breathing rate = 0.347 x 10-3 m 3/sec(Reference 2)
- b. Atmospheric dispersion factor (X/Q) = 2.00 x 10-3 sec/m 3
- c. 1-131 dose conversion factor = 1.48 x 10 6rem /Ci Combining these parameters gives an effective dose conversion factor equal to 1.027 rem /Ci. Thus, the total thyroid dose is calculated by multiplying the total activity release (dose equivalent I-131 curies) by the effective dose conversion factor (1.027 rem /Ci).
- 4. Additional assumptions used in the determination of radiological releases to the atmosphere for certain e'ents are:
- a. For pipe breaks outside containment in piping connected to the reactor coolant system, the release to atmosphere accounts for the formation of steam resulting from depressurization of the reactor coolant.
- b. For pipe breaks or valve malfunctions outside containment in the main steam system which result in eventual dry-out of a steam generator, radioactive nuclides within the steam generator are assumed to be released to atmosphere with a decontamination factor (DF) equal to 1.
O I Amendment No. 7 15.0-10 March 31, 1982
-v REFERENCES FOR SECTION 15.0_
- 1. NRC Regulatory Guide ). 70, Revision 2, " Standard Format and Content of-Safety Analysl5 Reports for Nuclear Power Plants," September 1975.
- 2. " Combustion Engineering Standard Safety Analysis Report," CESSAR Docket No. STN-50-470, December 1975.
- 3. Combustion Engineering Standard Safety Analysis Report (CESSAR) " System 80 Nuclear Steam Supply System Standard Nuclear Design Preliminary Design Approval," PDA-2, Docket No. STN 50 470, NRC, December 31, 1975. ,
- 4. "C-E Methods for loss of Flow Analysis," CENPD-183, July 1975.
- 5. Typical Balance of Pir.nt Design. See Applicants SAR
- 6. Revision'1, " Analyses of Anticipated Transients Without Reactor Scram in Combustion Engineering NSSSs," CENPD-158, May 1976.
- 7. "CESEC Digital Simulation of a Combustion Engineering Nuclear Steam Supply System," CENPD-107, April 1974, Proprietary Information.
- 8. "ATWS Model Modifications to CESEC," CENPD-107, Supplement 1, September 1974, Proprietary Information.
- 9. "AIWS Models Modification to CESEC" CENPD-107, Supplement 1, Amendment 1-P, November 1975, Proprietary Information.
- 10. "ATWS Model for Reactivity Teedback and Effect of Pressure on Fuel,"
CENPD-107, Supplement 2, September 1974, Proprietary Information.
- 11. "ATWS Model Modifications to CESEC," CENPD-107, Supplement 3, Auoust 1975.
l
- 12. "ATWS Model Modifications to CESEC," CENPD-107, Supplement 4-P, December 1975, Proprietary Information.
- 13. "C0AST Code Description," CENPD-98, April 1973, Proprietary Information.
- 14. "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program,"CENPD-135, April 1974 (Proprietary).
I "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program (Modification)," CENPD-135, Supplement 2, December 1974 (Proprietary).
"STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program," CENPD-135, Supplement 4, August 1976 (Proprietary). l
- 15. " Calculative Methods for the C-E Large Break LOCA Evaluation Model," CENPD-132, Supplement 1, December 1974 (Proprietary).
- 16. "C-E Method for Control Element Assembly Ejection Analysis," CENPD-190-A, January 1976.
Amendment No. 7 15.0-11 March 31, 1982
- 17. "HERMITE A Multi-Dimensional Space-Time Kinetics Code for PWR Transients,"
CENPD-188, March 1976, Proprietary Information. (
- 18. " TORC Code - A Computer Code for Determining the Thermal Margin of a Reactor Core," CENPD-161-P, July 1975, Proprietary Information.
- 19. "CE Critical Heat Flux - Critical Heat Flux Correlation for CE Fuel Assemblies with Standard Space Grids," CENPD-162-P, April 1975, Proprietary Informa tion.
- 20. " Loss of Flow - CE Methods for Loss of Flow Analysis," CENPD-183, July 1975, Proprietary Information.
- 21. " TORC Code-- Verification and Simplified Modeling Methods," CENPD-206-P, '
January 1977, Propietary Information.
- 22. " Iodine Spiking," CENPD-180, March 1977.
- 23. " Radioactive Behavior in the RCS Ouring Transientt Operations," Supplement 1 to CENPD-180 March 1977. !
- 24. "RESAR 3-S Round 1 Questions"
- 25. Wash .1400, " Reactor Safety Study - An Assessment of Accident Risks in U.S. ammercial Nuclear Power Plants," October,1975.
- 26. NUREG- 5/087, " Standard Review Plan for the Review of Safety Analysis Report < for Nuclear Power Plants," as revised through December 31, 1978.
- 27. LD-82-001 (dated 1/6/82), "CESEC Digital Simulation of a Combustion 1 Engineering Nuclear Steam Supply System", Enclosure 1-P to letter fram A. E. Scherer to D. G. Eisenhut, December, 198i.
i 1 i 1 i O Amendment No. 7 15.0-12 March 31,1982 I
TABLE 15.0-1 O (This table intentionally blank) O 1 I O Amendment No. 7 March 31,1982
TABLE 15.0-2 CHAPTER 15 SUBSECTION DESIGNATION Each subsection is identified as 15.W.X.Y. With trailing zeros omitted where: W=1 Increase in heat removal by the secondary system 2 Decrease in heat removal by the secondary system 3 Decrease in reactor coolant system flowrate 4 Reactivity and power distribution anomalies 5 Increase in reactor coolant inventory 6 Decrease in reactor coolant i'iventory 7 Radioactive release from a subsystem or component X = 1,2, etc. Event Title from Ref. 26 Y=1 Identification of causes and frequency classifications 2 Sequence of events and systems operation 3 Analysis of effects and consequences 4 Conclusions O' I O Amendment No. 7 March 31, 1982 J ___-_________A
TABLE 15.0-3 1 (This table intentionally blank) l l l l l l l l Amendment No. 7 March 31, 1982 1 l
TABLE 15.0-4 REACTOR PROTECTION SYSTEM TRIPS USED IN THE SAFETY ANALYSIS Reactor Analysis II) Trip 10 Event RPS Setpoint Delay Time (c) High logarithmic Power Level 2% 550 ms Variable Overpower 17% or 130%( ) ' High Pressurizer Pressure 2450 psia 550 ms Low Pressurizer Pressure 1580 psia 550 ms Events not Low Steam Generator Pressure 820 psia 550 ms Mentioned Below Low Steam Generator Water Level 40% wide range (b) 550 ms High Steam Generator Water Level 99%nggyow 550 ms range Low DNBR 1.19 150 ms High Local Power Density 21 150 ms Steam Generator AP Low Flow 90%gft(d) (h) 10 Variable Overpower 17% or 130%(a) Feedwater and High Pressurizer Pressure 2475 psia 550 ms Steam Line Breaks low Pressurizer Pressure 1600 psia 550 ms Low Steam Generator Pressure 810 psia 550 ms low Steam Generator Water Level 35% wide range (b) 550 ms High Steam Generator Water Level 99%n{gyow 550 ms range Low DNBR 1.19 150 ms High Local Power Density 21 kw/ft (d) 150 ms
- a. See discussion in Section 7.2.
1
- b. Percent of distance between the wide range instrument taps above the lower tap. See Chapter 5 for details.
i
- c. The reattor trip delay times are also discussed in Section 7.2.
10 ,
- d. Setpoint value is set below the value at which fuel centerline melting would I occur. See Section 4.4 i
- e. Percent of distance between the narrow range instrument taps above the lower tap. See Chapter 5 for details.
- f. Some Chapter 15 analyses assumed more conservative setpoints for specific events.
- g. Perce,t of hot leg flow. 10
- h. 1.0 second from time of occurrence of low flow trip condition until the reactor trip breakers open.
Amendment No. 10 June 28, 1985
/ '
TABLE 15.0-5 INITIAL CONDITIONS Parameter Units Range Core Power % of'3800 Mwt 0 - 102 4 Radial 1-pin peaking - 1.40 to 1.63 factor (with uncertainty) Axial Shape Index -0.3 _
< ASI < + 0.3 Reactor Vessel Inlet % of 445600 95 - 116 Coolant Flowrate Pressurizer Water % distance between 26 to 60 Level upper tap and lower I l
tap above lower tap 1 Core Inlet Coolant F 500 - 580 (2) Temperature Reactor Coolant System psia 1785 - 2400 Pressure Steam Generator Water % distance between 40 - 88 Level upper tap and lower tap above lower tap area under axial shape in lower half of core
- area under axial shape in upper half of core (1) ASI = total area under axial shape 1
(2) Additional restrictions were applied to: Section 15.2.3, minimum core inlet c'oolant temperature above 90% power equals 560 F; and Section 15.1.5, 10 maximum core inlet coolant temperature equals 570*F. l 1 1 n 1 IQ) Amendment No. 10 June 28, 1985
l TABLE 15.0-6 J SINGLE FAILURES STEAM BYPASS CONTROL SYSTEM
- 1. Failure to Modulate Open
- 2. Failure to Quick Open
- 3. One Bypass Valve Fails to Quick Close
- 4. Excessive Steam Bypass Flow
- 5. Failure to Generate Automatic Withdrawal Prohibit Signal During Steam Bypass Operation
- 6. Failure to Generate the Reactor Power Cutback Signal REACTIVITY CONTROL SYSTEMS
- 7. Regulating Group (s) Fail (s) to Insert or Withdraw
- 8. A Single CEA Stuck *
- 9. A CEA Subgroup Stuck *
- 10. Failure to Initiate or Execute the Reactor Power Cutback
- 11. CEA's Withdraw upon Automatic Withdrawal Prohibit and/or CEA Withdrawal Prohibit FEEDWATER CONTROL SYSTEM
- 12. Failure of Reactor Trip Override
- 13. Failure of High Level Override TURBINE-GENERATOR CONTROL SYSTEM
- 14. Setback w/o Cutback
- 15. Failure to Modulate the Turbine Control Valves
- 16. Failure to Setback Given a Cutback (100% > Initial Power > 75%)
- 17. Failure ~to Setback (75% > Initial Power >- 60%)
- 18. Failure to Runback (60% > Initial Power)
- 19. Failure to Trip the Turbine PRESSURIZER PRESSURE CONTROL SYSTEM (PPCS)
- 20. Failure of Spray Control Valves to Open
- 21. Failure of Spray Control Valves to Close
- 22. Failure of Backup Heaters to Turn On
- 23. Failure of Backup Heaters to Turn Off
- Control Element Drive Mechanism does not respond to control signal.
Release of CEA(s) on trip is not inhibited. O l Amendment No. 7 : March 31,1982 I o
TABLE 15.0-6 (Cont'd) PRESSURIZER LEVEL CONTROL SYSTEM O"-
- 24. Backup Charging Pump Fails to Turn On
- 25. Backup Charging Pump Fails to Turn Off
- 26. Letdown Flow Control Valve Fails to Close
- 27. Letdown Flow Control Valve Fails to Open MAIN FEEDWATER SYSTEM
- 28. One MFIV Fails to Close
- 29. One Back-flow Check Valve Fails to Close MAIN STEAM SYSTEM
- 30. One MSIV Fails to Close
- 31. One Atmospheric Dump Valve Fails to Open
- 32. One MSSV Fails to Reclose EMERGENCY FEEDWATER SYSTEM
- 33. Failure of Any One Emergency Feed Pump to Start EMERGENCY CORE COOLING SYSTEM
- 34. Failure of One HPSI or LPSI Pump ELECTRICAL POWER SOURCES
- 35. Loss of Offsite Power After Turbine Trip
- 36. Failure of One Emergency Generator to Start, Run, or Load
- 37. Failure of One Breaker to Achieve Fast Transfer to Backup Power Supply O
Amendment No. 7 March 31,1982
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15.1 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 15.1.1 DECREASE IN FEEDWATER TEMPERATURE 15.1.1.1 Identification of Event and Causes , A decrease in feedwater temperature may result from a loss of high pressure feedwater heaters. Loss of one of two high pressure feedwater heater drain i tank pumps interrupts the steam extraction from the high pressure turbine to j one of two parallel feedwater trains and results in the loss of three of six high pressure heaters. No other single failure would result in the loss of more heaters. Since each of the two feedwater heater trains increases the l enthalpy of the feedwater by about 100. Btu /lbm, the loss of one train (three heaters) would cause an overall reduction in the feedwater enthalpy of approximately 50 Btu /lbm. 15.1.1.2 Sequence of Events and System Operations A decrease in feedwater temperature causes a decrease in the temperature of the reactor coolant, an increase in reactor power due to the negative moderator temperature coefficient, and a decrease in the reactor coolant system (RCS) and steam generator pressures. Detection of these conditions' is accomplished by the RCS and steam generator low pressure alarms and the high linear power .i alarm. If the transient were to result in an approach to specified acceptable l fuel design limits, trip signals generated by the core protection calculators l would assure that low departure from nucleate' boiling ratio (DNBR) or high l local power density limits are not exceeded. l 15.1.1.3 Alalysis of Effects and Consequences A comparison of the RCS temperatures shows that the maximum RCS temperature decrease for the decrease in feedwater temperature event'is less than that for the inadvertent opening of a steam generator atmospheric dump valve (IOSGADV). The smaller cooldown results in less power increase and, consequently, in less , DNBR decrease during the transient. Therefore, the systems operation described l above and the resulting sequence of events would produce a DNBR transient less adverse than that associated with the 10SGADV event presented in Section 15.1.4. The limiting single failure with respect to fuel performance is the loss of offsite power on turbine trip for the same reasons as given in Section 15.1.4. This event in combination with a loss of offsite power results in an event similar to the 10SGADV event in combination with a loss of offsite power which is also presented in Section 15.1.4. All increased heat removal events analyzed in this section are characterized by decreasing RCS pressure due to the cooldown of the primary system. Thus, this event, or this event plus a single failure, will result in an insignificant increase in RCS pressure.
'15.1.1.4 Conclusions The decreased feedwater temperature event results in a DNBR greater than 1.19 throughout the transient. The event in combination with a loss of offsite power results in only a limited number of fuel pins in DNB. For both cases, g the RCS pressure remains well below 2750 psia.
15.1-1 Amendment No. 7 March 31,1982
1 15.1.2 INCREASE IN FEEDWATER FLOW 15.1.2.1 Identification of Event and Causes An increase in feedwater flow is caused by the further opening of a feedwater j control valve or an increase in feedwater pump speed. The maximum increase at j full power is approximately 10% above nominal for the normal feedwater system. i 15.1.2.2 Sequence of Events and System Operations An increase in feedwater flow causes a decrease in the temperature of the reactor coolant, an increase in reactor power due to the negative moderator temperature coefficient, a decrease in the RCS and steam generator pressures and an increase in steam generator water level. Detection of these conditions is accomplished by the RCS low pressure alarm and steam generator low pressure , and high water level alarms. Protection against the violation of specified ! acceptable fuel design limits, as a consequence of an increase in feedwater j flow, is provided by the low DNBP, and high local power density trips. 1 Protection against high steam generator water level is provided by the high ! , steam generator water level trip. 15.1.2.3 Analysis of Effects and Consequences l A comparison of RCS temperatures shows that the maximum RCS temperature decrease for the increase in feedwater flow event is less than that for the inadvertent opening of a steam generator atmospheric ducp valve (10SGADV) event. The smaller cooldown results in less power increase and, consequently, in less DNBR decrease during the transient. Therefore, the systems operation l described above and the resulting sequence of events would produce a DNBR transient no more adverse than that associated with the 10SGADV event presented in Section 15.1.4. The limiting single f ailure with respect to fuel performance is the loss of offsite power on turbine trip for the same reasons as given in Section 15.1.4. This event in combination with a loss of offsite power results in an event similar to, but less severe than, the 10SGADV event in combination with a loss of offsite power which is also presented in Section 15.1.4. 1 i All increased heat removal events analyzed in this section are characterized by decreasing RCS pressure due to the primary system cooldown. Thus, this event, or this event plus a single failure, will result in an insignificant increase ( in RCS pressure. I 15.1.2.4 Conclusions 1 The increased feedwater flow event results in a DNBR greater than 1.19 l throughout the transient. The event in combination with a loss of offsite l power results in only a limited number of fuel pins in DNB. For both cases, the RCS pressure remains below 2750 psia. , 1 l l O Amendment No. 7 15.1-2 March 31,1982
15.1.3 INCREASED MAIN STEAM FLOW 7
/ ' 15.1.3.1 Identification of Event and Causes An increase in main steam flow is caused by an inadvertent increased opening of the turbine admission valves. This may be caused by operator error or turbine load limit malfunctions and will result in no more than an 11% increase over the nominal full power steam flow rate. An increase in main steam flow can l also result from the inadvertent opening of a turbine bypass valve or an atmospheric dump valve; however, these events are discussed separately in Section 15.1.4.
15.1.3.2 Sequence of Events and System Operations An increase in main steam flow c,auses a decrease in the temperture of the reactor coolant, an increase in core power and heat flux, and a decrease in reactor coolant system and steam generator pressures. Detection of these conditions is accomplished by the RCS and steam generator low pressure alarms and the high reactor power alarm. If the transient were to result in an approach to specified acceptable fuel design limits, trip signals generated by the core protection calculators would assure that low departure from nucleate boiling ratio (DNBR) or high local power density limits are not exceeded. 15.1.3.3 Analysis of Effects and Consequences ; A comparison of the RCS temperatures shows that the maximum RCS temperature i O decrease for the increased main steam flow event is identical to that for the ( inadvertent opening of a steam generator atmospheric dump valve (10SGADV) event. This is due to the fact that both events cause an increase in main steam flow of 11%. Thus, the resultant power increase and the subsequent DNBR transient are also identical. Therefore, the systems operation described above and the resulting sequence of events for the increased main steam flow event I will be similar to the 10SGADV event presented in Section 15.1.4. The limiting single failure with respect to fuel performance is the loss of off-site power at the time of turbine trip for the same reasons as given in Section 15.1.4. This event in combination with a loss of offsite power is similar to, but no more severe than, the 10SGADV event combined with a loss of off-site power which is also presented in Section 15.1.4. All increased heat removal events analyzed in this section are characterized by decreasing RCS pressure due to the cooldown of the primary system. Thus, this event, or this event plus a single failure, will show an insignificant increase in RCS pressure. 15.1.3.4 Conclusions The increased main steam flow event results in a DNBR greater than 1.19 throughout the transient. The event in combination with a loss of off-site power results in only a limited number of fuel pins in DNB. For both cases, the RCS pressure remains well below 2750 psia. Amendment No. 7 15.1-3 March 31, 1982 l l
~ 15.1.4 INADVERTENT OPENING 0F A STEAM GENERATOR REllEF OR SAFETY VALVE 15.1.4.1 Identification of Event and Causes Case 1: Event (10SGADV) An atmospheric dump valve ( ADV) or a turbine bypass valve may be inadvertently opened by the operator or may open due to a failure of the control system which operates the valve. A steam generator safety valve will remain open only as a result of a valve failure. The opening of any of these valves will result in similar consequences because they relieve steam at the same maximum flow rate (11% of full power turbine flow rate). The inadvertent opening of a steam generator atmosperic dump valve (10SGADV) is presented here to illustrate these events. Case 2: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve plus a single failure (10SGADV + LOP) For the events of this section, the major parameter of concern is the minimum hot channel DNBR. This parameter establishes whether a fuel design limit has been violated and thus whether fuel cladding degradation might be anticipated. Those factors which cause a decrease in local DNBR are:
- a. increasing coolant temperature
- b. decreasing coolant pressure
- c. increasing local heat flux (including radial and axial power distribution effects)
- d. decreasing coolant flow The single failure (SF) which yields the minimum transient hot c.hannel DNBR is the SF which combines the greatest decrease in DNBR after initiation of a reactor trip signal with the lowest possible pre-trip DNBR. An evaluation of the SFs listed in Table 15.0.6 shows that the limiting SF for the event of this section is the loss of offsite power concurrent with a turbine trip (LOP) which is assumed to occur at a point in the transient at which the minimum hot channel DNBR is just above that which would cause the core protection calculators (CPCs) to initiate a reactor trip signal on low DNBR. The DNBR is thus at the lowest possible pre-trip value. The loss of flow due to the four pump coast down which results from the assumption of LOP following turbine trip causes a greater decrease in DNBR af ter reactor trip than other possible SFs.
None of the other SFs can cause a significant change in DNBR in the time interval between the start of the flow coastdown and the time at which core heat flux begins to decrease due to CEA insertion. Therefore the event plus single failure presented in this section is the 10SGADV + LOP. In addition to the assumed single failure of loss of offsite power it is assumed that the most reactive CEA is held in the fully withdrawn position following reactor trip. 15.1.4.2 Sequence of Events and Systems Operation Case 1: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve (10SGADV). The opening of a steam generator ADV increases the rate of heat emoval by the steam generators, causing cooldown of the RCS, Due to the negative moderator 15.1-4 Amendment No. 7 March 31, 1982
l I temperature coefficient, core power increases from the initial value of 102% of j i rated core power, reaching a new stabilized value of 113%. The feedwater ! control system, which is assumed to be in the automatic mode, supplies i feedwater to the steam generators such that steam ganerator water levels are maintained. Acting upon the large power mismatch between the reactor and turbine and the audible indication of steam blowdown, the reactor operator recognizes that the plant is in an ah;cmal state and manually trips the reactor. The analysis presented herein assumes this initial operator action is j delayed until after 30 minutes following the first indication of the event. l l Following the generation of a turbine trip on reactor trip the feedwater control system enters the reactor trip override mode and reduces feeuwater flow to 5% of nominal, full power flow. Since the steam bypass control system is ! assumed to be in the manual mode with all bypass valves closed, the main steam j safety valves (MSSVs) open to limit secondary system pressure and remove heat stored iin the core and RCS. The secondary system pressure then decreases due , to the cooldown caused by flow through the MSSVs and the ADV and the MSSVs I close. The secondary system pressure continues to decrease to the point where a mcin steam isolation signal (MSIS) is generated. This causes one steam ;
- generatar to be isolated from the flow path through the open ADV and causes main feedwater flow to be terminated. The affected steam generator continues to blow down and the level falls below the emergency feedwater actuation signal (EFAS) setpoint. However, the EFAS logic, acting upon the fact that the pressura in the affected steam generator is much lower than in the intact steam generai)r, prevents actuation of emergency feedwater flow. As a result the {
affecte a steam generator eventually boils dry. During the period of binwdown l following reactor trip, reactor coolant temperatures and pressure decredse 1 sl owly. Af ter dryout of the affected steam generator, decay heat and heat addition from the walls and structure of the primary coolant system cause a radual increase in reactor coolant temperatures and pressure. Relief of steam by the safety valves on the unaffected steam generator provides cooling which l limits reactor coolant temperatures. Reactor coolant pressure is limited by i the pressurizer safety valves. i Subsequent to tripping the reactor, the operator manually closes the ADV which had been inadvertently opened, terminating steam release to the atmosphere from the affected steam generator. In the analysis presented herein it is conservatively assumed that this action to close the ADV is delayed 20 minutes beyond the operator's initial action to trip the reactor, or a total of 50 minutes af ter event initiation. RCS heet removal for plant stabilization and cooldown is accomplished by using the turbine bypass valves. The operator is assumed to initiate plcnt cooldown 30 minutes after he manually trips the reactor. Case 2: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve with Loss of Offsite Power Following Turbine Trip (IOSGADV + LOP). Up until the time of the assumed turbine trip the transient due to the 10SGADV is identical with or without the 'oss of offsite power. For the 10SGADV + LOP event the turbine is assumed to try at 45 seconds into the transient, with the f minimum hot channel DNBR stabilized at a value just above that which would I cause the CPCs to initiate a low DNBR reactor trip. Credit is not taken for k the control grade reactor trip that would occur upon turbine trip. A loss of 15.1-5 Amendment No. 7 March 31, 1982 L__-_-__-_________-____________________________
offsite power is assumed to occur immediately following turbine trip. The resultant coastdown of all four reactor coolant pemps causes the initiation of a low DNBR reactor trip via the action of the CPC's af ter detection of decreasing pump speed. Following turbirie trip the feedwater control system enters the reactor trip override mode and reduces feedwater flow to 5% of nominal full power flow. Since the steam bypass control system is assumed to be in the manual mode with all bypass values closed, the MSSVs open to limit secondary system pressure and remove heat stored in the core and RCS. The secondary system pressure then decreases, due to the cooldown caused by the flow through the MSSVs and the ADV; and the MSSVs close. The secondary system pressure continues to decrease to the point where a MSIS is generated. This causes one steam generator to be isolated from the flowpath through the open ADV and causes main feedwater flow to be terminated. The affected steam generator continues to blow down and the level falls below the EFAS setpoint. However, the EFAS logic, acting upon the fact that the pressure in the affected steam generator is much lower than that in the intact steam generator prevents actuation of emergency feedwater flow. As a result the affected steam generator eventually boils dry. During the period of blowdown following reactor trip, reactor coolant temperatures and pressure decrease slowly. After dryout of the affected steam generator, decay heat and heat addition from the walls and structure of the primary coolant system cause a gradual increase in reactor coolant temperatures and pressure. Relief of steam by the safety i valves on the unaffected steam generator provides cooling which in turn maintains natural circulation flow through the core and limits reactor coolant temperatures. Reactor coolant pressure is limited by the pressurizer safety valves. Acting upon a variety of indications--including the initial large power mismatch between the reactor and turbine, the steady decrease in steam generator pressures and water levels after reactor trip, the continued decrease in pressure and level in the affected steam generator af ter MSIS, the low steam ! generator pressure and water level alarms, and the audible indication of steam blowdown--the reactor operator diagnoses the incident and manually closes the ; ADV which had been inadvertently opened, terminating steam release to the ! atmosphere from the affected steam generator. The analysis prcsented herein i assumes that this initial operator action to close the open ADV is delayed until 30 minutes following the first indication of the event. RCS heat removal for plant stabilization and cooldown is accomplished by manual control of the l ADVs on the unaffected steam generator. The operator is assumed to initiate plant cooldown 30 minutes after he manually closes the ADV which had been inadvertently opened. 15.1.4.3 Analysis of Effects and Consequences A. Mathematical Model The nuclear steam supply steam (NSSS) response to the 10SGADV and the 10SGADV + LOP was simulated using the CESEC-III computer program described in section 15.0.3. The time-dependent thermal margin on DNBR in the reactor core was calculated using the TORC computer program which uses the CE-1 critical heat flux correlation described in Chapter 4. O l 15.1-6 Amendment No. 7 Marcn 31, 1982
v Input Paraneters and Initial Conditions ( B. Table 15.1.4-3 lists the assumptions and initial conditions used for these analyses in addition to those discussed in section 15.0. Conditions were chosen such that the overpower condition caused by the increase in steam flow results in the closest approach to the specified acceptable fuel design l'imits (SAFDL) without causing a reactor trip. If core power increases more than the 11% due to the increasing steam flow, the Core Protection Calculators (CPC) will initiate a reactor trip and there will be no further degradation in thermal nargin. For transients initiated at other sets of initial conditions, a trip may or may not be required depending on whether the initial thermal margin is as low as for the combination of conditions used in these analyses. C. Results Case 1: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve (IOSCADV) The dynamic behavior of the salient NSSS parameters following the 10SGADV is Presented in Figures 15.1.4-1.1 to 15.1.4-1.15. Table 15.1.4-1 summarizes the major events, times and results for this transient. The opening of an ADV increases the rate of heat removal by the steam generators causing cooldown of the RCS. Due to the negative moderator reactivity coefficient, core power increases from 102% of rated core O power, reaching a new, stabilized value of 113% after approximately 30 seconds. The feedwater control system, which is assumed to be in the automatic mode supplies feedwater to the steam generators such that the steam generator water levels are maintained. During the 10SGADV transient the minimum transient DNBR of 1.19 first occurs at approximately 30 seconds and remains there until 1850.4 seconds when the l 10 operator manually trips the reactor. At 1850.55 seconds the trip breakers open. At this point, both the local and core average power decrease rapidly l 10 and DNBR increases. From 1858 seconds to 1886 seconds the MSSV's release steam. At 2149.4 seconds the steam generator pressure drops below the MSIS setpoint of 10 820 psia. The MSIS initiates closure of the MSIV's and MFIV's at 2150.4 seconds. The MFIV's and MSIV's close by 2155 seconds. The affected steam generator dries out at P650 seconds. At 3000 seconds the operator manually closes the open ADV. The operatnr initiates plant cooldow- t 3600 seconas. I Case 2: In6dvertent Opening of a Steam Generator Atmospheric Dum Loss of Offsite Power after Turbine Trip (10SGADV + LOP)p Valve with The dynamic behavior of the salient NSSS parameters following 10SGADV with loss of offsite power is presented in Figures 15.1.4-2.1 to 15.1.4-2.15. Table 15.1.4-2 summarizes the major events, times and results for this transient. The opening of an ADV increases the rate of heat removal by the steam p generators causing cooldown of the RCS. Due to the negative moderator t reactivity coefficient core power increases from 10h of rated core 15.1-7 Amendment No. 10 June 28, 1985 a
power, reaching a new, stabilized value of 113% af ter approximately 30 seconds. The feedwater control system, which is assumed to be in the automatic mode, supplies feedwater to the steam generators such that the steam generator water levels are maintained until the time of loss offsite power. i During the 10SGADV + LOP transient the minimum transient DNBR of 1.195 first occurs at approximately 30 seconds and remains there until the assumed turbine trip followed by loss of offsite power at 45 seconds. Due to decreasing core flow following the loss of power to the reactor coolant pumps, conditions exist for a low DNBR trip. At 45.6 seconds a low DNBR trip signal is initiated by the core protection calculators. The reactor trip breakers open at 45.75 10 seconds. At 46.1 seconds the minimum transient DNBR of 1.05 is calculated to occur, after which DNBR rapidly increases as shown by Figure 15.1.4-2.15. At 52 seconds the MSSV's open and release steam until 81 seconds. l10 Voids begin to form in the upper head of the reactor vessel at 74 seconds. At 312.4 seconds the steam generator pressure drops below the MSIS setpoint of 10 820 psia. The MSIS initiates closure of the MSIV's and MFIV's at 313.4 seconds. The MFIV's and the MSIV's close by 318 seconds. At 1150 seconds the affected steam generator dries out. At 1800 seconds the operator manually closes the open ADV. The operator initiates plant cooldown at 3600 seconds. Due to the coastdown of the reactor coolant flow a reduction of DNBR below 1.19 is calculated to occur. Approximately 8% of the fuel pins are predicted to experience DNB. However, within 3 seconds of reactor trip, the local and average core heat flux have decreased enough such that no pins remain in DNB. 15.1.4.4 Conclusions The 10SGADV event results in a DNBR greater than 1.19 throughout the transient. The event in combination with a loss of off-site power (IOSGADV + LOP) results in a small fraction of the fuel pins being predicted to be in DNB for a few seconds. Thus at the most a limited number of fuel rod cladding perforations could occur for the 10SGADV + LOP event. For both cases, the RCS pressure remains well below 2750 psia, ensuring that the integrity of the RCS is maintained. O j 15.1-8 Amendment No. 10 l June 28, 1985
O i O THIS PAGE INTENTIONALLY BLANK j i i O 15'1-9 Amendment No. 7
-March 31, 1982
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m i f TABLE 15.1.4-1 i SE00ENCE OF EVENT 5 FOR FULL POWER j I INADVERTENT OPENING OF A STEAM GENERATOR ATMOSPHERIC DUMP VALVE (IOSGADV) Setpoint Time (sec) Event or value ; 1 1.0 .One at,. spheric dump valve opens fully -- 30.0 Steady-state hot channel DNBR achieved 1.19 1850.4 Operator initiates manual trip -- 10 1850.55 Trip breakers open -- 10 l
.1858 Main steam safety valves open, psia 1282 1886 Main steam safety valves close, psia 1218 l 1872 Void begins to form in RV upper head --
l 1 2149.4 Steam generator pressure reaches main 820 steam isolation signal (MSIS) analysis I setpoint, psia 10 2150.4 Main steam isolation signal generated -- 2155 MFIV's close completely -- , 2155 MSIV's close completely -- 2650 Affected steam generator dries out -- 3000 Operator manually closes ADV -- 3600 Operator initiates plants cooldown -- l Amendment No. 10 June 28, 1985
TABLE 15.1.4-2 SEQUENCE OF EVENTS FOR FULL POWER INADVERTENT OPENING OF A STEAM GENERATOR ATMOSPHERIC DUMP VALVE WITH LOSS OF OFFSITE POWER AFTER TURBINE TRIP Setpoint Time (sec) Event or Value 0.0 One atmospheric dump valve opens fully -- 1 30.0 Steady state hot channel DNBR achieved 1.19 45.0 Turbine trips -- 45.0 Loss of offsite power occurs -- 45.6 Low DNBR trip signal generated -- 10 45.75 Trip breakers open -- 10 46.1 Minimum transient DNBR 1.05 48 Hot channel DNBR increases above 1.195 -- 10 52 Main steam safety valves open, psia 1282 l o 81 Ma'n steam safety valves close, psia 1218 74 Void begins to form in RV upper head -- 312.4 Steam generator pressure reaches main 820 steam isolation signal (MSIS) analysis j setpoint, psia 10 313.4 Main steam isolation signal generated -- 318 MFIV's close completely -- 318 MSIV's close completely -- 1150 Affected steam generator dries out -- 1800 Operator manually closes ADV 3600 Operator initiates plant cooldown -- O Amendment No. 10 June 28,1985 i J
I
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TABLE 15.1.4-3 J i ASSUMPTIONS AND INITIAL CONDITION FOR FULL POWER TRADVERTENT OPENING 0F AN ATMOSPHERIC DUMP. VALVE
.Gi (10SGADV AND 10SGADV + LOP i Parameter Value Initial Core Power Level, MWt 3876 Initial Core Inlet Coolant .575 Temperature, F Ingtial Core Mass Flow rate, 146.8 10 lbm/hr Initial Pressurizer Pressure, psia 2120 Initial Pressurizer Water Volume, ft 3 1100 Initial Steam Generator Pressure, psia 1175 Initial Steam Generator Inventory, 182,000 lbm per SG CEA Worth on Trip,10-2 Ap -8.8 Core Burnup End of cycle Oij ASI .3 Max. Radial Peaking Factor 1.4 l
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m 15.1.5 STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE CONTAINMENT 4
/ 15.1.5.1 Identification of Event and Causes V) A steam line break (SLB) is defined as a pipe break in the main steam system, SLB cases are chosen to maximize potential for a post-trip return to power, to maximize potential for degradation in fuel cladding performance, and to maximize dose at the site Exclusion Area Boundary. The results show that fission power levels remain sufficiently low following reactor trip to preclude degradation in fuel performance as a result of post-trip return to power, that degradation in fuel performance prior to trip is of sufficiently limited extent, that the core will remain in place and intact with no loss of core cooling capability, and that doses are within 10CFR100 guidelines. The steam line breaks presented are:
A. Cases chosen to maximize potential for a post-trip return to power:
- 1. A large steam line break inside containment during full power operation with concurrent loss of offsite power in combination with a single failure, and a stuck CEA (SLBFPLOP).
- 2. A large steam line break inside containment during full power operation with offsite power available in combination with a single failure and a stuck CEA (SLBFP).
- 3. A large steam line break inside containment during zero power operation with concurrent loss of offsite power in combination with a D single failure, and a stuck CEA (SLBZPLOP).
- 4. A large steam line break inside containment during zero power operation with offsite power available in combination with a single failure and a stuck CEA (SLBZP).
B. Cases chosen to maximize potential for degradation in fuel performance and dose at the site Exclusion Area Boundary:
- 5. A steam line break outside of containment upstream of the main !9 steam isolation valve (MSIV) during full power operation with offsite power available in combination with a single failure, technical specification steam generator tube leakage, and a stuck CEA (SLBFPD).
l9 ]
- 6. A large steam line break outside of containment upstream of the MSIV l
~
during zero power operation with concurrent loss of offsite power in combination with a single failure, technical specification steam generator tube leakage, iodine spike, and a stuck CEA (SLBZPLOPD). 1 The largest possible steam line break size is the double ended rupture of a l steam line upstream of the MSIV. In the System 80 design, an integral flow restrictor exists in each steam generator outlet nozzle. The largest effective steam blowdown area foi each steam line, which is limited b, the flow restrictor throat area, is appiu, .mou.'y 30% of the steam line cross-section area, or 1.28 square feet. f% t 3 V l 15.1-10 Amendment No. 9 I February 27, 1984 i
1 Results are presented in Appendix C which demonstrate that the cases listed above bound the results obtained for a spectrum of break sizes, loss of offsite power times, and single failures. 2 15.1.5.2 Sequence of Events and Systems Operation Steam line breaks are characterized as cooldown events due to the increased steam flow rate, which causes excessive energy removal from the steam generators and the reactor coolant system (RCS). This results in a decrease in reactor coolant temperatures and in RCS and steam generator pressure. The cooldown i.auses an increase in core reactivity due to the negative moderator and Doppler reactivity coefficients. Detection of the cooldown is accomplished by the pressurizer and steam generator low pressure alarms, by the high reactor power alarm and by the low steam generator water level alarm. Reactor trip as a consequence of a steam line break is provided by one of several available reactor trip signals including low steam generator pressure, low RCS pressure, low steam generator water level, high reactor power, low DNBR trip initiated by the core protection calculators and, for inside containment breaks, high containment pressure. For a SLB that occurs with a concurrent loss of offsite power, the events of turbine stop valve closure, termination of feedwater to both steam generators and coastdown of the reactor coolant pumps are assumed to be initiated simultaneously. Following reactor trip the most reactive control rod is conservatively assumed to be held in the fully withdrawn position. The depressurization of the affected steam generator results in the actuation of a main steam isolation signal (MSIS). This closes the MSIVs, isolating the unaffected steam generator from blowdown and closes the main feedw~ isolation valves (MFIVS), terminating main feedwater flow to both steam generators. After the reduction of steam flow that occurs with MSIV closure,the level in the intact steam generator falls below the emergency feedwater actuation signal (EFAS) setpoint. The resulting EFAS causes emergency feedwater (EFW) flow to be initiated to the intact steam generator. The EFAS logic prevents feeding the affected steam generator. The pressurizer pressure decreases to the point where a safety injection actuation signal (SI AS) is initiated. The isolation of the unaffected steam generator and subsequent emptying of the affected steam generator terminate the cooldown. i The introduction of safety injection boron upon SIAS causes core reactivity to I decrease. The operator, via the appropriate emergency procedures, may initiate plant cooldown by manual control of the atmospheric steam dump valves, or, in the event that offsite power is available, by using the MSIV bypass valves associated with the unaffected steam generator and the turbine bypass valves, any time af ter the af fected steam generator empties. The analysis presented herein conservatively assumes operator action is delayed until 30 minutes after first indication of the event. The plant is then cooled to 350 F and 400 psia, at which point shutdown cooling is initiated. A parametric study of single failures (See Appendix C) that would have an adverse impact on the SLB has determined that the failure of one of the high pressure safety injection (HPSI) pumps to start following SIAS has the most adverse effect for the full power case with concurrent loss of offsite power and all zero power cases (Cases 1,3,4, and 6). Consequently, one HPSI pump is conservatively 6ssumed to fail for these cases. The evaluation shows that for the full power SLB without loss O Amendment No. 7 15.1-11 March 31, 1982
m of offsite power (Case 2) the most adverse effect is caused by failure of a MSIV on one of the steam lines on the intact generator to close following . MSIS. Consequently for this case steam is assumed to continue to be released ) from the intact steam generator after MSIS at a rate consistent with the l interface requirement of a maximum of 11% design steam flow rate non-isolable steam flow. This open flow path is represented by an effective flow area for i steam blowdown from the intact steam generator of 0.2556 square feet. For l9 j case 5 (SLBFPD) there is no single failure which increases the potential for i degradation in fuel cladding performance or which increases the offsite dose. However the failure of a MSIV was used in the analysis to be consistent with 9 ! case 2 (SLBFP). q The sequence of events for Cases 1 through 5 above are presented in Tables l 15.1.5-1 through 5, respectively. The sequence of events for Case 6 is the same as for Case 3. l 15.1.5.3 Analysis of Effects and Consequences A. Mathematical Models The mathematical models and data transfer between codes used in the SLB analysis are presented in Appendix C. B. Input Parameters and Initial Conditions The initial conditions assumed in the analysis of the NSSS response to Cases 1 O i through 5 are presented in Tables 15.1.5-6 through 10, respectively. . The initial conditions for Case 6 are the same as those for Case 3. Justification of the selection of initial conditions ard input parameters is presented in Appendix C. C. Results l Case 1: Large Steam Line Break During Full Power Operation with ! Concurrent Loss of Offsite Power (SLBFPLOP) The dynamic behavior of the salient NSSS parameters following the SLBFPLOP is presented in Figures 15.1.5-1.1 through 15.1.5-1.16. Table 15.1.6-1 summarizes the major events, times, and results for this transient. Concurrent with the steam line break, a loss of offsite power occurs. At this time an actuation signal for the emergency diesel generators is initiated. Due to decreasing core flow following loss of power to the reactor coolant pumps, conditions exist for a low DNBR trip. At 0.6 second a low DNBR trip signal is initiated by the core protection calculators. At 0.75 second the reactor trip breakers open. At 7.7 seconds the steam generator pressure drops below the j MSIS setpoint of 810 psia. At 8.0 seconds voids begin to fona in the upper head of the reactor vessel. The MSIS initiates closure of the MSIVs and MFIVs at 8.7 seconds. The MFIVs and MSIVs close by 13.3 seconds. EFW is automatically initiated to the intact steam generator, assuming no delay after the EFAS 10 signal on low level in the intact steam generator, at 13.3 seconds. At 120 seconds the Pressurizer empties. At 177.4 seconds the pressurizer pressure has dropped below 1600 psia and initiates a SIAS at 178.4 seconds. Within 29.6 seconds of SIAS the operable HPSI pump is loaded on the diesels and reaches' full speed and the HPSI valves are fully open. At 237 seconds the affected steam generator empties. 15.1-12 Amendment No. 10 June 28, 1985
At 259 seconds the maximum core reactivity (+ 0.09 % ap ) occurs. Safety injection boron begins to reach the core at 280 seconds. As shown by Figure 15.1.5-1.16, the values of DNBR remain above those for which fuel damage would be indicated. At a maximum of 30 minutes the operator, via the appropriate emergency procedure, initiates plant cooldown by manual control of the atmospheric dump valves, assuming that offsite power has not been restored. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia. Case 2: Large Steam Line Break During Full Power Operation with Offsite Power Available (SLBFP) The dynamic behavior of the salient NSSS parameters following the SLBFP is presented in Figures 15.1.5-2.1 through 15.1.5-2.15. Table 15.1.0-2 summarizes the major events, times, and results for this transient. At 6.95 seconds after the initiation of the steam line break a trip signal is initiated by the core protection calculators on a projected DNBR of 1.19. At 7.1 seconds the reactor trip breakers open. At 11.9 seconds voids begin to form in the upper head of the reactor vessel. At 12.9 seconds the steam 10 generator pressure drops below the MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs and MFIVs at 13.9 seconds. The MFIVs and the l 10 operable MSIVs close by 18.5 seconds. EFW is automatically in tiated to the intact steam generator, assuming no delay after the EFAS signal on low level in the intact steam generator, at 18.5 seconds. At 67 seconds the pressurizer empties. At 89.4 seconds the pressurizer pressure drops below 1600 psia and 10 initiates a SIAS at 90.4 seconds. Within 29.6 seconds of SIAS the HPSI pumps reach full speed and the HPSI valves are fully open. At 149 seconds the affected steam generator empties. At 151 seconds the maximum core reactivity (-0.18% ap) occurs. Safety injection boron begins to reach the core at 160 seconds. The values of DN8R remain above 10 during the post-trip approach-to-criticality portion of this transient. At a maximum of 30 minutes the operator, via the appropriate emergency procedure, initiates plant cooldown by manual control of the turbine bypass valves. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia. Case 3: Large Steam Line Break During Zero Power Operation with Concurrent Loss of Offsite Power ] The dynamic behavior of the salient NSSS parameters following the SLBZPLOP is presented in Figures 15.1.5-3.1 through 15.1.5-3.15. Table 15.1.5-3 summarizes the major events, times, and results for this transient. Concurrent with the steam line break, a loss of offsite power occurs. At this time an actuation signal for the emergency diesel generators is initiated. Due I to decreasing core flow following loss of power to the reactor coolant pumps, conditions exist for a low DNBP trip. At 0.6 second a low DNBR trip signal is 1 initiated by the core protection calculators. At 0.75 second the reactor trip l breakers open. At 5.0 seconds the steam generator pressure drops below the 10 MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs and MFIVs at 6.0 seconds. The MFIVs and MSIVs close by 10.6 seconds. EFW is auto-matically initiated to the intact steam generator, assuming no delay after 10 the EFAS signal on low level in the intact steam generator, at 10.6 seconds. , 15.1-13 Amendment No. 10 June 28, 1985
At 44.6 seconds the pressurizer pressure drops below 1600 psia and initiates a 9 SIAS at 45.6 seconds. Within 29.6 seconds of SIAS the operable HPSI pump is loaded on the diesels and reaches full speed and the HPSI valves are fully open. At 55 seconds voids begin to form in the upper head of the reactor vessel. At 10 59 seconds the pressurizer empties. Safety injection boron begins to reach the core at 120 seconds. At 189 seconds the maximum core reactivity (-0.06%Ap) occurs. At 1240 seconds the affected steam generator empties. The values of DNBR remain above 10 during this transient. At a maximum of 30 minutes the operator, via the the appropriate emergency procedure, initiates plant cooldown by manual control of the atmospheric dump valves, assuming that offsite power has not been restored. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia. Case 4: Large Steam Line Break Zero Power Operation with Offsite Power Available (SLBZP) The dynamic behavior of the salient NSSS parameters following the SLBZP is presented in Figures 15.1.5 a.1 through 15.1.5-4.15. Table 15.1.5-4 summarizes the major events, times, and results of this transient. At 5.64 seconds after initiation of the steam line break, the steam generator pressure drops below the low steam generator pressure trip and MSIS setpoint of 810 psia. At 6.79 seconds the reactor trip breakers open. The MSIS initiates closure of the MSIVs and MFIVs at 11.2 seconds. The MFIVs and MSIVs close by 10 11.2 seconds. EFW is automatically initiated to the intact steam generator, assuming no delay after the EFAS signal on low level in the intact steam G generator, at 11.2 seconds. At 40.6 seconds the pressurizer pressure drops below 1600 psia and initiates a SIAS at 41.6 seconds. Within 29.6 seconds of SIAS the operable HPSI pump reaches full speed and the HPSI valves are fully 10 open. At 48 seconds voids begin to form in the upper head of the reactor vessel. At 52 seconds the pressurizer empties. Safety injection boron begins to reach the core at 110 seconds. At 310 seconds the maximum core reactivity (-0.02%Ap ) occurs. At 418 seconds the affected steam generator empties. The values of DNBR remain above 10 for this transient. At a maximum of 30 minutes the operator, via the appropriate emergency procedure, initiates plant cooldown by manual control of the MSIV bypass valves associated with the unaffected steam generator and turbine bypass valves. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia. Case 5: Small Steam Line Break Outside Containment During Full Power Operation 9 with Offsite Power available (SLBFPD) The dynamic behavior of the 3-lient NSSS parameters following a typical limiting SLBFPD is presented in Q ures 15.1.5-5.1 through 15.1.5-5.8. Table l 9 15.1.5-5 summarizes the major events, times and results for this transient. The mnsequences of this transient -- fraction of fuel rods predicted to expt. ience DNB -- are the same as those for SLBFPDs for a spectrum of break sizes, due to the protective action of the core protection calculators (CPCs). See the discussion in Section 15C.3.2 and Figure 15C-1 of Appendix 15C. The largest break size yields the minimum DNBR. Therefore the transient presented 9 here is that which results from the double ended break of a main steam line. ) Not later than 5.85 seconds after initiation of the steam line break, a trip signal is initiated by the CPCs on a projected DNBR of 1.19. At 6.00 seconds 15.1-14 Amendment No. 10 June 28, 1985
the reactor trip breakers open. At 7.49 seconds a minimum transient DNBR of y 1.11 is calculated to occur, after which DNBR rapidly increases, as shown in Figure 15.1.5-5.9, At 8.94 seconds voids begin to form in the upper head of l the reactor vessel, At 12.2 seconds the steam generator pressure drops below l In9 the MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs and MFIVs at 13.2 seconds. The MFIVs and the operable MSIVs close by 17.8 seconds. l10 Subsequently, the events of this transient follow a sequence similar to those of the SLBFP (Case 2). Since the cooldown is less severe the potential for post-trip degradation in fuel cladding performance is less for this case (SLBFBD) than for Case 2 (SLBFP). At a maximum of 30 minutes the operator, using the appropriate emergency procedure, initiates plant cooldown by manual control of the turbine bypass valves. Shutdown coolino is initiated when the RCS reaches 350 F and 400 psia. At the point of the minimum transient DNBR no more than 0.4% of the fuel rods are predicted to experience DNB. However, as a bounding assumption, 0.7% of the fuel pins are assumed to fail. All of the activity in the fuel gap for fuel rods that are assumed to fail is assumed to be uniformly mixed with the reactor coolant. The activity in the fuel clad gap is assumed to be 10% of the iodines and 10% of the noble gases accumulated in the fuel at the end of core life, assuming continuous full power operation. This results in a primary 9 coolant activity of 618 pCi/gm. Assuming one gpm steam generator tube leakage, during a period of two hours after initiation of the SLBFBD, the integral leakage from the RCS through the affected steam generator is 720 lbm, which is assumed to be released to the atmosphere with a DF of 1. This mass release results in a contribution to the inhalation thyroid dose at the Exclusion Area Boundary (EAB) of 220 rem. l 9 The total steam released from the affected steam generator is 153,000 lbm. l The affected steam generator will empty in two hours; therefore all the mass release from the affected steam generator to the atmosphere has a DF of 1. The g calculated inhalation thyroid dose is not more than 9.8 rem for the blowdown originating from the secondary system fluid discharge from the affected steam genera tor. Less than 86,000 lbm of steam from the unaffected steam generator will be released trough the steam line break. During the SLBFPD the MSIVs will isolate 9 the unaffected steam generator and prevent it from emptying. Therefore, a DF of 100 is assumed in calculating iodine activity released from the unaffected steam generator. The resulting contribution to the inhalation thyroid dose at the EAB is less than 0.1 rem. Should condenser vacuum be lost during this transient,up to an additional 860,000 lbm of steam from the unaffected steam l10 generator would be released to the atmosphere through the atmospheric steam dump valves. This would result in an additional contribution to the dose of not more than 0.5 rem. 10 The foregoing doses are calculated by the methods outlined in Section 15.0.4, Table 15.1.5-11 presents the major assumptions, parameters, and radiological consequences for this transient. In summary, the total two-hour inhalation thyroid dose at the EAB as a consequence of the SSLBFP is no more than 231 rem. 15.1-15 Amendment No. 10 June 28, 1985
Case 6: Large Steam Line Break Outside Containment from Zero Power Operation with Loss of Offsite Power (SLBZPLOPD) Case 6 is included in Case 3, since the break of the latter can be either inside or outside of containment. The Figures, Tables, and Discussion for Case 3 apply to Case 6. Assuming one gpm steam generator tube leakage, during a period of two hours after initiation of the SLBZPLOPD the integral leakage from the RCS through the affected steam generator is 720 lbm, which is assumed to be released to the atmosphere with a DF of 1. This mass release results in a contribution to the inhalation thyroid doses at the EAB of: (a) 1.6 rem, assuming technical specification primary coolant activity; (b) 20.1 rem, assuming a pre-existing iodine spike; or (c) 41.5 rem, assuming an event-induced iodine spike. The total steam released from the affected steam generator is 300,000 lbm, which is the total initial mass inventory. The affected steam generator will empty in two hours; therefore all the mass release from the affected steam generator to atmosphere has a DF of 1. The calculated inhalation thyroid dose is 15.0 rem for the blowdown steam originating from the initial steam 10 generator mass inventory. Less than 850,000 lbm of steam from the unaffected steam generator will be released through the atmospheric steam dump valves and through the steam line O break within two hours. During the SLBZPLOPD the MSIVs will isolate the unaffected steam generatnr and prevent it from emptying. Therefore, a DF of 100 is assumed in calculating iodine activity released from the unaffected steam generator. The resulting contribution to the inhalation thyroid dose at the EAB is 0.4 rem. The foregoing doses are calculated by the methods outlined in Section 15.0.4. Table 15.1.5-11 presents the major assumptions, parameters, and radiological consequences for this transient. In summary, the total two-hour inhalation thyroid dose at the EAB as a consequence of the SLBZPLOPD is no more than 56 rem. 15.1.5.4 Conclusion For the large steam line break in combination with a single failure and stuck CEA, with or without a loss of offsite power, fission power remains sufficiently ! low following reactor trip to preclude fuel damage as a result of post-trip return to power. ; For a large steam line break during zero power operation in combination with a loss of offsite power and technical specification tube leakage the two-hour inhalation thyroid dose at the EAB is well within 10CFR100 guidelines: (a) 16 rem, assuming technical specification primary coolant activity; q (b) 36 rem, assuming a pre-existing iodine spike; or l (c) 57 rem, assuming an event-induced iodine spike. 20 15.1-16 Amendment No. 10 June 28, 1985
i The maximum potential for radiological releases due to fuel failure occurs for full power steam line breaks outside containment in combination with a stuck CEA, For these cases the maximum potential for degradation in fuel cladding performance occurs prior to and during reactor trip. The fraction of fuel predicted to experience DNB for these events is no more than 0.4%. With ! the assumption of one gallon per minute steam generator tube leakage and a l bounding assumption of 0.7% fuel failure the two-hour inhalation thyroid dose 1 at the EAB is calculated to be no more than 231 rem, which is within the 10 CFR100 guideliries. Potential fuel failure is sufficiently limited to ensure that the core will remain in place and intact with no loss of core cooling capabilities. O I Ol! 15.1-17 Amendment No. 9 February 27, 1984
TABLE 15.1.5-1 SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING FULL POWER ) OPERATION WITH CONCURRENT LOSS OF OFFSITE POWER (SLBFPLOP) Time (Sec) -Event Setpoint or Value I i 0.0 Steam Line Break and Loss of -- i Offsite Power Occur 1 l 0.6 Low DNBR Trip Signal' Generated, 1.19 10 Projected DNBR - 1 0.75 Trip Breakers Open -- 7.7 Steam Generator Pressure Reaches Main 810' Steam Isolation Signal (MSIS) Analysis 10_ ! Setpoint, psia 8.0 Voids Begin to Form in RV Upper -- Head 8.7 Main Steam Isolation Signal, Generated- -- 10 13.3 MFIVs Close Completely -- i 13.3 MSIVs Close Completely -- 13.3 Steam Generator Level Reaches 25 Emergency-Feedwater Actuation Signal Analysis Setpoint, % of wide range 10 13.3 EFW Initiated to Intact Steam -- Generator 120 Pressurizer Empties -- 177.4 Pressurizer Pressure Reaches Safety 1600 . Injection Actuation Signal (SIAS) 10 l Analy. sis Setpoint, psia 178.4 Safety Injection Actuation Signal -- Generated 208 Safety Injection Flow Begins -- 237 Affected Steam Generator Empties -- 259 Max {mumTransientReactivity, +0.09 10~ Ap }- 277 Minimum Post-Trip DNBR 2.7 280 Safety Injection Baron Begins to -- Reach Reactor Core 1800 Operator Initiates Cooldown -- Amendment No. 10 June 28, 1985
TABLE 15.1.5-2 SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFP) Time (Sec) Event Setpoint or Value 0.0 Steam Line Break Occurs -- 6.95 Low DNBR Trip Signal Generated, 1.19 10 Projected DNBR 7.10 Trip Breakers Open -- 10 11.9 - Voids Begin to Form in RV Upper -- Head 12.9 Steam Generator Pressure Reaches 810 Main Steam Isolation Signal Analysis Setpoint, psia 10 13.9 tiain Steam Isolation Signal Generated -- 18.5 MFIVs Close Completely -- 18.5 MSIVs Close Completely -- 18.5 Steam Generator Water Level Reaches 25 Emergency Feedwater Actuation Signal 10 Analysis Setpoint, percent of wide range 18.5 EFW Initiated to Intact Steam -- Generator 67 Pressurizer Empties -- 89.4 Pressurizer Pressure Reaches Safety 1600 Injection Actuation Signal Analysis Setpoint, psia 10 90.4 Safety Injection Actuation Signal -- Generated 120 Safety Injection Flow Begins -- 149 Affected Steam Generator Empties -- 151 MaximumTransiegt -0.18 Reactivity, 10" Ap 151 Minimum Post-Trip DNBR 26 160 Safety Injection Boron Begins to -- I Reach Reactor Core 1800 Operator Initiates Cooldown -- Amendment No. 10 June 28, 1985 , 1 j
~
TABLE 15.1.5-3 O SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING ZERO POWER OPERATION WITH CONCURRENT LOSS OF 0FFSITE POWER (SLBZPLOP AND SLBZPLOPD) Time (Sec) Event Setpoint or Value i 0.0 Steam Line Break and Loss of -- 0ffsite Power.0ccur 0.6 Low DNBR Trip Signal Generated, 1.19 10
-Projected DNBR 0.75 Trip Breakers Open --
5.0 Steam Generator Pressure Reaches 810 Main Steam Isolation Signal Analysis Setpoint, psia ) 6.0 Main Steam Isolation Signal Generated -- 10.6 MFIVs Close Completely -- 10.6 MSIVs Close Completely -- 10.6 Steam Generator Level Reaches 25 i b Emergency Feedwater Actuation Signal d Analysis Setpoint, % wide range 10 10.6 EFW Initiated to Intact Steam -- Generator 44.6 Pressurizer Pressure Reaches Safety 1600 Injection Actuation Sicnal Analysis Setpoint, psia 45.6 Safety Injection Actuation Signal -- Generated 55 Voids Begin to Form in RV Upper Head -- 59 Pressurizer Empties 75.2 Safety Injection Flow Begins -- 10 120 Safety Injection Boron Begins to -- Reach Reactor Core 189 MaxjmumTransientReactivity. -0.06-10" op 1240 Affected Steam Generator Empties -- 1800 Operator Initiates Cooldown -- I Amendment No. 10 June 28,1985
1
)
TABLE 15.1.5 4 j SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING ZERO POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBZP) Time (Sec) Event Setpoint or Value 0.0 Steam Line Break Occurs -- 5.64 Steam Generator Pressure Reaches 810 Reacter Trip Analysis Setpoint, psia 5.64 Steam Generator Pressure Reaches 810 Main Steam Isolation Signal Analysis 10 Setpoint, psia 6.64 Low Steam Generator Pressure Reactor -- Trip and Main Steam Isolation Signal Generated 6.79 Trip Breakers Open -- 11.2 MFIVs Close Completely -- 11.2 MSIVs Close Completely -- 11.2 Steam Generator Water Level Reaches 25 Emergency Feedwater Actuation Signal Analysis (Setpoint) ; i
% wide rang 10 11.2 EFW Initiated to Intact Steam --
Generator 40.6 Pressurizer Pressure Reaches Safety 1600 Injection Actuation Signal Analysis Setpoint, psia ) 41.6 Safety Injection Actuation Signal -- Generated 48 Voids Begin to Form in RV Upper Head -- 52 Pressurizer Empties -- 71.2 Safety Injection Flow Begins -- 10 110 Safety Injection Boron Begins to -- Reach Reactor Core 310 MagmumTransientReactivity, -0.02 10 Ap 418 Affected Steam Cenerator Empties -- 1800 Operator Initiates Cooldown -- Amendment No. 10 June 28, 1985
TABLE 15.1.5-5 SE00ENCE OF EVENTS FOR A SMALL STEN 1 LINE BREAK OUTSIDE CONTAINMENT DLRING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFPD) l Time (Sec) Event Setpoint or Value 0.0 Steam Line Break Occurs -- 5.85 Low DNBR Trip Signal Generated 1.19 Projected DNBR 10 9 6.00 Trip Breakers Open -- 10 7.49 Minimum Transient DNBR 1.11 8.94 Voids Begin to Form in RV Upper Head -- 12.2 Steam Generator Pressure Reaches 810 , Main Steam Isolation Signal Analysis Setpoint, psia . 10 l 13.2 Main Steam Isolation Signal Generated --
]
17.8 Steam Generator Water Level Reaches 25 l Emergency Feedwater Actuation Signal I Analysis Setpoint, percent of wide range g 17.8 EFW Initiated to Intact Steam l Generator ' 9 17.8 MFIVs Close Completely --
]
17.8 MSIVs Close Completely -- 64.6 Pressurizer Pressure Reaches Safety 1600 Injection Actuation Signal (SIAS) Analysis Setpoint, psia 10 65.6 Safety Injection Actuation Signal Generated 75 MaximumPost-trjpTransient 1.92 9 Reactivity, 10~ Ap 95.2 Safety Injection Flow Begins -- 10 100 Affected Steam Generator Empties -- 200 Safety Injection Boron Begins -- to reach Reactor Core 9 p 430 Secondary Post-trip _fransient -2.06 g Reactivity Peak, 10 ap 1800 Operator Initiates Cooldown -- l Amendment No. 10 l June 28, 1985
TABLE 15.1.5-6 A05UMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING FULL l POWER OPERATION WITH CONCURRENT LOSS OF OFFSITE POWER (SLBFPLOP) l Parameter Assumed Value Initial Cora Power Level, MWt 3876 Initial Core Inlet Coolant Temperature, F 570 Initial Core Mass Flov! Rate,106 lbm/hr 148.8 Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft 3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shape Index +.3 CEA Worth for Trip,10-2 Ap -8.8 Initial Steam Generator Inventory, lbm, affected 182000 intact 148000 One High Pressure Safety Injection Pump Inoperative Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowdown Area for Each Steam Line, ft 2 1.283 O Amendment No. 7 March 31, 1982
TABLE 15.1.5-7 O ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFP) Parameter Assumed Value Initial Core Power Level, MWt 3876 Initial Core Inlet Coolant Temperature, F 570 l 6 Initial Core Mass Flow Rate,10 lbm/hr 148.8 l Initial Pressurizer Pressure, psia 2400 l Initial Pressurizer Water Volume, ft3 1100 Doppler Coefficient Multiplier 1.15 j Moderator Coefficient Multiplier 1.10 l Axiel Shape Index +.3 CEA Worth for Trip,10-2 L3 -8.8 Initial Steam Generator Inventory, lbm, affected 182000 intact 148000 One Main Steam Isolation Valve on Intact Steam Inoperative j Generator i Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowdown Area for Each Steam Line, ;'.2 1.283 l i l l A Amendment No. 7 March 31, 1982
TABLE 15.1.5-8 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING . ZER0 POWER OPERATION WITH CONCURRENT LOSS OF OFFSITE POWER (SLBZPLOP AND SLBZPLOPD) Parameters Assumed Value Initial Core Power Level, MWt 10 Initial Core Inlet Coolant Temperature, F 575 Initial Core Mass Flow Rate,106 lbm/hr 147.6 Initial Pressurizer Pressure, psia 2400 . Initial Pressurizer Water Volume, ft3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 i Axial Shape Index +.3 l CEA Worth for Trip,10-2 Ap -6.0 Initial Steam Generator Inventory, lbm, affected 279000 1 intact 143000 One High Pressure Safety Injection Pump Inoperative Core Burnup End of Cycle j B1owdown Fluid Saturated Steam Blowdown Area for Each Steam Line, f t 2 1.283 l 1 i l l O Amendment No. 7 March 31, 1982
v l TABLE 15.1.5-9 l
/ ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING ! \_ ZERO POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBZP) l Parameter Assumed Value Initial Core Power Level, MWt 10 Initial Core Inlet Coolant Temperature, F 575 Initial Core Mass Flow Rate,106 lbm/hr 147.6 l
Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft 3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shapo Index +.3 CEA Worth for Trip,10-2 Ap -6.0 Initial Steam Generator Inventory, Ibm, affected 279000 l intact 163000 One High Pressure Safety Injection Pump Inoperati ve Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowdown Area for Each Steam Line, ft 2 1.283 1 l
\
Amendment No. 7 March 31, 1982
TABLE 15.1.5-10 ASSUMPTIONS AND INITIAL POWER CONDITIONS FOR A STEAM LINE BREAK OUTSIDE CONTAINMENT DURING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFPD) Parameter Assumptions Initial Core Power Level, MWt 3876 Initial Core Inlet Coolant Temperature, F 570 Initial Core Mass Flow Rate,106 lbm/hr 148.4 9 Initial Pressurizer Pressure, psia 2139 3 Initial Pressurizer Water Volume, ft 1100 j 9 Doppler Coefficient Multiplier 0.85 Moderate Coefficient Multiplier 1.10 i Axial Shape Index +0.3 9 Radial Peaking Factor, F R I'42 i CEA Worth for Trip,10-2 A -8.8 I Initial Steam Generator Inventory, lbm, affected 122000 intact 122000 Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowdown area for each steam line, ft 2 1.283 l9 l Amendment No. 9 February 27, 1984
TABLE 15.1.5-11 I (Sheet 1 of 3) O Q PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAM OF MSIV i I Value Pa rameter - SLBFPD (Case 5) SLBZPLOPD (Case 6) g A. Data and Assumptions Used to Evaluate the Radioactive Source Term
- a. Power Level, Mwt 3876 10
- b. Burnup, years 2 2
- c. Percent of Fuel Assumed to Experience DNB, % 0.7 0 !
- d. Reactor Coolant 4.6 4.6*
Activity Before Event Table 11.1.1-2 Table 11.1.1-2 (based on 3876 MWt), ; uCi/gm ! f g e. Secondary System Section 15.0.4 Section 15.0.4
\ Activity Before Event
- f. Primary System Liquid 525,600 525,600 Inventory, lbm
- g. Steam Generator Inventory, Ibm
- Affected Steam 122,000 300,000 Generator 9
- Intact Steam 122,000 143,000 Generator B. Data and Assumptions Used to Estimate Activity Released from the Secondary System
- a. Primary to Secondary 1.0 (total) 1.0 (total)
Leak Rate, gpm
- b. Total Mass Release from 153,000 300,000 g the Affected Steam Generator
*Except for case assuming pre-existing iodine spike (see footnote on next page).
Amendment No. 9 February 27, 1984
TABLE 15.1.5-11 (Cont'd.) (Sheet 2 of 3) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES l OF A STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAM OF MSIV Value Parameters SSLBAP (Case 5) SLPZPLOPD (Case 6)
- c. Total Mass Release from 840,000 850,000 l the Intact Steam Generator
- d. Reactor Coolant System Activity After Event, Ci Isotope I-131 8.568(+4)*
I-132 1.217(+5) 1-133 1.605(+5) 1-134 1.680(+5) ; I-135 1.469(+5) ' Kr-85M 1.421(+4) ** Kr-85 3.903(+2) Kr-87 2.400(+4) Kr-88 3.475(+4) Xe-131M 6.018(+2) ' Xe-133 1.618(+5) Xe-135 9.724(+4) Xe-138 2.557(+4)
- e. Percent of Core Fission **
Products Assumed Released 10 to Reactor Coolant
- f. Iodine Decontamination 1.0 1.0 >
Factor in the Affected Steam Generator
- g. Iodine Decontamination 100 100 Factor in the Intact Steam Generator i
- h. Credit for Radioactive No No Decay in Transit to Dose Point
- i. Loss of Offsite Power No Yes
- Numbers in parenthesis refer to the power of ten; e.g. 8.568(+4)=8.568x10 4
**lhree sub-cases are presenteo sub-case RCS activity after event, pCi/gm a) technical specification activity 4.6 b) pre-existing iodine spike 60 /,mendment ::o. 7 c) event-induced iodine spike 124 Marr.h 31, 1989 I
m - TABLE 15.1.5-11 (Cont'd. ) (Sheet 3 of 3) O)
-(
PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSE0VENCES 0F A STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAM OF MSIV Value Parameter SSLBFP (Case 5) SLBZPLOPD (Case 6) C. Dispersion Data
- 1. Distance to Exclusion 500 500 Area Boundary, m
- 2. Distance to Low 3000 3000 Population Zone Outer Boundary, m
- 3. AtmosphericDjspersion Factor, sec/m 2.00 x 10-3 2.00 x 10-3 D. Dose Data
- 1. Method of Dose Section 15.0.4 Section 15.0.4 Calculation i
- 2. Dose Conversion Section 15.0.4 Section 15.0.4
- p Assumptions
(
- 3. Control Room Design See Applicant's See Applicant's i Parameters SAR SAR I
l Amendment No. 7 March 31, 1982
9 l I I THIS PAGE INTENTIONALLY BLANK. i i I 1 l l O
O 150 i i i i 125 - e 2
-j 100 -
2 8 E d e 75 ci O o 50 - - U 8 25 -- - l ' 0 i 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 O C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure S CONCURRENT LOSS OF OFFSITE POWER 15.1.5-CORE POWER vs TIME 1,1
0 150 i i i i 5 d 125 - - s l 6 r a: g 100 - - d 2 8 g 75 - - - 0 5 o. O s 50 -- - 1 d e u y 25 -- - a 0 I ' h' ' 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-CORE HEAT FLUX vs TIME -1.2
1 l i o 1 2500 , i i i ) ( 2000 l m 1500 - - ur : m l 0 E 1@0 - O $ e 500 - I I 0 I I 0 100 200 300 400 500 TIME, SECONDS i Amendment No. 7 March 31,1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S RCS PRESSURE vs TIME 1.3
i l 50000 , , i i 40000 - - I o 1 Ui E 30000-- - W 1
$ l w
$20000 _. CORE -
5 s qb g AFFECTED SG LOOP
%10000 -
R E e w ~
~
0 # INTACT SG LOOP
-10000 1 I I I 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 rwy March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSIE POWER 15.1.5-S REACTOR COOLANT FLOW RAE vs TIME 1.4 l
A V l 700 i i i i l 'i l l l 8 M0, CORE OUTLET - O x 1 ' R CORE AVERAGE 25 a
&.500 -
1
- E - -
z 5 o 400 - CORE INLET O 8 8
!3
$ 3%
200 I i 1 I i 0 100 200 300 400 500 TIME, SECONDS ; Amendment No. 7 March 31, 1982 C-E . FULL POWER lARGE STEAM LINE BREAK WITH Figure , S CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-REACTOR COOLANT TEMPERATURES (A) vs TIME - 1.5 A
i .O V 700 , , INTACT SG HOT LEG
& 600 -
d e INTACT SG COLD LEGS , i2 h500 x - AFFECTED SG HOT LEG " z
@ 4%
O 2 g / l AFFECTED SG COLD LEGS
$300 x
200 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSITE POWER 15,1,5-S REACTOR COOLANT TEMPERATURES (B) vs TIME 1,5B
~
1 i 10 , , , , e- MODERATOR
\
6 - -
- e. l
. DOPPLER y2 \ -
~
5 b % s 5 -2 -- - V g TOTAL SAFETY INJECTION
-6 -
l ! CEA l
-10 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE SEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S REACTIVITY CHANGES vs TIME 1.6
~. ,
i l O 1200 , , , , 1000 - 1 g800 5 9 : m i W 600 -- 5 . \ Di 1 x 3 400 - - C E i l 200 - - I I I 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF 0FFSITE POWER 15 S PRESSURIZER WAER VOLUME vs TIME 15*j 1 J
1200 i i i i i 1000 - - g 1 E d#~ INTACT SEAM GENERATOR
~
E u I 600 -- - l
??
i w l O $ o
- E 400 - -
i l h AFFECED SEAM GENERATOR 200 - - 0 1 I l 0 100 200 300 400 500 TIME, SECONDS i i Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure S CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S'EAM GENERATOR PRESSURES vs TIME 1. 8
l 7000 (q , i i i j U S w ii! l 0 l
- 5000- - -
l g a I
; 4000 -- -
8 2 o is 3000 - - e O R N 1 l u i 8 2000 - - k I U 1000 - j f .NTACT SEAM GENERATO - t AFFECTED SEAM GENERATOR O I i i ' 0 100 200 300 400 500
. TIME, SECONDS l
Amendment No. 7 O c-: March 31, 1982 FULL POE R LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSIE POWER 15,1,5-S SEAM GENERATOR BLOWDOWN RAES vs TIME 1,9 l 1 I
(^h, : L) I 1 2500 , , i i 1 o 2000'- - M 3 I O N 1500 -- - n 3 9
.I')
G $ g 1000 -- - S E 500 - INTACT STEAM GENERATOR - i
- AFFECTED STEAM GENERATOR l
0 0 100 200 300 400 500 TIME, SECONDS l l Amendment No. 7 r March 31, 1982 (N) C-E f FULL POWER (ARGE STEAM LINE BREAK WITH rigure SM6P8 // CONCURRENT LOSS OF 0FFSITE POWER FEEDWATER FLOW RATES vs TIME 15',1'0 l1 5
O 500 , , , , 400 - - L g m
> 300 - _
b I 5 x 200 - - O e re l@ - _ INTACT AND AFFECTED STEAM GENERATORS
' ' ' i 0
0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER lARGE STEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF 0FFSIE BREAK SE FEEDWAER ENTHALPY vs TIME 15',1* l 11 5 -
i j O 300000 , , , ,
% 250000 - -
?<
W 200000 - - ce f2 5 3 l
~ 150000 -
s 1 5 INTACT STEAM GENERATOR O stooooo W I w AFFECTED STEAM GENERATOR b / ;
@ 50000 w
l 0 I I I O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 l O- C-E FULL POWER lARGE SEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSIE POWER 15,1,5-STEAM GENERATOR MASS INVENTORIES vs TIME 1,12 1
l 350000 i , , i 300000 - - 250000 - -
$' l 1
~
l Bi S w 200000 - - l i
- E b
w y150000 - - O e b
~ 100000 -. -
50000-- - l O I I i i 0 100 200 300 400 500 i TIME, SECONDS l Amendment No. 7 March 31, 1982 C-E FULL P0WER LARGE SEAM LINE BREAK WITH Figure l CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S INTEGRATED STM MASS RELEASE THRU BREAKvsTIME 1. 13 i
i i 200 , , , i o 160 - - i Ui I E 1 5 g'120 - - II' 5 m M 80 -
)
O i li' di 40 _ _ l 0 l 0 100 200- 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE SEAM LINE BREAK WITH r; CONCURRENT LOSS OF 0FFSIE POWER 15!ur.1.5-S SAFETY INJECTION FLOW vs TIME 1, 14 l l l
O 25oo ' - - > TOP OF REACTOR VESSEL 2000 - - 1 LIQUID VOLUME N1500 - -
$c 5
8 W 1000 - - O i 500 TOP OF HOT LEG 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 O C-E March 31, 1982 FULL POWER lARGE SEAM LINE BREAK WITH Fi S CONCURRENT LOSS OF 0FFSITE POWER 15!ure1.5-REACTOR VESSEL LIQUID VOLUME vs TIME 1.15
l O J 10 , , , , I 8 -
. a:
o S6 - - EE hi 2 g4 - O !
- E 2
i i ' 0 I 0 100 200 300 400 500 TIME, SECONDS [ i Amendment No. 7 March 31, 1982 C-E FULL POWER lARGE STEAM LINE BREAK WITH pi l CONCURRENT LOSS OF 0FFSITE POWER 15$ur.1.5-
'E MINIMUM POST-TRIP DNBR vs TIME 1.16
1 150 i i i i 1 125 - i e
$ 1
? '
g 100 - 2 lei ng 75 -- 5 a.
~
\
O i g o a. 50 -- l l 1 8 50 - 0 I ' ' ' 0 100 200 300 400 500 , TIME, SECONDS l' Amendment No. 7 i March 31, 1982-l l C-E FULL POWER LARGE STEAM LINE BREAK WITH -Fi ur. OFFSITE POWER AVAILABLE S CORE POWER vs TIME 15'.1' 2I 5 l-L___--_-______------_-_. -- l
v 1 v 150 , , 5 d 125 - - l i- 1 0:: 1 100 o d i? 25 - s 75 - j g ! e 0 s 50 u_ l-
~C e 25 -
8 ! C '
~
' ' i 1
0 0 100 200 300 400 500 TIME, SECONDS l 1 l Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH r; j OFFSITE POWER AVAILABLE 15!ur,1.5- 1 S CORE HEAT FLUX vs TIME 2.2 ) l
0 1 2500 , i i i , 1 2000 -- -
)
< l
@1500 d' l a
m i
- p. W 1000 - -
Q a. x 500 - - 1 0 1 1 1 1 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure OFFSI1E POWER AVAILABLE 15,1,5-S RCS' PRESSURE vs TIME 2.3
i 50000 , , ,__ CORE 4 40000 - - l 8 m E 4
$ 3@00 - ~
AFFECTED SG LOOP ; VI 3: I g 20000 - INTACT SG LOOP i 2 z 5 ' 8 O o e l @@ - - f? o 6 x 0 - 1
-10000 I I I I 0 100 200 300 400 500 1 TIME, SECONDS Anendment No. 7 March 31, 1982 C-E , FULL POWEg.]E p SgggFgK WITH p;gur, l fjEPg / REACTOR COOLANT FLOW RATE vs TIME 15 5-
700 , , i i i CORE OUTLET m 600 N y CORE AVERAGE x l i2 CORE INLET 1 & 1 & 15% - - g E
$ N 8400 O 5 o ;
6 5 300 - - 200 I 'l I I 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 O C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur. OFFSITE POWER AVAILABLE 15 1.5-E REACTOR COOLANT TEMPERATURES C) vs TIME 2 3A i
.a V l l
700 i i i i i 1 e 6@ - - g AFFECTED SG HOT LEG s l 5 AFFECTED SG COLD LEG W ST - - h INTACT SG HOT LEG 5 1 84@ - - k e / \ R o INTACT SG COLD LEG l l 55 l x 3% - - l I I I I 200 O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 O March 31,1982
~~
C~E , FULL POWER LARGE STEAM LINE BREAK WITH sgur, SM@P8 // q OFFSITE POWER AVAILABE REACTOR COOLANT TEMPERATURES (B) vs TIME 1515-j.5B
O 10 i i i i 6 k MODERATOR - 3ts
$2 z
[ DOPPLER - l Y Y w l a D 5 -2 - - 5 O $ TOTAL SAEETv INJECTION
-6 - -
CEA I I I i
.10 ,
0 100 200 300 400 500 1 TIME, SECONDS j 1 Amendment No. 7 March 31, 1982 { C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur. OFFSITE POWER AVAILABLE S REACTIVITY CHANGES vs TIME 15'.1. 26 5 -
._ ______ __ _ j
1200 I i l l l 1 4 1000 - - l g' 800 -- -
]
5 8 ! e
@600- -
i B: 5 N (3 B2
'k.J 8 400 - _
0 E 200 - - 1 0 i i i i 0 100 200 300 400 500 1 TIME, SECONDS l l
' Amendment No. 7 March 31, 1982 C-E , FULL POWER LARGE STEAM LIN5 BREAK WITH Figure SEPS // OFFSITE POWER AVAILABLE PRESSURIZER WATER VOLUME vs TIME 15.1'5-2.7 c-_-- - - - -
O 1200 , , , i 1 1000 h - l l $ , s
! INTACT SEAM GENERATOR e 600 -
f2 D E b U lE 400 - [ AFFECTED STEAM GENERAT _ h 200 - I i 0 i i 0 100 200 300 400 500 TIME, SECONDS ; Amendment No. 7 [ March 31,1982 C-E Full POWER LARGE SEAM LINE BREAK WITH sgm 0FFSIE POWER AVAllABLE S STEAM GENERATOR PRESSURES vs TIME 15 5-
7000 , i i i 6000 - - S w iiE
"}
5000 -- - W B l d 4000 - s an b3000 - O !e
$2000 2 AFFECTED STEAM GENERATOR b
m . 1000 - - INTACT STEAM GENERATOR ! 0 N k ' ' u 0 100 200 300 400 500 TIME, SECONDS Amendment No. ) l
.( March 31, 1982 i
C-E FULL POWER LARGE STEAM LINE BREAK WITil pigu, , 1 0FFSITE POWER AVAILABLE E 15 1 5- ' STEAM GENERATOR BLOWDOWN RATES vs TIME p,j
1 0 ; 1 2500 , , , i j
\
i 2000 -- -
)
Ui 3: vi 1500 - W d 1000 - - ce
/ \ N V $
S i 500 - INTACT STEAM GENERATOR -
\ '
g AFFECTED SEAM GENERATOR 0 I i i i 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 , March 31, 1982 C-E , FULL POWER [ARGE SEAM LINE BREAK WITH p;8ur. OFFSIE POWER AVAllABLE SM6P8 / FEEDWAER FLOW RAES vs TIME 15.1.5-
I O 1 500 , i. i. i 400 - - 3 co t'300 a f M w I
]
g200 - -
-J O 5 Pu 4 W
100 - INTACT AND AFFECED STEAM GENERATORS 0- ' l- ' ' 0 100 200 300 400 500 TIME, SECONDS l
.Arendment No 7 -
March 31, 1982 C-E FULL POWER LARGE SEAM LINE BREAK WITH - OFFSIE POWER AVAILABLE ,1'i pf.u,, 1.5-E FEEDWARR ENTHALPY vs TIME 2.11 -I '
(J k 300000 i i i ' 1 i
% 250000 - -
x lE 3 N200000
=
E W \ E 150000 - INTACT STEAM GENERATOR l 100000 - - x hE g AFFECTED STEAM GENERATOR-50000 - _ w I I I I 0
- 0. 100 200 300 400 500 TIME, SECONDS i
Amendment No. 7 March 31, 1982
~
C-E FULL POWER LARGE STEAM LINE BkEAK WITH Figur. OFFSITE POWER AVAILABLE 15.1 5-S STEAM GENERATOR LIQUID MASS vs TIME 2.12
350000 i i i O 300000 - - l i 250000 - -
)
__i Bi 9 u_ 200000 - -
- E b
= l
/
y 150000 lO B W z
~
100000 - - 50000 -- -
' I i 1 0
0 100 200 300 400 500 TIME, SECONDS Amendment No. 7
, March 31, 1982 C-E , FULL POWER LARGE STEAM LINE BREAK WITH rigur, OFFSIE POWER AVAILABLE 5-SM5P8 / INEGRATED STEAM RELEASE vs TIME 15".1'3 2l
200 i i i I g 160 m
~
5 a g'120 - cc' 5 C
$ 80 - -
m 40 - -
' I I '
0 0 100 200 300 400 500 1 TIME, SECONDS l i Amendment No. 7 March 31,1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur. OFFSITE POWER AVAILABLE 15'1 5-SM6 SAFETY INJECTION FLOW vs TIME 2.14
2500- , .
, i i
\
2000 - TOP 0F REACTOR VESSEL l l LIQUID VOLUME y'1500 - - E5 x 8
$ 1000 -
O g S 500 - TOP 0F HOT LEG 0 ' ' ' ' 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 % l' c_g FULL POWER LARGE STEAM LINE BREAK WITH Figur. 0FFSITE POWER AVAILABLE 15.1.5-2 918[ REACTOR VESSEL LIQUID VOLUME vs TIME 2.15
0 150 , , , , 125 - - e W 2 d 100 - - 2 Ms 5 d e 75 - - O ifg 50 - y ; 8 25 - 0 ' O 100 200 300 400 500 ' TIME, SECONDS f Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH p; y,, CONCURRENT LOSS OF 0FFSITE POWER 15 1 5-E CORE POWER vs TIME
- 3. i s
l 150 , , i i l 5 d 1 25 - - H i' tl5 x 23 3: - - 2 100
.y 2
8 g 75 - - U ce O E LJ . s 50 - - d s 1 x W 25 - - 8 0^ l I I I 0 100 200 300 400 500 l TIME, SECONDS l Amendment No. 7 ' March 31, 1982
~
C-E , ZERO POWER UiRGE STEAM LINE BREAK WITH- iigu,, CONCURRENT LOSS OF 0FFSITE POWER 15 1 5_ E M P8 / CORE HEAT FLUX vs TIME 3.2_. i
C
-2500
, , , i l
1 2000 - G o- 1500 - - ur 5 l N w - E 1000 - - O e m 500 - - l 0 ' ' I I l 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7-March 31, 1982
^
C-E ZERO POWER LARGE STEAM LINE BREAK WITH Figure . . ! CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S RCS PRESSURE vs TIME 3,3
l c 50000 , , , , I 40000 - - M m E O 30000 - -
)
iI a
$20000 -
g CORE 5 n 8 V U 10000 - AFFECTED SG LOOP
$g ce
/
INTACT SG LOOP 1 I ' '
-10000 O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigur.
CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-2 REACTOR COOLANT FLOW RATE vs TIME 3.4 i L _ _ ____ _ _ _ _________._________ _____
i O l 700 , , , , 8-m 6@ - -
- U h CORE OUTLET 5 - -
& Sm g CORE AVERAGE
$2 5 -
@400 O g O
CORE INLET
@300 - _
i: i i I I 200 0 100 200 300 400 500 i i
/ nendment No. 7
) ~
March 31,1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH s . CONCURRENT LOSS OF 0FFSITE POWER 157y,,-1,5_ REACTOR COOLANT TEMPERATURES (A) vs TIME 3,5A
/'^N u
700 i i i q i l 1
, 600 INTACT SG HOT LEG O I'
- )
g 500 - INTACT SG COLD LEGS
- s W
!E !
$400 - -
1 O O AFF CTED SG V $ HOT LEG N i R o , 6 300 -
/
AFFECTED SG COLD LEGS I I i 1 200 0 100 200 300 400 500 TIME, SECONDS i Amendment No. 7 l (q March 31,1982
/
c_e ZERO POWER LARGE STEAM LINE BREAK WITH Fi8use i CONCURRENT LOSS OF OFFSITE POWER 15,1,5-S REACTOR COOLANT TEMPERATURES (B) vs TIME 3.5B
\ .I 10 i , i i MODERATOR 6 - -
c. l # 1 l vr D0PPLER g2 - - 5 5 x
~
M ~ / ~ E~ TOTAL U SAFE INJECTION Q
-6 CEA i
I
-10 I I I 0 100 200 300 400 500 TIME, SECONDS I
Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH p; u,, , CONCURRENT LOSS OF 0FFSITE POWER 15 1 5-EMB REACTIVITY CHANGES vs TIME j,f l
J l 1200 i i .- i i 1000- - - l 1 i I 800 -- - f 5 ! S
- e. 1 W \
g 600 -- - s O E m 4% - -
!O E
2@ - -
' ' I '
0 O 100 200 300 400 500 TIME, SECONDS 1
'l i
l 1 O, Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF 0FFSIE POWER 15.1.5-S PRESSURIZER WATER VOLUME vs TIME 3.7
0 1200' , , , i 1000 - - G o_
$ 800 - -
~
sm
!O 600 - INTACT STEAM GENERATOR e _
e O 8 o 400 - M 200 - AFFECTED STEAM GENERATOR _ l l 0 ' ' ' ' 0 100 200 300 400 500 TIME, SECONDS
& Amendment No. 7
(" _ March 31, 1982-C-E ZERO POWER LARGE STEAM LINE BREAK WITH H sgur. CONCURRENT LOSS OF 0FFSITE POWER S STEAM GENERATOR PRESSURES vs TIME 15'1'5-38
I 1 I 7000
'] , , , , .J 6000 - -
I B 52 5
" 5000- - -
Idi M a l 9 4000- - - z l $
$ l 9
=
3000 -- - l l 1 x f2 1 g AFFECED SEAM GENERATOR [z 2000 -- e
- E h
~ ~
INTACT SEAM GENERATOR
/
0 i i i l l 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 O C-E March 31, 1982 ZERO POWER LARGE SEAM LINE BREAK WITH n'u,, CONCURRENT LOSS OF 0FFSIE POWER 15-S SEAM GENERATOR BLOWDOWN RAES vs TIME 15.J 3 l
O 2500 , , i i g 2000 e i 5a y'1500 - M
.u I
$ 1000 -
O E S it INTACT SEAM GENERATOR 500 _ l l j AFFECTED SEAM GENERATOR l 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 [ March 31, 1982 ' C-E , ZERO POWER LARGE SEAM LINE BREAK WITH ngur.
- 23EP8 // CONCURRENT LOSS OF 0FFSITE POWER FEEDWAER FLOW RATES vs TIME 1lh05-L _ _ _ _ - _ - - _ _ - - _ - - _ -
q l O 1 450 i i i i 360 -- - 5 s 5 g 270 -- b s e 180 -- W O s Q lt! 90 INTACT AND AFFECTED STEAM GENERATORS 0' ! O 100 200 300 400 500 TIME, SECONDS l J Amendment No. 7 March 31,1982 l -l C-E '
//
ZERO POWER LARGE STEAM LINE BREAK WITH CONCURRENT LOSS OF 0FFSITE POWER Figure [ EMBP8 FEEDWATER ENTHALPY vs TIME 15'.1. 3 11 5- i
300000 i i i I ! I g 250000 - - vi
$ 200000 - -
!iE m 150000 - -
@ d I
g -INTACT SEAM GENERATOR l s O l f100000 - 5 s b m AFFECTED STEAM GENERATOR 50000 - 0 I I I I 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 f) LJ March 31, 1982 C-E ZERO POWER LARGE SEAM LINE BREAK WITH p;,ur. CONCURRENT LOSS OF 0FFSIE POWER 15*1.5-STEAM GENERATOR MASS INVENTORIES vs TIME 3 12 1 \ _ _ _ . _ __ _ _ _ _ _ -
i O 300000 , , , i q 250000 - - l w \
$ 200000 - - 1
??
s u_ l
- E l
@150000 -
w
)
O bf i O & \ V y100000 - -
]
5 50000 -- - 1 1 0 I I i 1 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 t March 31,1982 C-E ZERO POWER LARGE SEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF 0FFSITE POWER 15 1 5_ S INTEGRATED STM MASS RELEASE THRU BREAKvsTIME 3.15
l 1 200 i i i i 4 g 160 - - 50 g'120 - - II' 5 m
$M -
O l tt'
@) 40 - -
0 I I I I 0 100 200 300 400 500 TIME, SECONDS g C-E DEN'"3i! Yh27 ZERO POWER LARGE STEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-2 918 SAFETY INJECTION FLOW vs TIME 3,14
O 2500 i i i i TOP 0F REACTOR VESSEL 2000 - - 1 # --
$1500 LIQUID VOLUME -
$5 x
W 8 m 1000 a S SW - TOP 0F HOT LEG 0 0
/ '
100 200 I 300 I 400- 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigure ! CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-E REACTOR VESSEL LIQUID VOLUME ys TIME 3.15.__
0 150 i i i i I 125 .- - 5 s: 2 -- - d 100 , l E B t-J 0 75 1 5 c. I O e
@ 50 - - -
1 a W 8 25 - - 0' I I I ' 0 100 200 300 400 500 TIME, SECONDS 4 j Amendment No. 7 March 31,1982 C-E ZERO POWER LARGE SEAM LINE BREAK WITH rigur. OFFSIE POWER AVAILABLE 15.1*5-S CORE POWER vs TIME 4,1 l
150 , , , , l x l 3 125 m s x 1 5 !
@ IT
- - 1 a.
d I if i U5 75 - -
!iE u
e i li' 1 O- x - 50 { S u_ , I H 6 x 25 g 8 0> ' i 1 1 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 O March 31,1982 ' C-E ZERO POWER LARGE STEAM LINE BREAK WITH ri OFFSITE POWER AVAILABLE 15!ur.1.5-S CORE HEAT FLUX vs TIME 4.2
)
_-_________-___-__-_1
O 2500 i i i i 2000 - - i l 5
$ 1500 - -
u' a
$ k-
$1000 -
O E 500 - l I 0 1 i 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 O' C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigur. OFFSITE POWER AVAILABLE S RCS PRESSURE vs TIME 15.1.5-4.3 i
O 50000 , i i l CORE l 40000 - - o ) m E
$ 30000 -
AFFECTED SG LOOP lei
/
8 d 20000 - INTACT SG LOOP E 5 10000 __ e R o tl5 e 0 4
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15.2 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM k 15.2.1 LOSS OF EXTERNAL LOAD 15.2.1.1 Identification of Event and Causes The loss of external load event is caused by the disconnection of the turbine generator from the electrical distribution grid. 3 15.2.1.2 Scouence of Events and Systems Operation i A loss of external load generates a turbine trip which results in a reduction in steam flow from the steam ger;erators to the turbine due to the closure of the turbine stop valves. The steam bypass control system (SBCS) and reactor I power cutback system (RPCS) are both normally in the automatic mode and would be available upon turbine trip to accommodate the load rejection without necessitating reactor trip or the opening of main steam safety valves. Should j a turbine trip occur with these systems in manual mode, a complete termination ; of main steam flow results and reactor trip would occur on high pressurizer I pressure. If no credit is taken for immediate operator action, the main steam j safety valves will open to limit the secondary pressure increase and provide a l heat sink for the NSSS. The operator can initiate a controlled system cooldown using the SBCS any time after reactor trip occurs. 15.2.1.3 Analysis of Effects and Consequences O The results of the loss of load event are no more limiting with respect to RCS - pressurization than those of the loss of condenser vacuum (LOCV) event ! presented in Section 15.2.3. The LOCV also results in a turbine trip, however, ( feedwater flow is assumed to terminate following LOCV whereas it is assumed to j ramp down to 5% following the loss of load. This larger reduction in heat I removal capability results in a higher peak RCS pressure for the LOCV. ! Like the LOCV, the DNBR increases during the loss of load due to the increasing ! pressure. Thus, the initial DNBR is also the minimum DNBR. For the loss of l load, due to its similarity with the LOCV event, there are no concurrent single failures which when combined with the loss of external load result in consequences more severe than the LOCV event with respect to RCS pressur-ization. The limiting single failure with respect to fuel performance is the j loss of offsite power on turbine trip. This event with a concurrent loss of ! offsite power results in an event identical to the loss of flow (LOF) event i discussed in Section 15.3.1. Results of the LOF event are directly applicable to the loss of external load with loss of offsite power on turbine trip. 15.2.1.4 Conclusions 1 For the loss of load event and the loss of load with a concurrent single l failure, the RCS pressure remains below 2750 psia thus ensuring primary j integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding ; i ntegri ty. l l i i i Amendment No. 7 l 15.2-1 March 31,1982
m _ 15.2.2 TURBINE TRIP 15.2.2.1 Identification of Event and causes A turbine trip may result from a number of conditions which cause the turbine generator control system (TGCS) to initiate a turbine trip signal. A turbine trip initiates closure of the turbine stop values. 15.2.2.2 Sequence of Events and Systems Operation A turbine trip results in a reduction in steam flow from the steam generators to the turbine due to the closure of the turbine stop valves. The steam bypass control system (SBCS) and reactor power cutback system (RPCS) are both normally in the automatic mode and would be available upon turbine trip to accommodate the load rejection without necessitating reactor trip or the opening of main steam safety valves. Should a turbine trip occur with these systems in the manual mode, a complete termination of main steam flow results and reactor trip would occur on high pressurizer pressure. If no credit is taken for immediate operator action, the main steam safety valves will open to limit the secondary pressure increase and provide a heat sink for the NSSS. The operator can initiate a controlled system cooldown using the SBCS any time after reactor trip occurs. 15.2.2.3 Analysis of Effects and Consequences The results of the turbine trip event are no more limiting with respect to RCS l pressurization than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The LOCV also results in a turbine trip, however, feedwater flow is assumed to terminate following LOCV whereas it is assumed to , ramp down to 5% following the turbine trip. This larger reduction in heat I removal capability results in a larger peak RCS pressure for the LOCV. l l Like the LOCV, the DNBR increases during the turbine trip due to the increasing ! pressure. Thus, the initial DNBR is also the minimum DNBR for the loss of load. Due to its similarity with the LOCV events, there are no concurrent single failures which when combined with the turbine trip result in consequences more severe than the LOCV event with respect to RCS pressurization. The limiting single failure with respect to fuel performance is the loss of of fsite power on turbine trip. This event with a concurrent loss of offsite power results in an event nearly identical to the loss of AC power which initiates the loss of flow (LOF) event discussed in Section 15.3.1. Results of the LOF event are directly applicable to the turbine trip event with loss of offsite power. 15.2.2.4 Conclusions For the turbine trip event and the turbine trip with a concurrent single failure, the RCS pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integrity. O Amendment No. 7 15.2-2 March 31, 1982
v J 15.2.3 LOSS OF CONDENSER VACUUM 15.2.3.1 Identification of Event and Cause O
.- _.--- l A loss of condenser vacuum (LOCV) may occur due to the failure of the circulating water system to supply cooling water, failure of the main condenser evacuation system to remove noncondensible gases, or excessive in-leakage of air through a turbine gland. The turbine is assumed to trip immediately coincident with the cause for the loss of condenser vacuum.
When in the automatic mode, the Steam Bypass Control System (SBCS), if it controls atmospheric bypass valves, and the Reactor Power Cutback Sydem (RPCS) , will function to reduce the steam generator and RCS pressure increases during a ' turbine trip. These systems may allow the NSSS to continue operating at a reduced power level. However, in this analysis both the SBCS and RPCS are assumed to be in the manual mode and credit is not taken for their functioning. Consideration of single failures is addressed in Section 15.2.3.3D. l 15.2.3.2 Sequence of Events and Systems Operation Table 15.2.3-1 presents a chronological sequence of events which occur following the LOCV until operator action is initiated. Figure 15.0-1 contains a glossary of SEA symbols and acronyms which may be used with the Sequence of Events Diagram, Figure 15.2.3-1, to trace the actuation and interaction of the systems utilized to mitigate the consequences of this event. Table 15.2.3-2 contains a matrix which describes the extent to which normally g operating plant systems are assumed to function during the transient. The success paths in the Sequence of Events Diagram, Figure 15.2.3-1, are as foll ows: Reactivity Control: An automatic reactor trip occurs on high pressurizer pressure. The CEA's begin to fall and insert negative reactivity. After the reactor trip a SIAS is l generated on low pressurizer pressure. Additional negative reactivity is inserted when the borated safety injection water reaches the core. The boron concentration is adjusted to insure that a proper negative reactivity shutdown l margin 0 achieved prior to cooldown. The boron concentration is adjusted by manual', controlling the CVCS, If letdown is used for boration, the letdown isclation valves, which were closed on the SIAS/CIAS, must be reopened. Reactor Hedt Removal: A C* AS occurs on low pressurizer pressure, following which the component cooling water to the RCP's is lost. The operator restores cooling water to the reactor coolant pumps and a normal RCS cooldown is conducted. The SCS is mangally actuated when RCS temperature and pressure have been reduced to 350 F and 400 psia. This system provides sufficient cooling to bring the RU to cold shutdown. O 15.2-3 Amendment No. 7 March 3i, 1982
Primary System Integrity: A large reduction in primary system heat removal occurs when the main feedwater pumps and the turbine all trip. This causes tne RCS pressure to increase and open the Primary Safety Valves (PSVs). Steam is initially released from the PSVs to the Reactor Drain Tank (RDT). The total steam release (1634 lbm) { exceeds the RDT capacity and will probably cause the ruptare disc to fail. A j' CIAS generated on low pressurizer pressure isolates the RCP controlled bleedoff fl ow. The bleedoff relief valve opens and passes the bleedoff flow to the ruptured RDT. The containment building receives some of the PSV and bleedoff liquid released in this event. The pressurizer level is restored automatically by the safety injection flow, even though other means are available. During i cooldown, the pressurizer pressure and level control sys; ems are manually l operated to regulate pressure and level in the primary system. To perform this 1 action, the letdown isolation valves (which were closed on CIAS and SIAS) must 1 be opened. When the RCS pressure has been reduced to approximately 650 psia, the operator will vent or drain the SITS to reduce their pressure and will then isolate them. Secondary System Integrity: The turbine and main feedwater pumps automatically trip at time zero on the loss of condenser vacuum. The turbine stop valves close instantly and an SBCS interlock prevents the bypass valves from opening. The secondary system pressure increases and opens the main steam safety valves. Emergency feedwater flow reaches the steam generators and restores the levels. Cancellation and reactuation of emergency feedwater may occur since the main steam safety valves remain open until 346 seconds. Once the plant parameters are stabilized, the operator initiates cooldown by utilizina one feedwater pump designated as
" auxiliary" and intended for normal startup and shutdown of the plant in conjunction with the ASDS 'f this pump is part of a separate Auxiliary Feedwater System then he w. first secure the Emergency Feedwater System. He may also let the ESFAS regula;e the feedwater flow by issuing and withdrawing EFAS-1 and/or EFAS-2 5 ' gnals iown to cold shutdown entry conditions. See Applicant's FSAR fo- itails af the Emergency and/or Auxiliary Feedwater Systems.
Control Room Habitability: CI AS, SI AS or B0P signals may actuate control room habitability systems. See Applicent's FSAR for details. Fuel 81andling Building Habitability: CI A',, Sl AS or B0P signals may actuate fuel handling building habitability sy',tems . See Applicant's FSAR for details. Radioactive Effluent Control: CI AS isolates various systems to reduce or terminate radioactive releases. CIAS actuates primary, secondary, and containment isolation equipment. Other ' actions may be initiated by B0P systems. See Applicant's FSAR for details. i Amendment No. 7 15.2-4 March 31, 1982 i
n 15.2.3.3 Analysis of Effects and Consequences i 1 U A. Mathematical Model The NSSS response to a LOCV was simulated using the CESEC-II computer program described in Section 15.0. The initial DNBR was calculated using the TORC computer code (see Section 15.0.3.1.6) which uses the CE-1 CHF correlation described in Reference 19 of Section 15.0. B. Input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to a LOCV are discussed in Section 15.0. Table 15.2.3-4 contains the initial conditions and assumptions used for this event. The initial conditions for the principal process variables were varied within the ranges given in Table 15.0-5 to determine the set of initial conditions that would produce the trost l adverse consequences following a LOCV. Various combinations of initial core inlet temperature, core inlet flow, pressurizer pressure, steam generator level and pressurizer water level were considered in order to evaluate the effects on peak reactor coolant system (RCS) pressure. Decreasing the initial core inlet temperature reduces the initial steam generator pressure, thereby delaying the heat removal associated with the opening of the main steam safety valves. However, the initial inlet temperature for this event was restricted to a minimum of 560 F. Decreasing i the initial inlet temperature (as well as increasing the initial core flow rate) also minimizes the core average coolant temperature which results in the I y]/
/
most positive moderator temperature coefficient. l Reduction of the initial pressurizer pressure delays the occurrence of reactor trip on high pressurizer pressure and allows the maximum reduction in steam generator heat removal prior to and following trip. As a result maximum RCS overpressurization occurs, provided that the delay does not allow the main steam safety valves to open prior to reaching the peak pressure condition. Decreasing the initial pressurizer water level produces similar trip delays. C. Results The dynamic behavior of important NSSS parameters following the loss of condenser vacuum is Presented in Figures 15.2.3-2 to 15.2.3-14. The sudden reduction of steam flow, caused by the LOCV leads to a reduction of the primary-to-secondary heat transfer. The moderator reactivity increases slightly prior to the reactor trip due to a positive MTC as the average core
- temperature increases from thc initial conditions. This added reactivity causes the core power to reach a maximum at 6.8 seconds. The rapid heatup of the reactor coolant results in a high pressurizer pressure trip condition at 5.84 seconds. The reactor trip breakers open at 6.99 seconds and limit the lu maximum core power to 102% of full power.
The pressurizer safety valves open at 6.9 seconds and the maximum RCS pressure p of 2742 psia is reached ct 8.6 seconds. The main steam safety valves open at 6.7 seconds and the maximum secondary pressure of 1353 psia is reached at 14.0 (s) seconds. 10 15.2-5 Amendment No. 10 June 28, 1985 L -_ ___- _
The RCS pressure decreases rapidly due to the combined effects of reactor trip and primary and main steam safety valves. The pressurizer safety valves close at 12.0 seconds and the main steam safety valves close at 346.0 seconds. Emergency feedwater flow automatically begins at 44.1 seconds and continues to l10 fill the steam generators until a normal level is reached at 1408 seconds. At 964.1 seconds a safety injection actuation signal is generated when the l 10 pressurizer pressure decreases below 1580 psia. Borated water enters the RCS at 1150.0 seconds from the high pressure injection pumps. Thirty minutes af ter initiation of the events, the operator commences a cooldown using the atmospheric dump valves to release steam. The DNBR during the event, remains above its initial value of 1.4; therefore, DNB does not occur. D. Single Failures The LOCV event is assumed to abruptly and completely terminate both main steam and feedwater flow, Considering peak pressure criteria, the only mechanisms for mitigation of the reactor coolant system (RCS) pressurization are the pressurizer safety valves, the reactor coolant flow and main steam safety valves. The last two influence the RCS-to-steam generator heat transfer rate. There are no credible failures which can degrade pressurizer safety valve or main steam safety valve capacity. A decrease in RCS-to-steam generator heat transfer due to reactor coolant flow coastdown can only be caused by a failure 1 to fast transfer (FFT) to offsite power or a loss of offsite power (LOP) following turbine trip (i.e. , two or four pump coastdown, respectively), The two and four pump coastdowns result in an immediate reactor trip, generated by the Core Protection Calculators (CPC's). Due to the rapid reactor trip, both of these failures reduce the peak pressure relative to the LOCV itself. With regard to fuel performance, decreased coolant flow is the only parameter which can significantly reduce the minimum DNBR during the LOCV event. FFT and LOP are the only single failures which impact coolant flow. LOCV by q itself, however, produces an increasing DNBR (see F' are 15.2.3-2). This i results in a greater thermal margin than is requirL to preclude a DNBR below i 1.19 for either single failure. Consequently neither will cause fuel failure. LOP, however, because of the more rapid flow coastdown, causes a greater degradation in DNBR and hence is more limiting. The decrease in DNBR is shown in Figure 15.3.1-9. 15.2.3.4 Conclusions For both the loss of condenser vacuum event, and LOCV with a single failure, the maximum RCS pressure remains below 2760 psia, thus ensuring primary system integrity. The minimum DNBR remains above 1.19, thus ensuring fuel cladding integrity. l 1 0 15.2-6 Amendment No. 10 June 28, 1985
TABLE 15.2.3-1 (Sheet 1 of 2) O SE00ENCE OF EVENTS FOR THE LOCV Time Setpoint (Sec) Event or Value Success Path 0.0 Loss of Condenser Vacuym 5.84 Pressurizer Pressure Reaches Reactor 2450 Reactivity Trip Analysis Setpoint, psia Control 10 1 6.7 Main Steam Safety Valves 0 pen 1282 Secondary psia System Integrity 6.7 Steam Generator Water Level Reaches 40 Reactor Trip Analysis Setpoint; 10 percent of wide range 6.8 Maximum Core Power, % of Design 102 Reactivity Power Control 6.84 High Pressurizer Pressure Trip Reactivity Signal Generated Control 10 i p 6.9 Pressurizer Safety Valves, Open psia 2525 Primary Integrity System 6.99 Trip Breakers Open Reactivity 10 Coni:t ol 8.6 Maximum RCS Pressure, psia 2742 12.0 Pressurizer Safety Valves Close, 2462 Prima ry- ' psia System
' Integrity 14.0 Maximum Steam Generator Pressure, 1353 psia 33.1 Steam Generator Water Level Reaches 15 i Emergency Feedwater Actuation Signal Analysis Setpoint, percent of wide range 34.1 Emergency Feedwater Actuation 10 Signal Generated 44.1 Emergency Feedwater Flow 875 Secondary Initiated, gpm System Integrity.
Amendment No. 10 June 28, 1985
l TABLE 15.2.3-1 (Cont.)(Sheet E of 2) Time Setpoint (Sec) Event or Value Success Path 346.0 tiain Safety Valves Close, psia 1218 Secondary System Integrity 963.1 Pressurizer Pressure Reaches Safety 1580 Reactor Heat i Injection Actuation Signal Analysis Removal i Setpoint, psia 10 964.1 Safety Injection Actuation Reactor Heat Signal Generated Removal 993.7 Safety Injection Flow Initiated Primary System Integrity 1150.0 Borated HPSI Flow Enters the Core Reactivity Control 1408.0 Steam Generator Water Level 80 Secondary Reaches EFAS Reset Analysis System 10 Setpoint, p(rcent of wide range Integrity 1800.0 Operator Initiates Plant Cooldown Reactor Heat Removal 1 l l l O Amendment No. 10 June 28, 1985
v T_ABL E 15. 2. 3-2 (Sheet 1of2) DISPOSITIO i 0F fl0PfMLLY OPERATIt:G, SYSTEMS FOR LOCV ( A $# #
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- 1. Main Feedwater Control System j
- 2. Main Feedwater Pump Turbine Control System
- j
- 3. Turbine-Generator Control System * /
- 4. Steam Bypass Control System /
- 5. Pressurizer Pressure Control System /
V 6. Pressurizer Level Control System /
- 7. Control Element Drive Mechanism Control System /
- 8. Reactor Regulating System / l
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps /
- 11. Chemical and Volume Control System /
- 12. Secondary Chemistry control System * /
- 13. Condenser Evacuation System * /
- 14. Turbine Gland Sealing System * /
- 15. Iluclear Cooling Water System * /
- 16. Turbine Cooling Water System * /
- 17. Plant Cooling Water System * /
- 18. Condensate Storage facilities * /
- 19. Circulating Water System * /
- 20. Spent Fuel Pool Cooling and Clean-Up System * /
p 21. lion-Class 1E (tien-ESF) A.C. Power * / V 22. Class IE (ESF) A.C. Power * / 2
*Dalance-of-Plant Systems Ame .dment No. 7 '
March 31, 1982 ;
, TABLE 1 s.2.3 2 (C0!iillIVED)_ (Sheet 2 of 2)
DISPOSITI0il 0F f:0RMALLY OPERATI!!G SYSTEMS FOR LOCV O
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- 24. Class lE D.C. Power * /
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~ 7 TABLE 15.2.3-3 . i UTILIZATIO!1 0F SAFETY SYSTEMS 7m, FOR LOCV l V i l y C %, , g$ #c' O f;
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- 1. Reactor Protection System / !
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- 2. DiiBR/LPD Calculator 1
- 3. Engineered Safety Features Actuation Systems /
- 4. Supplementary Protection System 1
- 5. Reactor Trip Switch Gear /
{ '
- 6. Main Steam Safety Valves * /
- 7. Primary Safety Valves /
- 8. Main Steam Isolation System * / l
- 9. Emergency Feedwater System * /
- 10. Safety Injection System /
l
- 11. Shutdown Cooling System /
- 12. Atmospheric Dump Valve System * /
- 13. Containment Isolation System * /
l 14. Containment Spray System *
- 15. Iodine Removal System *
- 16. Containment Combustible Gas Control System *
, 17. ,
Diesel Generators and Support Systems *
- 18. Component (Essential) Cooling Water System * /
- 19. Station Service Water System * /
flotes: 9 1. Safety grade back-up to a safety grade system. < 4 1
- Balance-of-Plant Systems -
NUEH"'3T, Td82'
TABLE 15.2.3-4 ASSUMED INITIAL CONDITIONS FOR LOCV Parameter Assumed Value Initial Core Power Level, Mwt 3876 Core Inlet Coolant Temperature, OF 560 6 Core Mass Flow, 10 lbm/hr 193.7 Pressurizer Pressure, psia 2200 Initial Pressurizer Water Level, Percent 26 of wide range Initial Core Minimum DNBR 1.4 ! Radial Peaking Factor 1.62 { l Steam Generator Water Level, percent of 61 l wide range Doppler Coefficient Multiplier 0.85 ' CEA Worth for Trip,10 -2 6p -10.0 Amendment No. 7 March 31, 1982 I
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15.2.4 MAIN STEAM ISOLATION VALVE CLOSURE 15.2.4.1 Identification of Event and Causes The main steam isolation valve (MSIV) closure event is initiated by the closure of all MSIV due to a spurious closure signal. 15.2.4.2 Sequence of Events and Systems Operation The closure of all MSIV's results in the termination of all main steam flow. The decreased heat removal results in increasing primary and secondary temperatures and pressure. Reactor trip occurs on high pressurizer pressure. The pressure' increases in the primary and secondary systems are limited by the pressurizer and steam generator safety valves. The operator can initiate a controlled system cooldown using the steam bypass control system any time after reactor trip occurs. - 15.2.4.3 Analysis of Effects and Consequences The results of the MSIV closure event are no more limiting with respect- to RCS pressurization than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The LOCV also results in the termination o' all main steam flow. However, main steam flow is terminated more rapidly during the LOCV since the closure time for the turbine stop valves is much shorter-than that for the MSIVs. The faster reduction in heat removal results in a higher peek RCS pressure for the LOCV event. Like the LOCV, the DNBR increases during the MSIV closure event due to the increasing pressure. Thus, the iritial DNBR is also the minimum DNBR for the MSIV closure event. Due to it similarity with the LOCV event, there are no concurrent single failures which when combined with the MSIV closure event result in consequences more severe than the LOCV event with respect to RCS pressurization. The limiting single failure with respect to fuel performance is the loss of offsite - power on turbine trip. This event with a concurrent loss of offsite power ! results in an event nearly identical to the loss of AC power which initiates the loss of flow (LOF) event discussed in section 15.3.2. Results of the LOF event are directly applicable to the MSIV closure with loss of offsite power on turbine trip. I 15.2.4.4 Conclusions For the MSIV closure event and the MSIV closure with a concurrent single failure, the RCS pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integrity. 15.2.5 STEAM PRESSURE REGULATOR FAILURE This event does not apply to the CESSAR SYSTEM 80 design and therefore is not presented. O Amendment No. 7 15.2-7 March 31, 1982
15.2.6 LOSS OF NON-EMERGENCY A-C POWER TO THE STATI0H AUXILIARIES 15.2.6.1 Identification of Event and Causes The loss of non-emergency AC power to the station auxiliaries (LOAC) may result 3 from either a complete loss of the external grid or a loss of the onsite AC distribution system. The LOAC is presented as the initiating event for the four pump loss of flow event discussed in Section 15.3.1. 15.2.6.2 Sequence of Events and System Operation When all normal AC power is assumed to be lost to the plant, the turbine stop l valves close, and it is assumed that the area of the turbine control valves is j instantaneously reduced to zero. Also, the feedwater flow to both steam generators is instanteously assumed to go to zero. The reactor coolant pumps coast down and th
- reactor coolant flow begins to decrease. A reactor trip wM1 occur as a csult of a low DNBR condition as the flow coastdown begins.
The pressure increases in the RCS and steam generators are limited by the pressurizer and steam generator safety valves. The loss of all normal AC power is followed by automatic startup of the standby diesel generators, the power output of which is sufficient to supply electrical power to all necessary engineered safety features system and to provide the l capability of maintaining the plant in a safe shutdown condition. Subsequent ! to the reactor trip, stored and fission product decay energy must be dissipated l by the reactor coolant system and main steam system. In the absence of forced I reactor coolant flow, convective heat transfer coolant flow. Initially, the l residual water inventory in the steam generators is used as a heat sink, and the resultant steam is released to atmosphere by the spring-loaded steam generator safety valves. With the availability of standby diesel power, emergency feedwater is automatically initiated on a low steam generator wates level signal. Plant cooldown is operator controlled via the atmospheric dump valves until offsite power is restored at which time the steam bypass control j system and the condenser are utilized for the remainder of the cooldown. 15.2.6.3 Analysis of Effects and Consequences The results of the LOAC event are identical to those of the loss of reactor coolant flow event presented in Section 15.3.1 and are no more limiting with respect to RCS pressurization than the loss of condenser vacuum (LOCV) event discussed in Section 15.2.3. During the LOCV event the plant experiences simultaneous losses of steam and Nedwater flow and condenser availability. In addition, the plant experiences a complete loss of forced reactor coolant flow during the LOAC event. The loss of forced reactor coolant flow results in an earlier reactor trip for the LOAC event (on projected low DNBR) compared to the reactor trip for the LOCV event (on high pressurizer pressure). The earlier trip promotes a less severe primary-to-secondary heat imbalance and hence a lower peak RCS pressure for the LOAC event. The fuel performance for the LOAC is no more limiting than that for the loss of flow (LOF) event discussed in Section 15.3.1. The LOAC is the initiating event for the LOF so the fuel performance results of the LOF event are directly applicable to the LOAC event. O Amendment No. 7 March 31, 1982 15.2-8
w l 4 15.2.6.4 Conclusions
]
For the LOAC event and the LOAC with a concurrent single failure, the RCS pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integrity. 15.2.7 LOSS OF NORMAL FEEDWATER FLOW 15.2.7.1 Identification of Event and Causes The loss of normal feedwater flow (LFW) event may be initiated by losing one or both main feedwater pumps or by a spurious signal being generated by the feedwater control system resulting in a closure of the feedwater control i valve (s). I 1 l 15.2.7.2 Sequence of Events and Systems Operation LFW results in decreasing water level and increasing pressure and temperature - in the steam generators. The RCS pressure and temperature also rise until a l reactor trip occurs either due to low steam generator water level or high i pressurizer pressure. Assuming the steam bypass control system (SBCS) is in the manual mode of operation, termination of main steam flow due to closure of
~
the turbine stop valves following reactor trip temporarily causes steam generator and RCS pressurization. The decrease in core heat rate after insertion of the CEAs in combination with the main steam safety valves opening restores the RCS to a new steady state condition. Emergency feedwater flow is automatically initiated on a low steam generator water level assuring sufficient steam generator inventory for core decay heat removal and cooldown i to shutdown cooling entrance conditions. The cooldown is operator controlled 1 using the SBCS and the condenser. 15.2.7.3 Analysis of Effects and Consequences ! The maximum RCS pressure for the LFW event is less than that for the loss of condenser vacuum (LOCV) event discussed in Section 15.2.3. The LOCV event l results in the termination of main steam flow prior to reactor trip in addition I to the total loss of normal feedwater flow. This additional condition aggravates RCS pressurization by further reducing the rate of primary-to-secondary heat transfer below that of the LFW event. Like the LOCV, the DNBR increases during the LFW event due to the increasing RCS presure. Thus the initial DNBR is also the minimum DNBR for the LFW event. There are no concurrent single failures which when combined with LFW result in consequences more severe than the LOCV event with respect to RCS pressur-ization. The limiting single failure with respect to fuel performance is the loss of , offsite power following turbine trip. For the LFW event, prior to turbine trip the DNBR increases due to the RCS pressure increase. DNBR then briefly decreases after turbine trip due to the reactor coolant flow coast down on loss p of offsite power. The DNBR decreases similar to the DNBR transient associated 15.2-9 Amendment No. 7 March 31, 1982
with the total loss of reactor coolant flow event shown in Section 15.3.1, however, the DNBR decrease for LFW is not as severe due to the earlier reactor trip relative to the initiation of the coolant flow coastdown. Therefore, the minimum DNBR remains above 1.19. 15.2.7.4 Conclusions . For the loss of feedwater flow event and the loss of feedwater flow with a concurrent single failure the RCS pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integrity. 15.2.8 Feedwater System Pipe Breaks Appendix 15B describes the methods used to evaluate the feedwater pipe breaks, and the results of the evaluation. 1 O l l l l 9 Amendment No. 7 March 31, 1982 15.2-10
l 15.3 DECREASE IN REACTOR COOLANT FLOWRATE 1 l' 15.3.1 TOTAL LOSS OF REACTOR COOLANT FLOW 15.3.1.1 Identification of Events and Causes A complete loss of forced reactor coolant flow will result from the i simultaneous loss of electrical power to all reactor coolant pumps (RCPs). ] The only credible failure which can result in a simultaneous loss of power is a i complete loss of offsite power. In addition, since a loss of offsite power is assumed to result in a turbine trip and renders the steam dump and b" pass system unavailable, the plant cooldown is performed utilizing the s~ ondary valves and atmospheric dump valves. A total loss of forced reactor coolant flow will produce a minimum DNBR more i adverse than any partial loss of forced reactor coolant flow event. I l The loss of offsite power event plus a single failure will not result in a l lower DNBR than that calculated for the loss of offsite power event alone. For ) decreasing reactor coolant flow events, the major parameter of concern is the minimum hot channel DNBR. This parameter established whether a fuel design limit has been violated and, thus, whether fuel damage might be anticipated. Those factors which cause a decrease in local DNBR are:
- a. increasing coolant temperature )
- b. decreasing coolant pressure
- c. increasing local heat flux (including radial and axial power O
distribution effects) I
- d. decreasing coolant flow For the loss of offsite power event, the minimum DNBR occurs during the first few seconds of the transient and the reactor is tripped by the CPCs on the approach to the DNBR limit. Therefore, any single failure which would result in a lower DNBR during the transient would have to affect at least one of the above parameters during the first few seconds of the event. None of the single failures listed in Table 15.0-6 will have any effect on the transient minimum DNBR during this period of time.
Additionally, none of the single failures listed in Table 15.0-6 vil have any effect on the peak primary system pressure. The loss of offsite power will make unavailable any systems whose failure could affect the calculated peak pressure. For example, a failure of the steam dump and bypass system to modulate or quick open and a failure of the pressurizer spray control valve to open involve systems (Steam Dump and Bypass System and Pressurizer Pressure Control System (PPCS) which are assumed to be in the manual mode as a result of the loss of offsite power and, hence, unavailable for at least 30 minutes. Another example involving the PPCS would be the failure of the back-up heaters to turn off. Since the event is characterized by increasing RCS pressure, the back-up heaters will not be called upon to operate in such a transient. For the reasons stated in the above paragraphs the loss of offsite power event with a single failure is no more adverse than the loss of offsite power event in terms of the minimum DNBR and peak primary system pressure. 5 ( Amendment No. 7 15.3-1 March 31, 1982
15.3.1.2 Sequence of Events and Systems Operation Table 15.3.1-1 presents a chronological list and time of systems actions which ! occur during the total loss of reactor coolant flow event. Refer to Tcble i 15.3.1-1 while reading this and the following section. The success paths ! referenced in Table 15.3.1-1 are those given on the sequence of events diagram ! (SED), Figure 15.3.1-1. This figure, together with Figure 15.0-1, which contains a glossary of SED symbols and acronyms, may be used to trace the actuation and interaction of the systems used to mitigate the consequences of this event. The timings in Table 15.3.1-1 may be used to determine when, after event initiation each action occurs. The sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event. If offsite power can be restored, then the operator may elect instead to stabilize the plant at a mode other than cold shutdown. All actions required to stabilize the plant and perform the required repairs are not described here. The sequence of events and systems operations described below represents the way in which the plant was assumed to respond to the event initiator. Many plant responses are possible. However, certain responses are limiting with respect to the acceptance guidelines for this section. Of the limiting responses, the most likely one to be followed was selected. Table 15.3.1-2 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient. Table 15.3.1-3 contains a matrix which describes the extent to which safety ! systems are assumed to function during the transient. The success paths in the sequence of events diagram, Figure 15.3.1-1, are as follows: Reactivity Control: A loss of electrical power to all reactor coolant pumps produces a reduction of coolant ficw through the reactor core. The reduction in coolant flow rate causes an increase in the core average coolant temperature with a concurrent i' decrease in the margin to DNB. A low DNBR reactor trip is generated by the core protection calculators, as described in Section 7.2. This prevents the minimum DNBR calculated with the CE-1 CHF correlation from decreasing to less ) than 1.19 at any time during the transient. The CEAs begin to drop into the l core 1.09 seconds after the loss of electrical power to the RCPs inserting j negative reactivity. The 1.09 second delay conservatively includes the largest possible delay times for sensor delays, CPC calculation period, CEDM dead time, and CEDM coil decay time. Prior to initiating or during manual cooldown the operator adjusts the boron concentration to insure that a proper negative reactivity shutdown margin is achieved. This is accomplished by using the HPSI pumps which also replace RCS volume shrinkage. The operator must also borate using the charging pumps by manually loading them on the diesel generators and then aligning them to the refueling water tank (RWT), the source of borated water. ' Amendment No. 7 15.3-2 March 31, 1982 l
Reactor Heat Removal: O V Following the total loss of reactor coolant flow, reactor heat removal takes place by means of natural circulation. The steam generators provide primary to secondary heat transfer. The Shutdown Cooling System (SCS)0is manually actuated when RCS temperature and pressure have been reduced to 350 F and 400 psia, respectively. This system provides sufficient cooling flow to cool the RCS to cold snutdown conditions. . Secondary System Integrity: 1 The turbine is-assumed to trip our loss of offsite power. The loss of offsite power produces a loss of load on the turbine which generates a turbine trip si gnal . The turbine stop valves are closed as a result of. the trip. The steam a bypass control system becomes unavailable due to the loss of offsite power and subsequent loss of condenser vacuum. Also, as a result of the loss of condensor vacuum, main feedwater flow to the steam generators is lost. This l sequence of events results in opening of the Main Steam Safety Valves ; (MSSVs) which limits secondary system pressure and removes heat stored in the core and the RCS. Once the flow parameters are stablized, the operator j initiates cooldown (assumed to be initiated 30 minutes after event initiation) utilizing the Auxiliary Feedwater System ( AFWS) and the atmospheric dump valves. The AFWS may be a separate system or may be one emergency feedwater pump ! designated as " auxiliary" and intended for normal startup and shutdown of the l l plant. The operator may let the ESFAS regulate the feedwater flow by i t issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown , entry conditions. See Applicant's FSAR for details of the Emergency and/or I Auxiliary Feedwater Systems. As the cooldown proceeds, the operator reduces , the main steam isolation actuation setpoint to prevent the inadvertent l generation of an MSIS. Primary System Integrity: The pressurizer assists in the control of the RCS prssure and volume changes during the transient by compensating for the initial expansion of the RCS fluids. The combination of the loss of primary system heat sink (turbine stop valves close) with the reduction of reactor coolant flow results in an increase in RCS pressure which is limited by the primary safety valvec. The reactor drain tank receives the released steam. During the coo'Uc, the operator may control RCS pressure and pressurizer level by turning on the HPSI pumps and throttling the HPSI discharge valves to control the rate of change of RCS pressure. The operator may also control RCS pressure and pressurizer level via manual actuation and control of the charging pumps and related auxiliary spray. As the cooldown proceeds, the operator will reduce the safety injection actuation setpoint to prevent the inadvertent generation of an SIAS. When the RCS pressure has been reduced to approximately 650 psia, the operator will vent or drain the safety injection tanks to reduce their pressure and will isolate them. 15.3 3 Amendment No. 7 March 31, 1982
l i Restoration of AC Power: l A low voltage on the 4.16 kV safety buses generates an undervoltage signal which starts the diesel generators. The non-safety buses are automatically separated from the safety buses and all loads are shed (except for load centers). After < ich diesel generator set has attained operating voltage and frequency, its ouipt breaker closes connecting it to its safety bus. ESF equipment is then loaded in sequence on to this bus. Spent Fuel Heat Removal: Spent Fuel Pool (SFP) cooling is terminated on the loss of normal power to the ESF loads. Spent fuel heat removal is continuously accomplished by utilizing the heat capac!ty of the SFP water. Pool cooling is restored by manually loading the SFP cooling pumps onto the diesel generators and by aligning the l
~
SFP heat exchangers to receive essential cooling water. 15.3.1-3 Analysis of Effects and Consequences A. Mathematical Mode The NSSS response to a total loss of reactor coolant flow was simulated using ' the CESEC-II computer program described in Section 15.0.3. The minimum DNBR was calculated using the TORC computer code (see Section 15.0.3.) which uses ; the CE-1 CHF correlation described in Reference 19 of Section 15.0, and the ; HERMITE computer code described in Reference 17 of Section 15.0. B. Input Parameters and Initial Conditions i The input parameters and initial conditions used to analyze the NSSS response to a total loss of flow are discussed in Section 15.0. The parameters, which are unique to the analysis, discussed below, are listed in Table 15.3.1-4. The principal process variables that determine thermal margin to DNB in the core are monitored by COLSS. COLSS computes a power-operating limit which assists the operator in maintaining the thermal margin in the core equal to or , greater than that needed to cause the minimum DNBR to remain greater than 1.19, for a four pump loss of flow, assuming immediate reactor trip. COLSS is described in Section 7.7. The set of initial conditions chosen for the analysis presented in this section is one of a very large number of combinations within the reactor operating space given in Table 15.0-5 which would provide the minimum thermal margin required by the COLSS power operating li mi t. The consequences following a total loss of flow initiated from any one of these combinations of conditions would be no more adverse than those presented herein. C. Results The dynomic behavior of important NSSS parameters following a total loss of reactor coolant flow is provided in Figures 15.3.1-2 to 15.3.1-9. l The loss of offsite power causes the plant to experdnce a simultaneous turbine trip, loss of main feedwater, condenser inoperability, ad a four reactor l coolant pump coastdown. The loss of steam flow due to alosure of the turbine ] stop valves results in a rapid increase in the steam generator pressure. A 15.3 4 Amendment No. 7 March 31, 1982 i
m i (7 sharp reduction in primary to secondary heat transfer follows which, in
, I conjunction with the loss of forced reactor coolant flow, causes a rapid heat up of the primary coolant. The pressurizer safety valves open at 4.3 seconds, )
and the MSSys open at 5.4 seconds. The RCS pressure reaches a maximum of 2576 ' psia at 5.3 seconds (Figure 15.3.1-4). This is less than 110% of design pressure. At 11.7 seconds the secondary pressure reaches its maximum value of 1338 psia (Figure 15.3.1-8). This pressure is also less than 110% of design pressure. Subsequently, the RCS pressure decreases rapidly as the combination of reactor trip and primary and main steam safety valves opening reduce the reactor coolant system energy. The pressurizer safety valves close at 12.2 seconds. A second pressura increase occurs as a result of increasing RCS temperatures caused by the degrading primary to secondary heat transfer resulting from the continuously decreasing reactor coolant system flow rate. The rise in RCS temperatures increases the primary to secondary heat trans'er until the heat removed by the secondary system exceeds tne primary system heat generation. At this time the RCS temperatures, and subsequently the pressure, begin to decrease. After 30 minutes, the operator commences cooldown using the auxiliary feedwater system and the atmospheric dump valves. l The minimum CE-1 DNBR calculated to occur during the transiert is 1.19 (Figure 15.3.1-9); thus, no fuel pins are assumed to experienc DNB for this event. 15.3.1.5 Conclusions L The maximum RCS and secondary system pressures remain within 110% of their design values following the total loss of forced reactor coolant flow event. The minimum DNBR calculated to occur during the transient is 1.19 which ensures that the specified acceptable fuel design limit is not violated. ' l l 15.3-5 Amendment No. 7 March 31,1982
O THIS PAGE INTENTIONALLY BLANK. O l l O
TABLE 15.3.1-1 w ; i SEQUENCE OF EVENTS FOR TOTAL LOSS OF REACTOR COOLANT FLOW I Time Setpoint (Sec) Event or Value Success Path-0.0 Loss of Offsite Power
--Turbine Trip
- Diesel Generator Starting Signal
- Reactor Coolant Pumps Coast Down
- Loss of Main Feedwater i
-Reactivity O.6 Lcw DNBR Trip Signai 1.19 10 .,
Generated, Projected DNBR Control 0.75 Trip Breakers Open Reactivity ) Control- -l 1.09 CEA's Begin to Drop Reactivity ' Control 2.6 Minimum Transient DNBR 1.19 4.3 Pressurizer Safety Valves Open, 2525 Primary psia System ( i Integrity 5.3 Maximum RCS Pressure, psia 2576 5.-4 Main Steam Safety Valves 1282 Secondary Open, psia System 10 Integrity 11.7 Maximum Steam Generator Pressure, 1338 psia : 12.2 Pressurizer Safety Valves Closed, 7463 Primary psia System Integrity 1800.0 Operator Initiates Plant Cooldown I LO Amendment No.10 June 28,1985 >
TABLE 15.3.1-2 (Sheet 1 of 2) DISPOSITION OF NORMALLY OPERATING SYSTEMS j FOR THE TOTAL LOSS OF REACTOR COOLANT FLOW 9 x \
'O-we Ef, 9.,
9'
'vg, 5G( ug-p -Q.
F h ',' , -
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\e @No r
%$ be 7
'O 1
j p
- 1. liain Feedwater Control System /
- 2. Main Feedwater Pump Turbine Control System * /
- 3. Turbine-Generator Control System * /
- 4. Steam Bypass Control System /
- 5. Pressurizer Pressure Control System /
- 6. Prenurizer Level Control System /
- 7. Control Element Drive Mechanism Control System /
- 8. Reactor P,egulating System /
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps /
- 11. Chemical and Volume Control System / l
- 12. Secondary Chemistry control System * /
- 13. Condenser Evacuation System * /
- 14. Turbine Gland Scaling System * /
- 15. Nucicar Cooling Water System * / l
- 16. Turbine Cooling L'ater System * /
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities * /
- 19. Circulating Water System * /
- 20. Spent Fuel Pool Cooling and Clean-Up System * / l
- 21. Non-Class lE (Ncn-ESF) A.C. Power * / 1
- 22. Class IE (ESF) A.C. Power * / j
- Calance-of-Plant Systems -
g- g=-6 March 31, 1982
TABLE 15.3.1-2 (Cont'd) (Sheet 2 of 2) l DISPOSITION OF NORMALLY OPERATING SYSTEMS
~
FOR THE TOTAL LOSS OF REACTOR COOLANT FLOW
\. ,o, o
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'O SYSTEM -
- 23. !!on-Class lE D.C. Power * /
- 24. Class lE D.C. Power * /
Notes:
- 1. Failure in this system is the initiating event. 4 O
l l l l i l i i li i !
.j .
l
- Balance-of-Plant. Systems j ,
m y g go, , - March 31, 1982
TABLE 15.3.1-3 i i UTILIZATION OF SAFETY SYSTEMS FOR THE TOTAL LOSS OF REACTOR COOLANT FLOW 9 s s vs , v,,1, o
,0 ,c's,
%Q s*Et>
f , 'A h eo d 6, bp j Cy 6p
#b #,
b
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l Engineered Safety Features Actuation Systems /
; 3.
1 I
- 4. Supplementary Protection System I
i 5. Reactor Trip 9.iitch Gear / Main Steam Safety Valves * / 6.
- 7. Primary Safety Valves /
j Main Steca Isolation System * / / 2 (! 8. Emergercy Feed, tater System * / l 9.
- 10. Safety injection System
- 11. Shutdown Cooling Systcm / 2
/ 2 Atmospheric Dump Valve System * .l 12. Containment Isolation System
- 13.
- 14. Containment Spray System *
- 15. Iodine Removal System
- i 16. Containment Combustible Gas Control System +
3
- 17. Diesel Generators and Support Systems * /
- 18. Component (Essential) Cooling l!ater System * /
- 19. Station Service Water System * /
[kleS:
- 1. Safety grade back-up to a safety gr ade system. ,
- 2. Manually actuated during normal cooldown.
*P.alance-of-Plant Systems -
. _ __ .---kendment10. T~~~
March 31. 1982 J
I TABLE 15.3.1-4
/N ASSUMED INITIAL CONDITIONS FOR TOTAL LOSS OF REACTOR COOLANT FLOW Parameter Value j l
Core Power Level, MWt 3876- ! l Core Inlet Coolant Temperature, F 565 l Reactor Coolant System Pressure, psia 2250 Steam Generator Pressure, psia 1070 Core Mass Flow, 10 6 lbm/hr 157.4 Core Minimum DNBR - 1.51 Maximum Radial Power Peaking Factor 1.62 l Maximum Axial Power Peak 1.47 l CEA Worth on Trip,10-2 Ap -10.0 (most reactive CEA Stuck) l l n l l l l i l l l l D ' O Amendment No. 7 March 31, 1982
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v 15.3.2 FLOW CONTROLLER MALFUNCTION CAUSING FLOW C0ASTDOWN ( This event is categorized as a Boiling Water Reactor event in SRP 15.3.2 and, therefore, will not be analyzed. 15.3.3 SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER 15.3.3.1 Identification of Event and Causes A single reactor coolant pump rotor seizure can be caused by seizure of the upper or lower thrust-journal bearings. Loss of offsite power subsequent to l8 l turbine / generator trip may be caused by a complete loss of the external electrical grid triggered by the turbine / generator trip. The loss of offsite ; power causes a loss of power to the start-up transformers which prevents the l l plant electrical loads from being transferred to them from the unit auxiliary l transformers. Therefore, the onsite locds will lose power and the plant will experience a simultaneous loss of feedwater flow, condenter inoperability, and l8 a coastdowr. of all reactor coolant pump. Approximately 12 seconds after the loss of offsite power occurs the diesel generators start providing power to the two plant 4.16 kV safety buses. No credit is taken for restoration of offsite power prior to initiation of shutdown cooling. For decreasing reactor coolant flow events, the major parameter of concern is , the minimum hot channel DNBR. This parameter establishes whether a fuel ! design limit has been violated and, thus, whether fuel damage could be j anticipated. Those factors which cause a decrease in local DNBR are: h a. b. increasing coolant temperature decreasing coolant pressure
- c. increasin ,
effects) g local hea+ flux (including radial and axial power distribution I
- d. decreasing coolant flow For the single reactor coolant pump rotor seizure event, the minimum DNBR 8 occurs during the first one to four seconds of the transient, and the reactor l is tripped by the CPCs on the approach to the DNBR limit. Therefore, any single failure which would result in a lower DNBR during the transient would have to affect at least one of the above parameters during the first one to four seconds of the event.
l The single failures that have been postulated are listed in Table 15.0-6. Most of these failures affect the secondary system, and during the first one to four seconds they do not affect the primary system parameters which determine the DNBR. The only failures which could affect the RCS behavior during this interval are (1) a loss of normal AC, (2) a failure of the pressurizer level control system, (3) a failure of the pressurizer pressure l control system, and (4) a failure of the reactor regulating system. The loss 1 0 15.3-6 Amendment Number 8 May 10,1983
of normal AC power, which is assumed, results in loss of power to the reactor coolant pumps, the condensate pumps, the circulating water pumps, the pressurizer pressure and level control systems, the reactor regulating system, and the feedwater control system. Loss of function of the condensate and circulating water pumps and 'he feedwater control system initially affect only the secondary system ad, thus, do not affect DNBR in the first one to four seconds of the transient. Loss of power to the reactor regulating system and pressurizer level and pressure control systems renders those systems inoperable. This inoperability will have no significant impact on DNBR during the first one to four seconds. Loss of power to the reactor coolant pumps is the only potentially significant failure with regard to DNBR which results from a loss of AC. However, as a result of a three second delay between the time of turbine trip and the time 8 of loss of offsite power, there is no effect on minimum DNBR. Failure of the pressurizer level control, pressure control, or reactor regulating systems cannot appreciably affect any of the four factors which determine DNBR during the first one to four seconds of the event. Thus, none of the single failures listed in Table 15.0-6 will result in a more adverse transient minimum DNBR than that predicted for the single reactor coolant pump rotor seizure event. The assumed loss of AC renders the steam bypass control system inoperable as a result of the loss of the circulating water pumps. This results in the secondary safety valves system (prior energy being to operator released action) and to thethe atmosphereDump Atmospheric by the secondary (ADV) Valves after operator action is assumed. Operator action is assumed at 1800 seconds 8 into the transient. At this time the operator begins a controlled cooldown of , the plant. A single active failure of an ADV to close is assumed at 1800 seconds. The stuck open ADV causes the eventual dryout of the affected steam generator which results in all of the iodine contained in this steam generator being released to atmosphere. Thus, this failure in combination with the loss of offsite power maximizes the radiological consequences of the single reactor coolant pump rotor seizure event. None of the other single failures listed in Table 15.0-6 in combination with a loss of AC will yield more severe radiological consequences. 15.3.3.2 Sequence of Events and System Operation Table 15.3.3-1 presents a chronological list and time of system actions which occur following the single reactor coolant pump rotor seizure event. Refer to Table 15.3.3-1 while reading this and the following section. The success l8 raths referenced are those given on the Sequence of Events Diagram (SED), Figure 15.3.3-1. This figure, together with Figure 15.0-1, which contains a glossary of SED symbols and acronyms, may be used to trace the actuation and interaction of the systems used to mitigate the consequences of this event. O; l 15.3-7 Amendment Number 8 tiay 10,1983
)
The timings in Table 15.3.3-1 may be used to determine when, after event initiation, each action occurs. The loss of of fsite power is. assumed to occur due to grid instability. A three second delay between the time of turbine trip and the time of loss of offsite power is conservatively assumed in the analysis, based on the discussion presented in the report submitted via Combustion Engineering Letter 8 LD-82-040, A. E. Scherer to D. G. Eisenhut, dated March 31, 1982. The sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event. If offsite power can be restored,.then-the operator may elect instead to stabilize the plant at a mode other than cold shutdown. All actions required to stabilize the plant and perform the required repairs are not described here. The sequence of events and systems operations described below represents the' way in which the plant was assumed to respond to the event initiator. Many plant responses are possible. However, certain responses are limiting with respect to the acceptance guidelines for this section. Of the limiting I responses, the most likely one to be followed was selected. Table 15.3.3-2 contain:; a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient. ] Table 15.3.3-3 contains a matrix which describes the extent to which safety systems are assumed to function during the transient. The success paths in the sequence of events diagram, Figure 15.3.3-1,. are as O" follows: Reactivity Control: Following seizure of a reactor coolant pump shaft, the core flow rapidly decreases to the value that would occur with only three reactor coolant pumps operating. The rapid reduction in primary coolant flow rate causes an increase in the average coolant temperature in the core, a corresponding reduction in the margin to DNB, and an increase in the primary system pressure. A low DNBR reactor trip is generated by the Core Protection , Calculators. The trip conservatively assumes the largest possible delay time ! for the sensor delay, calculation period, CEDM dead time, and the CEDM coil I delay time (see Chapter 7). The CEAs begin to drop into the core at.1.25 , seconds inserting negative reactivity I Prior to initiating or during manual cooldown the operator adjusts the boron concentration to insure that a proper negative reactivity shutdown margin is achieved. This is accomplished by using the HPSI pumps which also ~eplace r RCS vt.lume shrinuge. The operator may also borate using the charging pumps by ' manually loading them on the diesel generators and then aligning them to the Refueling Water Tank (RWT), the source of borated water. 15.3-8 Amendment Number 8 May 10,1983-
i i I Reactor Heat Removal: ! The reactor heat removal takes place by means of natural circulation in the reactor coolant system following the coastdown of the undamaged reactor l coolant pumps. The steam generator provides primary to secondary heat transfer. The Shutdown Cooling System (SCS) is manually actuated when the RCS temperature and pressure have been reduced to the shutdown cooling entry l conditions of 350 F and 400 psia, respectively. This system provides i sufficient cooling to bring the RCS to cold shutdown. 1 Secondary System Integrity: l l The CEDM bus undervoltage relays, sensing the interruption of power on the CEDM power supply buses, generate a turbine trip signal. This results in closure of the turbine stop valves. The external grid which the plant is feeding is assumed to collapse as a result of turbine / generator trip. The l8 loss of offsite power causes a loss of power to the start-up transformers which prevents the plant electrical loads from being transferred to them from the unit auxiliary transformers. Therefore, the onsite loads will lose power and the plant experiences a simultaneous loss of feedwater flow, condenser inoperability, and a coastdown of all reactor coolant pumps. The pressure in both steam generators increases resulting in the opening of the Main Steam ' Safety Valves (MSSVs), which prevents secondary pressure from exceeding safety limits. The MSSVs close when the secondary pressure drops. Water level in each of the steam generators begins decreasing immediately after the loss of main feedwater flow and an emergency fsedwater actuation signal is generated on low steam ger.erator water level. The Emergency Feedwater Actuation System (EFAS) setpoint is first reached in the steam generator in the unaffected loop. This leads to the start-up of the emergency feedwater pumps. The primary source of the emergency feedwater is the condensate storage tank. The capacity of the storage tank is 300,000 gallons, which is sufficient feedwater ; to maintain the plant at hot standby for 8 hours. The condensate storage tank is provided with an atmospheric vent to maintain atmospheric pressure inside the tank 4The maximum condensate radioactivity concentration is 0.1 uCi/lbm (2.2 x 10- uC1/gm) dose equivalent I-131. After 30 minutes the operator initiates cooldown of the RCS by using the i atmospheric dump valves and the Auxiliary Feedwater System (AFWS). Once the l dump valves are opened, one valve is assumed to remain stuck open. This g results in the eventual generation of a Main Steam Isolation Signal (MSIS) on ' low steam generator pressure. Once the Main Steam Isolation Valves (MSIVs) l are closed, this' prevents further blowdown of the unaffected steam generator. 8 Auxiliary feedwater is automatically terminated to the affected steam generator as a result of a high steam generator differential pressure signal. The affected generator is then allowed to dry out. Cooldown is continued by ; the operator by utilizing the atmospheric dump valves of the unaffected steam j generator together with the Auxiliary Feedwater System. This process " O 15.3 9 Amendment Number 8 May 10,1983
continues until shutdown cooling entry conditions are reached. The AFWS may p t be a separate system or may be one emergency feedwater pump designated as
" auxiliary" and intended for normal startup and shutdown of the plant. The operator may let the ESFAS regulate the.feedwater flow by issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions. See applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater Systems ( IR given in Section 5.1.4 ). .8 Primary Sy tem Integrity: i The pressurizer assists in the control of the RCS pressure and volume changes during the transient by compensating for the initial expansion of the RCS fluid. The combination of the loss of primary system heat sink (turbine stop ;
valves close) with the reduction of reactor coolant flow results in an increase in RCS pressure, j l During cooldown, the operator may control RCS pressure and pressurizer level by turning on the HPSI pumps and throttling the HPSI discharge valves to control the rate of change of RCS pressure. The operator may also control RCS - pressure and pressurizer level via manual actuation and control of the charging pumps and related auxiliary spray. When the RCS pressure has been 8 j reduced to approximately 650 psia, the operator will vent or drain the safety 1 injection tanks to reduce their pressure and will isolate them. Restoration of AC Power: A low voltage on the 4.16 kV safety buses generates an undervoltage signal whien starts the diesel generators. The non-safety buses are automatically d separated from the safety buses and all loads are shed (except 4890 V load centers). After each diesel generator set has attained operating voltage and frequency, its output breaker closes connecting it to i' safety bus. ESF equipment is then loaded in sequence on to this bus. Radioactive Effluent Control: Containment Isolation Actuation Signal (CIAS) isolates various systems to reduce or terminate radioactive releases. CI AS actuates primary, secondary, and containment isolation equipment. Other actions may be initiated by B0P i systems. See Applicant's FSAR for details. Spent Fuel Heat Removal: Spent Fuel Pool (SFP) cooling is terminated on the loss of normal power to the ESF loads. Spent fuel heat removal is continuously' accomplished by utilizing the heat capacity of the SFP water. Pool cooling is restored by manually loading the SFP cooling pumps onto the diesel generators and by aligning the SFP heat exchangers to receive essential cooling water. 15.3-10 Amendment Number 8 May 10,1983
15.3.3.3 Analysis of Effects and Consequences 15.3.3.3.1 Core and Systcm Performance A. Mathematical Model The NSSS response to a single reactor coolant pump rotor seizure with loss of offsite power resulting from turbine trip was simulated using the CESEC-III computer program described in Reference 27 of Section 15.0. The initial DNBR was calculated using the TORC computer code (see Section 15.0.3) which uses t the CE-1 CHF correlation described in Reference 19 of Section 15.0. B. Input and Parameters and Initial Conditions l The ranges of initial conditions considered are given in Section 15.0. Table 15.3.3-4 gives the initial conditions used in this analysis. The rationale for selecting the values of the initial conditions which have a first order effect on the analysis follows. Using the highest core power maximizes the RCS heatup, which is the driving force of the secondary steam release. A high core inlet temperature was chosen to minimize the degree of subcooling in the core. This also results in higher steam generator pressures and, thus, quicker opening of the secondary safety valves, which is more adverse from a radiological standpoint. Tgereactorcoolantflowwaschosentobeits minimum value of 146.1 x 10 lbm/hr. This l'. ' flow was chosen in combination with the other conditions mentioned above sia e this will allow operation with a low radial peaking factor. The use of a low radial peaking factor maximizes the amount of fuel pins which may experience DNB. The primary system pressure was chosen to be compatible with the other initial conditions. The most positive moderator temperature coefficient and the minimum available scram CEA worth tend to maximize the heat flux af ter a reactor trip occurs, increasing the RCS heat-up. The operator initiation of plant cooldown at 30 minutes with l the subsequent failure of an atmospheric dump valve to close maximizes the 8 offsite doses. During this event two sources ot radioactivity contribute to the offsite doses: the initial activity in the steam generator and the activity associated with the assumed one gallon per minute steam generator tube leak. The initial secondary activity is assumed to be at 0.1 uCi/gm dose equivalent I-131. The initial activity assumed to be present in the reactor coolant leaking chrough the steam generator tubes is 4.6 pCi/gm (see Table 15.3-5). C. Rrsults The ciynamic behavior of important NSSS parameters following a single reactor coolatt pump rotor seizure with a loss of offsite pm : - is presented on Figures 35.3.3-2 to 15.3.3-10. Table 15.3.3-1 summarizes the significant results of the event. Refer to Table 15.3.3-1 while reading this section. O 15.3-11 Amendment Number 8 May 10,1983 l
v The single reactor coolant pump rotor seizure event results in a flow coast , down in the affected loop, a consequent reduction in flow through the core, an l increase in the average coolant temperature in the core, a corresponding reduction in the margin to DNB, and an increase in the primary system l pressure. A low DNBR reactor trip is generated by the core protection ! calculators. The reactor trip causes a turbine trip signal to occur. The CEAs begin to drop into the core at 1.25 seconds. At this time the 4 turbine / generator trips. Three seconds later the loss of offsite pcwer occurs. The reaaining RCPs do not begin their normal coastdown until after 8 ! the loss of offsite power. However, there is a slight decrease in RCP flow j during the three seconds immediately after turbine trip and prior to the loss ' of offsite power due to decreasing pump speed caused by frequency degradation (approximately 1 Hertz /second) of the electrical grid. The loss of offsite power also causes a loss of main feedwatar and condenser inoperability. The turbine trip with the SBCS and the condenser unavailable leads to a rapid buildup in secondary system pressure end temperature. This increase in pressure is shown in Figure 15.2.2-8. The opening of the MSSVs limits this pressure increase. The maximum secondary system pressure is 1347 psia which is less than 110% of design pressure. The increasing temperature of the seconda"y system leads to a reduction of the i primary to secondary heat transfer. Concurrently, the failed reactor coolant ! pump snd the three reactor coolant pumps coasting down (Figure 25.3.3-7) , result in RCS flow which further reduces tiie heat transfer capability of the ! RCS. This decrease in heat removal from the kCS leads to an increase in the core coolant temperatures as shown in Figure 15.' 3-5. The core coolant (p temperatures peak shortly after the time of reactor trip. ihe increase in RCS temperature leads to an increase in RCS pressure, as shown in Figure 15.3.3-4, caused by the thermal expansion of the RCS fluid. The RCS pressure reaches a maximum value of 2387 psia at 4.2 seconds which is less than 110% of design pressure. After this time, the RCS pressure decreases rapidly due to the declining core heat flux (see Figure 25.5.5-3), in combination with the opening of the MSSVs. Opening of the MSSVs limits the peak temperature and pressure of the secondary system. The MSSVs cycle until the emergency feedwater begins entering the steam generators. Emergency feedwater begins entering the steam generator in the unaffected loop at 263 seccnds, thus, enhancing the RCS cooldown and the subsequent reduction in pressure. During the first few seconds of the transient, the combination of decreasing flow rate, and increasing RC5 temperatures results in a decrease in the fuel pins' DNBR. The transient minimum DNBR of 0.967 occurs at 1.4 seconds as indicated in Table 15.3.3-1. Figure 15.3.3-9 shows the variation of the minimum DNBR with time. The negative CEA reactivity inserted after reactor trip causes a rapid power and heat flux decrease which causes DNBR to increase again. For this event no more than 0.85 percent of the fuel pins are calculated to experience DNB. All fuel pins which experience DNB are conservatively assumed to fail. p G 15.3-12 Amendment Number 8 May 10,1983
The offsite doses for this event result from steam released through the Main Steam Safety Valves (MSSVs) and Atmospheric Dump Valves (ADVs). At 30 minutes, the operator is assumed to use the ADVs to begin cooldown. At this time, one atmospheric dump valve is assumed to stick open. This leads to the generation of an MSIS and eventual termination of emergency feedwater flow to the affected steam generator. Once the affected steam generator has blown dry, the operator may continue a controlled cooldorn via the atmospheric dump valves of the unaffected steam generator. Additionally, the operator will be 8 feeding auxiliary feedwater flow to the unaffected steam generator. Table 15.3.3-1 shows the integrated steam release from the MSSVs and the ADVs. The radiological release produced by the transient results in a 277 rem two hour thyroid inhalation dose at the exclusion area boundary. The two hour thyroid inhalation dose at the exclusion area boundary is shown in Table 15.3.3-7. 15.3.3.3.2 Radiological Consequences A. Physical Model To evaluate the consequences of the single reactor coolant pump rotor izure with a loss of offsite power event, it is assumed that the condenser is not available for the entirety of the transient. For the first thirty minutes of the event, the cooldown is performed via the main steam safety valves. Aftarwards, an atmosphe.:c dump valve is assumed to stick open once the valve (s) are actuated by the operator in an attempt to initiate a controlled cooldown. After MSIS occurs and the affected generator has blown dry, the 8 , operator may then proceed to initiate a controlled cooldown via the atmospheric dump valves of the unaffected steam generator and the auxiliary feedwater system. B. Assumptions, Parameters, and Calculational Methods The major assumptions, parameters, and calculational methods used to evaluate the radiological consequences of the single reactor coolant pump rotor seizure are presented in Tables 15.3.3-5 and 15.3.3-6. Additional clarification is provided as follows: '
- 1. The Reactor Coolant System (RCS) equilibrium activity is based on long tenn operation at 108% of the ultimate core power level of 3800 MWt (3800 MWt x 1.08 = 4100 MWt) with 1% failed fuel. Refer to Table 11.1.1-2 for the isotopic distribution of RCS activity.
The RCS activity was calculated to determine the total amount of activity transmitted into the secondary system during the duration of thq accident due to a 1 gal / min primary to secondary leak. The primary to secondary leakage of 1 gal / min (technical specification limit) is assumed to continue to the steam generators for the entire event. The3 fluid density is assumed to be constant at its initial value of 45 lbm/ft . The 8 activity in the fuel clad gap is 10% of the iodines and 10% of the noble O 15.3-13 Amendment Number 8 May 10,1983
l TABLE 15.3.3-1 (Sheet 1 of 3) SEQUENCE OF EVENTS FOR THE SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF OFFSITE POWER RESULTING FROM TURBINE TRIP Total Setpoint Integrated Time or Safety Valve (sec.) Event Value Flow (lbm) Success Path 0.0 Seizure of a Si.igle --- --- --- Reactor Coolant Pump 0.76 Low DNBR Trip Signal 1.19 --- Reactivity 8 Generated, projected Control 0.91 Reactor Trip Breakers --- --- Reactivity 10 Open Control 1.25 CEAs Begin to Drop into --- --- Reactivity 8 the Core Control l 1.25 Turbine Trip / Generator --- --- --- V Trip 1.4 Minimum Transient DNBR 0.967 --- --- 4.1 Main Steam Safety Valves 1280 --- Secondary Open, Unaffected Loop, System psia Integrity ; 4.2 Maximum RCS Pressure, 2387 --- --- psia 4.25 Loss of Offsite Power --- --- --- 8 Occurs 4.5 Main Steam Safety Valves 1280 --- Seconda ry Open, Affected Loop, System psia Integrity 6.8 Maximum Steam Generator 1347 3,492 --- Pressure, Unaffected Loop, psia 7.4 Maximum Steam Generator 1340 5,451 --- Pressure, Affected Loop, psia v Amendment No. 10 June 28, 1985
TABLE 15.3.3-1 (Continued) 10 (Sheet 2of3) SEQUENCE OF EVENTS FOR THE SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF OFFSITE POWER RESULTING FROM TURBINE TRIP Total i Setpoint Integrated Time or (sec.) Event Value Safety (Valve Flow lbm) Success Path 217 Steam Generator Water 20 Secondary Level Reaches Emergency System Feedwater Actuation Integrity Signal Analysis Setpoint in the Unaf- 10 fected Loop, percent of wide range 218 Emergency Feedwater 85,679 Secondary Actuation Signal System Generated Integrity 263 Emergency Feedwater 119 91,407 Secondary Begins Entering Steam System Generator, Unaffected Integrity Loop, lbm/sec 696 Steam Generator Water 20 Secondary Level Reaches Emergency System Feedwater Actuation Integrity Signal Analysis Setpoint in the Affected Loop, percent of wide range 697 Emergency Feedwater 115,189 Secondary Actuation Signal System Generated Integrity Emergency Feedwater 119 Begins Entering the Steam Generator, Affected Loop, lbm/sec , 821 Steam Generator Safety 1218 120,398 Secondary Valves Close, Affected System i and Unaffected Loop, Integrity psia j l Amendment No. 10 June 28, 1985
fm TABLE 15.3.3-1(Continued) (Sheet 3 of 3) SEQUENCE OF EVENTS FOR THE SINGLE REACTOR COOLANT PUMP l ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER RESULTING FROM TURBINE TRIP Total Setpoint Integrated Time or (sec.) Event Value Safety (Valve Flow 1bm) Success Path 1 1800 Atmospheric Dump -100.0 120,398 Secondary Valves Opened to System Initiate Plant Integrity Cooldown, F/ hour. One Atmospheric Dump Valve Sticks Open
- 7200 Total Steam Release --- 1,128,293 ---
to Atmosphere, lbm 8 1 O t
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l 1 THIS PAGE INTENTIONALLY BLANK. O1 l l O l
1 .v- q TABLE 15.3.3-2 (sheet 1 of 2). O DISPOSITION OF NORMALLY OPERATING SYSTEMS FOR THE SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER RESULTING FROM TURB.INE TRIP og Q o, "2'. Igh, f SYSTEM A A ff
\
- 1. Main Feedwater Control System /
- 2. Main Feedwater Pump Turbine Control System * /
- 3. Turbine-Generator Control System * /
- 4. Steam Bypass Control System /
- 5. Pressurizer Pressure Control System /
- 6. Pressurizer Level Control System /
Control Element Drive Mechanism Control System / V 7.
/
- 8. Reactor Regulating System
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps / I l
- 11. Chemical and Volume Control system /
- 12. Secondary Chemistry Control System * /
- 13. Condenser Evacuation System * /
- 14. Turbine Gland Sealing System * /
- 15. Nuclear Cooling Water System * /
- 16. Turbine Cooling Water System * /
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities * /
- 19. Circulating Water System * /
- 20. Spent Fuel Pool Cooling and Clean-Up System * /
- 21. Non-ClasslE(Non-ESF)A.C. Power * /
- 22. Class lE (ESF) A.C. Power * /
r
\
- Balance-of-Plant Systems Amendment Number 8 May 10,1983 l l l I
- _ _- _ - _ _--- _ - _ _ _ _ __ _ .. . _ _ . __ =_
TABLE 15.3.3-2 (Cont'd.) (Sheet 2 of 2) DISPOSITION OF NORMALLY OPERATING SYSTEMS FOR THE SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER RESULTING FROM TURBINE TRIP
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- 23. Non-Class lE 0.C. Power * /
- 24. Class lE D.C. Power * /
O i l Note:1 A Failure in this System is the event initiator Amendment Number 8
- Balance-of-Plant Systems May 10,1983 1 1 I i
m TABLE 15.3.3-3 UTILIZATION OF SAFETY SYSTEMS FOR THE SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF OFFSITE POWER RESULTING FROM TURBINE TRIP 7 0 6 9 9p
^p $3 A, 09 AY( Y, .
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- 1. Reactor Protection System / l
- 2. DNBR/LPD Calculator /
l
- 3. Engineered Safety Features Actuation Systems / /
- 4. Supplementary Protection System 1
- 5. Reactor Trip Switch Gear /
- 6. Main Steam Safety Valves * /
- 7. Primary Safety Valves
- 8. Main Steam Isolation System * / /
- 9. Emergency Feedwater System * ./ / i
- 10. Safety Injection System / )
- 11. Shutdown Cooling System ./ 2
- 12. Atmospheric Dump Valve System * / / 2,3
- 13. Containment Isolation System * /
- 14. Containment Spray System *
- 15. Iodine Removal System *
- 16. Containment Combustible Gas Control System *
- 17. Diesel Generators and Support Systems * /
- 18. Component (Essential) Cooling Water System * /
19.. Station Service Water System * / Notes:
- 1. Safety grade back-up to a safety grade system.
- 2. Manually actuated during normal cooldown
- 3. One atmospheric dump valve is assumed to stick open.
Amendment Number 8 May 10,1983
- Balance-of-Plant Systems - l l l
Table 15.3.3-4 ASSUMED INITIAL CONDITIONS FOR THE SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER RESULTING FROM TURBINE TRIP Parameter Value Core Power Level, MWt 3876 Core Inlet Coolant Temperature, F 580 Reactor Coolant System Pressure, psia 2257 8 Steam Generator Pressure, psia 1221 Core Mass Flow,106 lbm/hr 146.1 Maximum Radial Power Peaking Factor 1.40 Maximum Axial Power Peak 1.47 I Core Minimum DNBR 1.48 8 Doppler Coefficient Multiplier 0.85 CEA Worth on Trip, 10- Ao -10.0 (most reactive CEA stuck) i Moderator Temperature Coefficient 0.0 O i 1 Amendment Number 8 May 10,1983 l l 1
( TABLE 15.3.3-5 (Sheet 1 of 3) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER RESULTING FROM TURBINE TRIP Darameters Value A. Data and Assumptions Used to Evaluate the Radioactive Source Term
- a. Power Level, Mwt 4200 I
- b. Burnup 2 year l 1
- c. Percent of Fuel Calculated to 0.85 8 ;
Experience DNB, % ; l
- d. Reactor Coolant Activity 4.6 pCi/gm j Before Event (based on 4100 MWt) Table 11.1.1-2 l l
- e. Secondary System Activity Section 15.0.4 Before Event
- f. Primary System Liquid 525,600 ;
7_ Inventory, lbm
- g. Steam Generator Inventory 1
- Liquid, lbm per steam generator 167,075
- Steam, Ibm per steam generator 14,863 B. Data and Assumptions Used to Estimate Activity Released from the Secondary System
- a. Primary to Secondary Leak Rate, 1.0 (total) gpm
- b. Total Mass Release Through the 1,128,29Y 8
Main Steam Safety Valves and Atmospheric Dump Valves (2 hours)
's Amendment Number 8 May 10,1983
TABLE 15. 3.3-5 (Continued) (Sheet 2 of 3) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER RESULTING FROM TURBINE TRIP Parameters Value J C. Reactor Coolant System Activity After Event, Ci Isotope I-131 1.039 (+5) I-132 1.519 (+5) 1-133 2.097 (+5) I-134 2.265 (+5) , I-135 1.954 (+5) Kr-85M 2.621 (+4) Kr-85 8.315 (+2) Kr-87 4.806 (+4) 8 Kr-88 6.867 (+4) Xe-131M 7.320 (+2) Xe-133 2.105 (+5) Xe-135 3.767 (+4) Xe-138 1.679 (+5) i
- d. Percent of Core Fission Products Refer to Section i Assumed Release to Reactor Coolant 15.3.3.3.2B j
- e. Iodine Partition Coefficient for the 100.0 Unaffected Steam Generator
- f. Iodine Partition Coefficient for the 1.0 Affected Steam Generator
- g. Credit for Radioactive Decay in No Transit to Dose Point
- h. Loss of Offsite Power Yes
- 0. Dispersion Data
- 1. Distance to Exclusion Area Boundary, m 500 Amendment Number 8 O
May 10,1983
C\ V TABLE 15.3.3-5 (contd.) (Sheet 3 of 3) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES l 0F A SINGLE REACTOR COOLANT PUMP ROTOR SElZURE WITH LOSS OF 0FFSITE l POWER RESULTING FROM TURBINE TRIP Parameters Value
- 2. Distance to Low Pcpulation Zone 3000.0 Outer Boundary, m 8
- 3. AtmosghericDispersionFactor, 2.00(-3) sec/m D. Dose Data j 1. Method of Dose Calculation Section 15.0-4
- 2. Dose Conversion Assumptions Section 15.0-4
- 3. Control Room Design Parameters See Applicant's FSAR 1
1 l l I O'- Amendment Number 8 May 10,1983 1
1 TABLE 15.3.3-6 SECONDARY SYSTEM MASS RELEASE TO THE ATMOSPHERE FOR THE SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF OFFSITE POWER RESULTING FROM TURBINE TRIP EVENT Time Integrated Safety Integrated Primary to (sec.) Valve Flow (lbm) Secondary Leakage (gallons) 0.0 0.0 0.00 2.0 0.0 0.03 3.0 0.0 0.05 5.0 480 0.08 10.0 13,884 0.17 20.0 36,677 0.33 40.0 53,354 0.67 60.0 54,812 1.00 80.0 62,536 1.33 100.0 66,282 1.67 150.0 73,248 2.50 200.0 83,047 3.33 300.0 95,560 5.00 500.0 108,710 8.33 821.0* 120.398 13.68 1800.0** 120,398 30.00 o Main steam safety valves close. oo Operator begins cooldown utilizing the atmospheric dump valves. One 8 atmospheric dump valve is assumed to stick open. O Amendment Number 8 May "t 0,1983
1 f- TABLE 15.3.3-7 l ( l
\ RADIOLOGICAL CONSE0VENCES OF A POSTULATED SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITF LOSS OF 0FFSITE POWER RESULTING FROM TURBINE TRIP From Secondary System Result Steam Releases Exclusion Area Boundary Dose (0-2 hours), rem:
Thyroid 277.0 l8 I I l l iO b l l l t ' (/ l Amendment Number 8 May 10,1983 e________-_____-_________-__________-
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~ / corresponds to the largest insertion rate expected from the sequential Q] withdrawal of the CEA groups with 40% overlap at the maximum speed of 30 in./ minute.
C. Results The dynamic behavior of important NSSS parameters following a CEA withdrawal from low power conditions is presented in Figures 15.4.1-1 through 15.4.1-8. The withdrawal of CEA's from low power conditions (1 MWt power) adds reactivity to the reactor core, causing both the core power level and the core heat flux to increase. The power transient causes increasing temperature and pressure transients, which together with a top peaked axial power distribution, produce l- the closest approach to the specified acceptable fuel design limit on DNBR. Since the transient is initiated at low power levels, one of the normal reactor feedback mechani:=, moderator feedback, does not contribute to any appreciable extent to the power excursion transient. At 23.75 seconds into the transient, a variable overpower trip is actuated. The CEA's begin dropping into the core end terminates the transient. The hot channel minimum DNBR reached during the 10 transient is 4.84 at 27.00 seconds. If the maximum rod radial peaking factor occurs in the region of the axial power peak, the peak linear heat generation rate during the transient reaches 13.8 KW/ft. 10 15.4.1.4 Conclusions l The uncontrolled CEA withdrawal from a subcritical or low power condition event O meets general design criteria 25 and 20. These criteria require that tFe d specified acceptable fuel design limits are not exceeded and the protection system action is initiated automatically. The withdrawal of CEA's from low l power conditions meets the following fuel design limits which serve as the acceptance criteria for this event: the transient terminates with a hot channel minimum DNBR greater than or equal to 1.19 and the peak linear heat generation rate during the transient is less than 21 KW/ft. O V 15.4-3 Amendment No. 10 June 28, 1985
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gases accumulated in the fuel at the end of core life, assuming O continuous fuel power operation. All of the activity in the fuel gap for fuel rods that are calculated to experience DNB is assumed to be V uniformly mixed with the reactor coolant. This assumption is consistent with Regulatory Guide 1.77.
- 2. The steam generator equilibrium activity is assumed to be 0.1 pCi/gm dose l8 equivalent Iodine-131 (1-131) prior to the accident. This is the technical specification limit for steam generator activity.
- 3. Offsite power is not available. At 1800 seconds the operator attempts to take control of the plant using the atmospheric dump valves. One atmospheric dump valve is assumed to stick open at this time for the remainder of the transient
- 8
- 4. Credit is assumed for emergency feedwater flow. For the fluid leaked from primary to secondary, iodine is assumed to released to the atmosphere with a partition coefficient of 1.0.
- 5. No credit for radioactive decay in transit to dose point is assumed.
- 6. The atmospheric dispersion factors used in this analysis, which are based on meteorological conditions assumed present during the course of the accident, are calculated according to the model described in subsection 2.3.4. The 5% level X/Q presented in Table 2.3-1 was used.
p 7. The mathematical model used to analyze the activity released during the 3 course of the accident is described in Section 15.0. '
- 8. Table 15.3.3-6 presents the integrated mass release from the secondary 8 safety valves and the total primary to secondary leakage. j
- 9. Calculated secondary mass releases are presented in Table 15.3.3-5. l8 C. Identification of Uncertainties and Conservatism in the Evaluation of the Results The uncertainties and conservatism in the assumptions used to evaluate the radiological consequences of the single reactor coolant pump rotor seizure with a loss of offsite power are as follows:
- 1. The RCS equilibrium activity is based on 1% failed fuel, which is greater by a factor of two to eight than that normally observed in past PWR operation.
- 2. The steam generator equilibrium activity for the affected steam generator .
is assumed to be equal to the technical specification limit (0.1 uCi/gm dose equivalent I-131). This specific activity is greater by a factor of approximately 1300 than the normal expected steam generator activity (refer to Table 11.1.8-1). O 15.3-14 Amendment Number 8 May 10,1983 I
- 3. The primary to secondary leakage of 1 gal / min (technical specification '
limit) is conservative because operation with a 1 gal / min primary to secondar gal / day)y leak is not expected (the expected leakage rate is equal to 20
- 4. The meteorological conditions assumed to be present at the site during the course of the accident are based on 5% level X/Qs. Meteorological conditions will be less severe 95% of the time. This results in the poorest values of atmospheric dispersion calculated for the EAB or LPZ outer boundary. Furthermore, no credit has been taken for the transit time required for activity to travel from the point of release to the EAB or LPZ outer boundary.
- 5. The assumption of no operator action for 1800 seconds (30 minutes) is a conservative assumption.
15.3.3.4 Conclusions The maximum RCS and steam generator pressures due to a single reactor coolant pump rotor seizure in combination with loss of offsite power following i generator trip event remain less than 110% of their design values. Only a ! small fraction of the fuel pins experience DNB and are conservatively assumed < to fail. The two hour thyroid dose is within 10CFR100 guidelines. l8 i O! O 15.3-15 Amendment Number 8 May 10,1983
1 1
15.3.4 REACTOR COOLANT PUMP SHAFT BREAK WITH LOSS OF 0FFSITE POWER ID 15.3.4.1 Identification of Event and Causes A single reactor coolant pump sheared shaft could be caused by mechanical failure of the pump shaft. This is assumed to result from a manufacturing l defect in the shaft. Loss of offsite power following turbine / generator trip j may be caused by a complete loss of the external electrical grid triggered by j the turbine / generator trip.
15.3.4.2 Sequence of Events and Systems Operation I The sequence of events and systems operations is similar to that for the l reactor coolant pump rotor seizure event, Section 15.3.3. The difference is l that for the shaft break event, the reactor is tripped on differential j pressure across either steam generator, whereas, for the pump rotor seizure !
event, the reactor is tripped by the CPC on a low projected DNBR condition. j The flow coastdown for a Rotor Seizure (RS) event is faster than the coastdown I
for a Shaf t Break (SB) event. For a shaft break, the rotor is still capable of rotating, thereby offering less resistance to flow during the rapid flow decrease. This results in a less severe coast down for the shaft break event than for the rotor seizure event. The SB trip time is 1.2 seconds; the RS i trip time is 0.91 seconds. Despite the later trip time, the slower SB I coastdown results in a higher minimum DNBR and less fuel failure for SB than for RS.
l For both RS and SB, three seconds after turbine trip a Loss of Offsite Power (LOP) was assumed. Both RS and SB reach the same 3-pump asymptotic flow 8 before their respective LOPS and do not result in decreasing DNBR after LOP.
, The RS plus LOP minimum DNBR is lower and fuel failure higher than those for SB plus LOP.
15.3.4.3 Analysis of Effects and Consequences 15.3.4.3.1 Core and System Performance The analysis of effects and consequences for thi; event is similar to that for the reactor coolant pump rotor seizure event, Section 15.3.3. The SB coastdown is slower and trip is later than those of the rotor seizure event.
The SB plus LOP event produces a higher minimum DNBR and le (MAElmE ai a* VALyt P,
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15.4.2.1 Identification of Event and Causes 1 b I O An uncontrolled sequential withdrawal of CEA's is assumed to occur as a result of a single failure in either the Control Element Drive Mechanism Control System (CEDMCS) or the Reactor Regulating System (RRS). 15.4.2.2 Sequence of Events and Systems Operation Table 15.4.2-1 presents a chronological sequence of events ich occur during a sequential CEA group withdrawal transient from the time the 'A's start to withdraw until the operator initiates cooldown. The corresponding success paths are given in the Sequence of Events diagram, Figure 15.4.21. Figure 15.0-1, which contains a glossary of SEA symbo'Is and acronyms, may be used with Figure 15.4.2-1 to trace the actuation and interaction of the systems utilized to mitigate the consequences of this event. Table 15.4.2-2 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient. The success paths i.1 the Sequence of Events diagram in Figure 15.4.2-1 are as follows: Reactivity Control: 1 As the CEA's are withdrawn, the core power level and thus, the RCS pressure increase. A low DNRR trip is generated, and the CEA's drop into the core. . Once the plant parameters have been stabilized, the operator adjusts the boron I concentration to insure that a proper negative reactivity shutdcwn margin is V achieved prior to cooldown. This is accomplished using the Chemical Volume Control System (CVCS). Reactor Heat Removal: Following the cooldown phase, the shutdown cooling system (SCS) is manually actuated when the RCS temperature and pressure have been reduced to 350 F and 400 psia, respectively. This system provides sufficient cooling flow to cool the RCS to cold shutdown. Primary System Integrity: t During the pressure transient in the primary system, the pressurizer bubble l acts to dampen the RCS pressure increase. The RCS pressure remains below the pressurizer pressure safety valve setpoint and remains less than 110% of design pressure. During the cooldown phase, the pressurizer pressure and level l control systems may be used to regulate pressure and level in the primary system. When the RCS pressure has been reduced to approximately 650 psia, the operator will vent or drain the SIT's to reduce their pressure and will then isolate them. As the cooldown proceeds, the operator will reduce the safety injection actuation setpoint to prevent the inadvertent generation of an SIAS. Secondary System Integrity: A Following the generation of a turbine trip on reactor trip, the Main Feedwater (j Control System (FWCS) enters the reactor trip override mode and reduces feedwater flow to 5% of nominal, full power flow. Since the Steam Bypass l 15.4-4 Amendment No. 7 March 31, 1982
Control System (SBCS) is assumed to be in manual mode with all bypass valves closed, the Main Steam Safety Valves (MSSV's) open to lim' t secondary system pressure and remove heat stored in the core and the RCS. Following the closure of the MSSV's, the FWCS is prevented from over-feeding the steam generators by the High-Level Override (HLO), which terminates feedwater flow until the steam j generator level decreases to its nominal range. Once the plant parameters are stabilized, the operator initiates cooldown utilizing main feedwater and the SBCS. As the cooldown proceeds, the operator reduces the main steam isolation actuation setpoint to prevent the inadvertent generation of an MSIS. When i steam pressure decreases to a point where the main feedwater pumps can no I longer be used, the operator secures the main pumps. Cooldown is continued by utilizing one feedwater pump designated as " auxiliary" and intended for normal startup and shutdown of the plant in conjunction with SBCS. He may also let the ESFAS regulate the feedwater flow by issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions. See Applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater Systems. l Table 15.4.2-3 contains a matrix which summarizes the utilization of the safety systems as they appear in this transient analysis. 15.4.2.3 Analysis of Effects and Consequences A. Mathematical Mode i The Nuclear Steam Supply System (NSSS) response to a CEA group withdrawal at power was simulated using the CESEC-II computer program described in Section 15.0.3. B. Input Parameters and Initial Conditions . Table 15.4.2-4 lists the assumptions and initial conditions used for this analysis in addition to those discussed in Section 15.0. These initial conditions (i.e. , radial power peak, core flow, and inlet temperature) were chosen such that a reactor trip on low DNBR is actuated prior to or at the same time as trips on high pressurizer pressure or variable overpower would be initiated. The selection of these parameters in this manner minimizes the hot channel minimum DNBR. The initial conditions and NSSS characteristics used in this analysis yield the minimum DNBR for any CEA group withdrawal incident. Parametric studies were performed on core inlet temperature, pressurizer pressure, and core flow. The j studies indicated that minimum DNBR during the CEA withdrawal is most sensitive to initial core inlet temperture. Thus, the maximum allowable core inlet temperature was assumed. The RCS pressure was chosen so that the reactor was operating at a Power Operating Limit (PDL) and was low enough to avoid a high ! pressurizer pressure trip. Thus, the conditions chosen yield the minimum DNBR for a CEA withdrawal at power,. The power level from which the withdrawal is initiated was assumed to be 102% of rated power. Minimum DNBR during the CEA withdrawal is more sensitive to high initial power levels. The initial core averace axial power distribution for this analysis is a shape characterized by an axial shape index equal to 1
-0.13. This distribution is assumed because it maximizes the shift of power to l the top of the core during the transient, and, thus, minimizes the DNBR. l l
l Amendment No. 7 15.4-5 March 31, 1982 '
Other input' parameters which are important to this analysis are the Moderator i e Temperature Coefficient (MTC) and Feel Temperature Coefficient (FTC) of 1 \ reactivity. A moderator temperature coefficient was assumed in this analysis I' which corresponds to beginning-of-life core conditions. This MTC has the smallest impact on retarding the rate of change of power, coolant temperature, and DNBR. A fuel temperature coefficient corresponding to beginning-of-life - conditions was used in the analysis, since this FTC causes the least amount of negative reactivity change for_ mitigating the transient increases in core power, heat flux, and the reactor coolant temperatures. The uncertainty on the fuel temperature coefficients used in the analyses is listed in Table 15.4.2-4. The regulating CEA position from which the CEA withdrawal is initiated corresponds to 25% insertion of the first regulating bank. This particular insertion was selected based on the calculated CEA worth and associated uncertainties to produce the worst transient. A corresponding maximum differential worth of 0.01% Ap per inch of rod motion was conservatively assumedinthepresentanalgis. This corresponds to a maximum reactivity withdrawal rate of 0.5 x 10 Ap per second based on the maximum CEA withdrawal speed of 30 inches per minute, including all uncertainties. All the control systems listed in Table 15.4.2-2, except the steam bypass control system, were assumed to be in the automatic mode since these systems have no impact on the minimum DNBR obtained during the transient. The steam bypass control system is assumed to be in manual mode because this minimizes ! DNBR during the transient. ) C. Results The dynamic behavier of important NSSS parameters following an uncontrolled CEA group withdrawal are presented in Figures 15.4.2-2 to 15.4.2-12. l 10 The withdrawal of CEA's causes a positive reactivity change, resulting in an increase in the core power and heat flux. As a consequence, the reactor coolant temperature and pressurizer pressure increase. At 9.51 seconds after 10 , initiation of the transient, a reactor trip on low DNBR is actuated. At 9.66 seconds the trip breakers are opened. The CEA's begin dropping into the core and terminates the transient. The minimum DNBR reached during the transient 10 is 1.19 at 11.00 seconds. If the maximum rod radial peaking factor occurs in the region of the axial power peak, the peak linear generation rate during the transient reaches 16.7 KW/ft. Table 15.4.2-1 lists the sequence of events for , the limiting DNBR case. ; 15.4.2.4 Conclusions The uncontrolled CEA withdrawal event meets general design criteria 25 and 20. j These criteria require that the specif46 acceptable fuel design limits are not exceeded and the protection system action is initiated automatically. The withdrawal of CEA's from full power conditions meets meets the following fuel design limits which serve as the acceptance criteria for this event: the transient terminates with a hot channel minimum DNBR greater than or eoual to 1.19 and the peak linear heat generation rate during the transient is less than 21 KW/ft. 15.4-6 Amendment No.10 June 28,1985
V O ,
)
l THIS PAGE INTENTIONALLY BLANK, O w ; I i O-
1 TABLE 15.4.2-1 O l SE0VENCE OF EVENTS FOR THE SEQUENTIAL CEA WITHDRAWAL EVENT SETP0 INT SUCCESS TIME (sec) Event OR VALUE PATH 0.0 Withdrawal of CEA's - -- Reactivity l Initiating Event Control 9.51 Low DNBR Trip Signal 1.19 Reactivity Generated, projected Control DNBR 10 9.66 Trip Breakers Open -- Reactivity Control l l 10.1 Maximum Core Power, 108.2
% of Design Power 11.0 Minimum DNBR 1.19 l 11.4 Maximum Core Average 105.6 '
Heat Flux, % of Full
) Power Heat Flux 12.3 Maximum Pressurizer 2363 Pressure, psia \
1 % Amendment No. 10 June 28, 1985 m
TABLE 15.4.2-2 (Sheet 1 of 2) DISPOSIT10ft 0F l;0RtALLY CPERATIflG SYSTEMS FOR Tl!E SEQUEf1T!AL CEA WITilDRAWAL AT FULL POWER Yb;13o Y d G% G ,d. TC f g b
'A s,'b x0fb, o OAOo 9, %9 b>g+
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"Q p
- l. Main Feedwater Control System / ,
- 2. Main Feedwater Pump Turbine Control System * /
- 3. Turbine-Generator Control System * /
- 4. Steam Bypass Control System /
- 5. Pressurizer Pressure Control System /
- 6. Pressurizer Level Control System /
- 7. Control Element Drive Mechanism Control System / 1
- 8. Reactor Regulating System / 1
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps /
- 11. Chemical and Volume Control System /
- 12. Secondary Chemistry Control System * /
- 13. Condenser Evacuation System * /
- 14. Turbine Gland Sealing System * /
- 15. Nuclear Cooling Water System * /
- 16. Turbine Cooling Water System * /
l 17. Plant Cooling Water System * / l 18. Condensate Storage Facilities * /
- 19. Circulating Water System * /
- 20. Spent Fuel Pool Cooling and Clean-Up System * /
- 21. Non-Class 1E (Non-ESF) A.C. Power * / l
- 22. Class 1E (ESF) A.C. Power * /
- Balance-of-Plant Systems
,i Amendment No. 7 March 31, 1982 l
l TABLE 15.4.2-2 (CONTIr1UEDl.. (Sheet' 2 of 2) ] DISPOSITION OF fl0RMALLY OPERATIflG SYSTEMS FOR THE SEQUEtlTIAL CEA WITHDRAWAL l AT FULL POWER
@o1 8. k #
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- 23. Non-Class lE D.C. Power * /
- 24. Class lE D.C. Power * /
l Notes:
- 1. This system may be cause of initiating event.
I I I j
*Dalance-of-Plant Systems l
- _ _ . _ - ___ j Amendment No. / !
March 31, 1982 l
TABLE 15.4.2-3 UTILI.Z. AT. ION OF St.FETY SYSTEMS. FOR THE SEQUENTIAL CEA WITHDRAWAL i AT FULL POWER l I
#f fc 'N2 b,, f
\9; ^
R& J t Q
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- 1. Reactor Protection System /
- 2. DNBR/LPD Calculator
- 3. Engineered Safety Features Actuation Systems /
- 4. Supplementary Protection System 1
, 5. Reactor Trip Switch Gear /
] 6. Main Steam Safety Valves * /
- 7. Primary Safety Valves /
l
- 8. Main Steam Isolation System * /
- 9. Emergency Feedwater System * /
- 10. Safety Injection System
- 11. Shutdown Cooling System / l
- 12. Atmospheric Dump Valve System * / !
- 13. Containment Isolation System *
- 14. Containment Spray System
- j 15. Iodine Removal System *
- 16. Containment Combustible Gas Control System
- l17. Diesel Generators and Support Systems
- j 18. Component (Essential) Coeling Water System * /
- 19. Station Service Water System * / .
Notes:
- 1. Safety backup for safety system.
1 O
- Balance-of-Plant Systems ,
Amendment No. 7 March 31,1982
n l l l
. TABLE 15.4.2-4
( ASSUMPTIONS AND IHITIAL CONDITIONS FOR THE SEQUENTIAL CEA WITHDRAWAL ARKEYSIS PARAMETER Value Core Power Level, MWt 3876 Core Inlet Temperature, OF 580 6 Core Mass Flow Rate, 10 lbm/hr 182.6 Reactor Coolant System Pressurizer, psia 2350 One Pin Radial Peaking Factor, with Uncertainty 1.77 Initial Core Minimum DNBR 1.52 Steam ~ Generator Pressure, psia 1178 Doppler Coefficient Mult' plier 0.85 CEA Worth at Trip,10-2 Ap -10.0 0.5 Reactivity Insertion Rate,10-4Ap/sec CEA Withdrawal Spped, inches / min 30.0
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s l Amendment No. 7 March 31, 1982 l
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I n 3000 l S-22 2500 - 5 a ci ! 12 5 2000 - E SG A 0 I s h1500 - SG B f e E i O E i 1000 - - E W m a i5 ' o s 500 - - 1 t 0 0 5 10 15 20 25 TIME, SECONDS i Amendment No. 7 March 31,1982 l C-E SEQUENTIAL CEA WITHDRAWAL AT POWER Figure EDEPJs / f[ TOTAL SEAM FLOW vs TIME 15.4 . 2 - 1 2 1
15.4.3 SINGLE FULL LENGTH CONTROL ELEMENT ASSEMBLY DROP 15.4.3.1 Identification of Event and Causes A single full length CEA drop results from an interruption in the electrical power to the Control Element Drive Mechanism (CEDM) holding coil of a single full length CEA. . This interruption can be caused by a holding coil failure or loss of power to the holding coil. The limiting case is the CEA drop which does not cause a trip to occur but results in an approach to the DNBR criterion of 1.19. 15.4.3.2 Sequence of Events and Systems Operation The transient is initiated by the release and subsequent drop of a full lenoth control element assembly. The resultant increase in the hot pin radial peaking factor coupled with a return to 102% of full power (following a temporary power depression) results in a minimum DNBR of 1.19 at approximately 36 seconds. Table 15.4.3-1 presents a chronological list of events that occur during the Ongle full length CEA drop transient, from. initiation to the attainment of steady state conditions. Table 15.4.3-2 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient analysis. No systems other than the normally operating systems are utilized to mitigate the consequences of this event. 15.4.3.3 Analysis of Effects and Consequences A. Mathematical Model The Nuclear Steam Supply (NSSS) response to the single full length CEA drop was simulated using the CESEC-Il computer program described in Section 15.0.3. The time-dependent thermal margin on DNBR in the reactor core was calculated using the TORC computer program which uses the CE-1 critical heat flux correlation described in Chapter 4. B. Input Parameters and Initial Ccnditions Table 15.4.3-3 lists the assumptions and initial. conditions used for this analysis in addition to those discussed in Section 15.0. The sets of initial conditions (power, pressure, temperature, coolant flow rate, radial peaking factors, and axial power distribution) were chosen such that a minimum initial thermal margin was obtained. This initial thermal margin corresponds to a DNBR of 1.37. This was done so that the transient minimum DNBR could be determined as a function of the dropped rod radial reaking factor increase. This information was then used to select the maximum change in radial peaking factor which, in conjunction with the extreme initial conditions on other parameters, causes the DNBR to reach 1.19 without a reactor trip. For the initial conditions selected, if the radial peak increases are large enough to cause the Core Protection Calcualtors (CPC) to initiate a s reactor trip, there is no appreciable decrease in thermal margin. Under the latter circumstances, both the local and core average power decrease; Amendment No. 7 15.4-7 March 31, 1982
therefore, none of the criteria are approached. For transients initiated at other sets of initial conditions, a trip may or may not be required depending on whether the initial thermal margin is as low for the combination of conditions used in this analysis. The negative reactivity inserted by a dropped CEA causes the power to initially j decrease everywhere in the core. With no reactor trio, the coolant inlet t temperature and pressure will gradually decrease. Concurrently, the radial peaking factor will increase ta an asystotic post drap value. The decreasing coolant temperature combined with the negai.1ve doppler and moderator temperature coefficients causes a positive reactivity insertion which brings { i the core back to 102% power at the time of minimum DNBR.
]
To compute the minimum DNBR, the heat flux is based on the 102% power conditions and the asymptotic radial peaking factor existing at that time. However, for conservatism, it is assumed that the coolant inlet temperature and pressure are at their initial pre-transient values. This is conservative because the net effect of decreasing coolant temperature and pressure is to offset the degradation in DNBR caused by the higher post drop peaking factors. Figures 15.4.3-3 and 15.4.3-5 reflect the conservatism in that the changes in ! hot channel heat flux and DNBR shown are based only on the change in radial l peak. The Reactor Regulating System is assumed to be in the automatic mode. For this I analysis, the choice of mode is inconsequential because there would be no I regulating bank motion if the system were in manual mode; and in the automatic mode the CEA Withdrawal Prohibit (CWP), actuated on the DNBR pretrip signal, prevents the motion of any regulating bank following the drop of a single full length CEA which causes the CPC calculated DNBR to approach 1.19. - C. Results
]
The c)'namic behavior of important NSSS parameters following the drop of a single full length CEA is presented in Figures 15.4.3-1 to 15.4.3-12. The full i length CEA drop is characterized by a prompt decrease in core average and local l power iollowed by an increasing distortion in radial power distribution. As the dropped CEA is detected by the CEA calculators, a conservative power distribution penalty factor is supplied as input to the CPC along with other measured process parameters. The sequence of events during the transient is enough to cause a reactor trip, then the reactivity feedbacks (due to the decreasing core inlet and average temperatures) cause the power (which was initially depressed immediately following the drop) to rise. The higher radial peaking factor, coupled with the core average power returning to its initial value, causes a decrease in DNBR. The results of parametric analyses of the change in radial peak (distortion) indicate that an increase in the integrated radial peak of 6%, in conjuction with the assumed values of other initial parameters, can be tolerated without a reactor trip. Therefore, if the plant is operating at the assumed extreme initial conditions., the drop of a rod which causes an increase in the asymptotic radial peaking factor of greater than 6% would cause a reactor trip to occur. For transients initiated at other sets of initial conditions a trip may or may not be required depending on whether the initial thermal margin is as low as for the combination of conditions used in this analysis. Amendment No. 7 15.4-8 liarch 31, 1982
For the case in which a trip does not occur a minimum DNBR of 1.19 is reached at 36 seconds. The pressure drop beyond this point is arrested by the return to full power and a new steady state is reached at about 50 seconds. The peak [-s s\ . N_/ centerline temperature obtained during the transient is less than 4000 0F. If the maximum rod radial peaking factor occurs in the region of the axial power peak, the peak linear heat generation rate during the transient reaches 12.5 KW/ft. 15.4.3.4 Conclusions The single full length CEA drop event meets general design criteria 25 and 20. ) These criteria require that the specified acceptable fuel design limits are not ) exceeded and the protection system action is initiated automatically. The drop of a CEA meets the following fuel design limits which serve as the acceptance criteria for this event: the transient terminates with a hot channel minimum DNBR greater than or equal to 1.19 and the peak linear heat generation rate during the transient is less than 21 KW/f t.
)
~
i I O) L Amendment No. 7 15.4-9 March 31, 1982
0 l l THIS PAGE INTENTIONALLY BLANK, O 1 0
TABLE 15.4.3-1 SE0VENCE OF EVENTS FOR THE SINGLE FULL LENGTH e CLA DROP LVENT Time Setpoint Success (Sec) Event or Value Path 0.0 A Single Full Length -- -- CEA Begins to Drop 22.0 Minimum Pressurizer 2048 -- Pressure, psia 36.0 Minimum DNBR 1.19 -- 380.0 Maximum Pressurizer ~2077 -- 1 O e i O Amendment No. 7 March 31, 1982
tai!LE 15.4.3-2 (Sheet 1 of 2) DISPOSITION OF fl0RMALLY OPERATING SYSTEMS FOR THE SIf1GLE FULt. LEtlGTH CEA DROP
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-7 's, 1- Q, SYSTEM
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- 2 .. .--.---
- 1. Main Feedwater Control System /
- 2. Main Feedwater Pump Turbine Control System * /
- 3. Turbine-Generator Control System * / i
- 4. Steam Bypass Control System /
- 6. Pressurizer Pressure Control System /
- 6. Pressurizer Level Control System /
- 7. Control Element Drive Mechanism Control System / 1
- 8. Reactor Regulating System /
- 9. Core Operating Limit Supervisory System /
l
- 10. Reactor Coolant Pumps /
- 11. Chemical and Volume Control System /
- 12. Secondary Chemistry Control System * /
- 13. Condenser Evacuation Sy: tem * /
- 14. Turbine Gland Sealing System * /
- 15. Nuclear Cooling Water System * /
- 16. Turbine Cooling Water System * /
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities * /
- 19. Circulating Water System * /
- 20. Spent Fuel Pool Cooling and Clean-Up System * /
- 21. Non-Class lE (Non-ESF) A.C. Power * /
- 22. Class lE (ESF) A.C. Power * /
- Balance-of-Plant Systems -
~~ ~
Amendment No. / March 31, 1982
v _ TABLE 15.4.3-2 (CONTIllVED)_ (Sheet 2 of 2) DISPOSITION OF f!0RMALLY OPERATING SYSTEMS FOR THE SIfiGLE FULL LEf!GTH )
's) CEA DROP O
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- 23. Non-Class 1E D.C. Power * /!
l 24. Class 1E D.C. Power * / NOTES:
- 1. A single-failure within this system may be responsible for the initiation of this event.
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- Balance-of-Plant Systems
~
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- TABLE 15.4.3-3 ASSUMPTIONS AND INITIAL CONDITIONS F0P, THE SINGLL FULL LENGTH LONTROL ELEMENT ASSEMBLY DROP Parameter Value Core Power Level, Mwt 3876 Core Inlet Coolant Temperature, OF 580 Core Mass Flowrate, 10 61bm/hr 145.2 l Pressurizer Pressure, psia 2067 Steam Generator Pressure, psia 1199 Axial Shape Index -0.3 Core Minimum DNBR 1.37 Integrated Radial Heat Flux Peak 1.34 Integrated Radial Peaking Factor 1.43 at Time of Minimum DNBR Dropped CEA Reactivity Worth,10-2 -0.06 Time for Dropped CEA to be Fully 2.0 Inserted, sec Doppler Coefficient Multiplier 1.15 I
O Amendment No. 7 March 31, 1982
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March 31,1982 C-E SINGLE FULL LENGTH CEA DROP Figure g / HOT CHANNEL HEAT FLUX vs TIME 15A,3_4
l I 1 0 2090 , , , , 2080 5 E i g 2070 - - t0 , if 5 y2060 - - o. 2050 - - l l 2040 0 80 160 240 320 400 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E SINGLE FULL LENGTH CEA DROP rigor, g PRESSURIZER PRESSURE vs TIME 15.4 . 3 - 5
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( OUTET7 630 - - 8 O vi 620 - - U R g h 610 k - H:! M s 8 o 600 - - W y590 - o 580 x INET y - 570 ' ' ' ' 0 80 160 240 320 400 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E i SINGE FULL ENGTH CEA DROP Figure g g gg f CORE AVERAGE COOLANT TEMPERATURES vs TIME 15.4. 3 - 7
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15.4.4 STARTUP 0F AN INACTIVE REACTOR COOLANT PUMP [ 15.4.4.1 Ider tification o' Event and Causes The startup of an inactive reactor coolant pump (SIRCP) is presented here with respect to RCS pressure and fuel performance criteria. The event was evaluated during modes 3 through 6 since plant operation with less than all four reactor coolant pumps is permitted only during those modes. The cases considered were no more than one reactor coolant pump operation or two reactor coolant pumps operating in one loop (the other loop idle; to maximize the pressure increase. 15.4.4.2 Sequence of Events and Systems Operation STRCP causes a sudden surge of relatively cold water to enter the core which may cause a core power and RCS pressure increase. For modes 3 and 4 the primary safety valves valves, main steam safety valves, and the Reactor Protection System are designed to maintain the RCS below 110% of design l pressure. During modes 5 and 6 when the shutdown cooling system is aligned overpressure protection is provided by the shutdown cooling system relief valves. The valves set pressure and is listed in Section 5.2.2 and 5.4.7. 15.4.4.3 Analysis of Effects and Consequences With no more than one reactor coolant pump operating or two reactor coolant pumps operating in one loop (the other loop idle), the SIRCP may lead to an increase in RCS pressure. However, as stated in Section 5.2.2 and Appendix 5A, the overpressure protection for C-E's System 80 pressurized water reactor, f steam generators, and reactor coolant system is in accordance with the i requirements set fourth in ASME Boiler and Pressure Vessel Code, Section III. 3 For modes 3 and 4 the primary safety valves, main steam safety valves, and Reactor Protection System are designed to maintain the RCS below 110% of design pressure during the worst case pressure transients. During modes 5 and 6 when the shutdown cooling system is aligned, overpressure protection is provided by the shutdown cooling system relief valves. 15.4.4.4 Conclusion Based on the design of the valves described in Subsection 15.4.4.3 the maximum pressure within the RCS occurring during a SIRCP will not exceed 110% design value. For modes 3 and 4, the heat imbalance due to the SIRCP is less limiting than that caused by the CEA withdrawal event. In modes 5 and 6, the capacity of the shutdown cooling relief valver prevents the RCS pressure following a SIRCP from exceeding the pressure / temperature limits for these modes. Regarding the approach to fuel design limits for the SIRCP, the minimum DNBR in the hot channel will increase as the transient progresses; therefore no fuel damage is expected. Amendment No. 7 March 31,1982 15.4-10
v 15.4.5 FLOW CONTROLLER MALFUNCTION CAUSING AN INCREASE IN BWR CORE FLOW RATE l This event is not applicable to pressurized Water Reactors and therefore is not incuded in this F >A. 15.4.6 IN&-X ENT DEB 0 RATION 15.4.6.1 Identification of Event and Causes The Inadvertent Deboration (ID) event is presented here with respect to time available for operator corrective action prior to the loss of minimum required shutdown margin. Fuel integrity is not challenged by this event. l I The ID event may be caused by improper operator action or by a failure in the ) boric acid makeup flow path which reduces the flow of borated water to the j charging pump suction. Either cause can produce a boron concentration of the ] charging flow which is below the concentration of the reactor coolant. Analysis of the ID event initiated during each of the six operational modes defined in the Technical Specifications was performed. These analyses show that Mode 5 (cold shutdown) results in the least time available for detection and termination of the event. This is because the shutdown margin requirement which will be specified by the Technical Specifications is smallest in mode 5. Since boron dilution is conducted under strict procedural controls which specify limits on the rate the magnitude of any required change in boron concentration, the probability of a sustained and erroneous dilution due to operator error is very low. The indications and/or alarms available to alert the operators that a boron dilution event is occurring in each of the operational modes are outlined below.
- 1. The following control room indications and corresponding pre-trip alarms are available for MODES 1 and 2: a high power or, for some set of conditions, a high pressurizer pressure trip in MODE 1 or a high logarithmic power level trip in MODE 2. Furthermore, a high Tgyg alarm i may also occur prior to trip.
- 2. In MODES 3 and 4 with CEAs withdrawn, the high logarithmic power level trip and pre-trip alarm and high neutron flux alarm will provide an j indication to alert the operator of an inadvertent boron dilution.
- 3. In MODES 3, 4, and 5 with CEAs fully inserted and in MODE 6, a high neutron flux alarm on the startup flux channels will provide indication of any boron dilution event.
- 4. In MODE 5 with the RCS partially drained for system maintenance, the s startup flux channel alarm will provide indication of any boron dilution event. In this plant condition, administrative controls would allow operation of only one charging pump at a maximum rate of 44 ppm. Plant operating procedure will require that the power to the other two charging pumps be removed and their breakers locked out. This drained down case is less limiting than the MODE 5 event presented below. '
Amendment No. 7 1 5.4-11 March 31, 1982
m The operational procedure guidelines, in addition to these indications and/or alarms, will assure detection and termination of the boron dilution event p before the shutdown margin is loss. 15.4.6.2 Sequence of Events and Systems Operation Refer to Figure 15.4.6.1 for the Sequence of Events Diagram. The core is initially subcritical with shutdown margin at the minimum value consistent with the technical specification limit for cold shutdown. An inadvertent deboration occurs which causes unborated water to be pumped into the RCS. The resulting decreases in RCS boron concentration adds positive reactivity to the core. Assuming dilution continues at the maximum possible rate, 95 minutes would elapse before the core becomes critical. The success path in the sequence of events diagram, Figures 15.4.6-1 is as follows: Reactivity Control: The operator is alerted to a decrease in the reactor coolant system (RCS) boron concentration either through a high neutron flux alarm on the startup flux channel, sampling, boronmeter indications, or boric acid flow rate. He turns off the charging pump (s) and closes the letdown control valves in order to halt further dilution. Next, he increates the RCS boron concentration by implementing the emergency boration procedure for achieving cold shutdown boron concentration. , 15.4.6.3 Analysis of Effects anr. Consequences
~
A. Mathematical Model i Assuming complete mixing of boron in the RCS, the rate of change of boron i concentration during dilution is described by the following equation. l M dC = -WC iTE Where: M = RCS mass 1 C = RCS boron concentration W = Charging mass flow rate of unborated water dC/dt is maximized by maximizing W and minimizing M. Assuming: ~ W = Constant, equal to the maximum possible value, and choosing: A M = Constant, equal to the minimum value occurring durin; the boron dilution incident. 15.4-12 Amendment No. 7 March 31,1982
the solution of Equation (1) can be written C(t) = C(o)e-t/T (2) l Where: T= M/W = Boron dilution time constant c(o) = Initial boron concentration The time T required to dilute to critically is given by T =1In C(o) (3) Ecrit Where: Ccrit = Critical boron concentration B. Input Parameters and Initial Conditions It is assumed that the inadvertent deboration proceeds at the maximum possible ra te. For this to occur, all charging pumps must be on, the reactor makeup j water tank must be aligned with the charging pump suction, a reactor makeup water pump must be on, letdown flow must be diverted from the volume control tank, and a failure in the boric acid makeup water flow path (e.g., flow control valve, CH-210Y f ailing in the closed position) must terminate borated water flow to the charging pump suction. Analysis of ID events initiated during each of the six plant operational modes (defined in the technical specifications) were performed. These analyses show that mode 5 (cold shutdown) results in the shortest available time for detection and termination of the avent. Therefore, the initial conditions and analysis parameters are chosen for the cold shutdown operational mode to minimize the interval from initiation of dilution to the time at which criticality is reached. Since a minimum flow of 4000 gpm is circulated through the RCS by the Shutdown Cooling System, complete mixing of boron within the RCS is assumed.
- 1. The technical specification lower limit on shutdown margin for cold shutdown is assumed, 2.016p.
- 2. The most adverse initial core condition would be for an initial K ff corresponding to 2.016p subcritical and assuming subcriticality i$
supplied by boron concentration only.
- 3. The cold reactor cgolant volume, excluding pressurizer and surge line, is 11,950 ft . A conservatively low reactor coolant mass was assumed by using the cold RCS internal volume. Assuming the coolant U
temperature of 210 F, the technical specification upper limit for cold shutdown, the resulting mass is 718,200 lbm.
- 4. All three charging pumps are assumed to be on at their maximum rate; 44 gpm per pump, for a total of 132 gpm. The corresponding mass flow ,
rate, assuming cold liquid flow, is 18.36 lbm/sec. I 15.4-13 Amendment No. 7 March 31, 1982
v i i
- 5. The initial boron concentration with all rods in and the inverse boron worth are 713 ppm and 56 ppm /% Ap respectively including uncertainties for the cold shutdown conditions: The initial subcritical boron
) concentration for the cold shutdown mode is found by adding the !
L/ product of the inverse boron worth and the minimum shutdown margin 1 (i.e. two percent ) to the critical boron concentration. The ) resulting minimum initial boron concentration is Mode 5 is 825 ppm. l Thus, the change of boron concentration from 2% Ap subcritical to j critical is 112 ppm. The parameters discussed above are summarized in Table 15.4.6-1. C. Results Using the above conservative parameters in Eauation (3), the minimum possible time interval to dilute from 2.0%6p subcritical to criticality is 95 minutes. Given the numerous indications of improper operation and the high neutron flux alarm on the startup flux channel, as provided in Figure 15.4.6-1, sufficient time is available to assure detection of a boron dilution event at least 15 minutes prior to criticality. Bornn dilution will then be terminated before loss of shutdown margin by the operator actions discussed in subsection 15.4.6.2. 15.4.6.4 Conclusions l The inadvertent deboration event will result in acceptable consequences. Sufficient time is available for the operator to detect and to terminate an inadvertent deboration event if it occurs. Fuel integrity is not challenged during this event, l l O Amendment No. 7 15.4-14 March 31, 1982
O THIS PAGE INTENTIONALLY BLANK. O . 1 i 4 O
v TABLE 15.4.6-1 ASSUMPTIONS FOR THE INADVERTENT DEB 0 RATION ANALYSIS j Parameter Assumptions Cogd RCS Volume (excluding pressurizer surge line), 11,950 ft RCS Mass (excluding pressurizer and surge line), lbm 718,200 Volumetric Charging Rate, gpm 132 Mass Charging Rate, 1bm/sec 18.36 l Dilution Time Constant, T , sec 39,118 Initial Boron Concentration-C(o), ppm 825 Critical Boron Concentration-Ccrit, ppm 713 I 1 i l I O l l i O d Amendment No. 7 March 31,1982
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15.4.7 INADVERTENT LOADING OF A FUEL ASSEMBLY INTO THE IMPROPER POSITION 15.4.7.1 Identification Of_ Events and Causes
% The Inadvertent ' Loading of a Fuel Assembly into the Improper Position event is )
l initiated by interchanging two fuel assemblies. The likelihood of an error in 1 core loading is considered to be extremely remote becuase of the strict f procedural control used during core loading. I l 15.4.7.2 Sequence of Events and System Operation The fuel enrichment within a fuel assembly is identified by a coded serial number marked on the exposed surface of the top end plate of the fuel l assembly. This serial number is used as a means of positive identification for I each assembly in the plant. A tag board is provided in the main control room j showing a schematic representation of the reactor core, spent fuel storage ' area. During the period of core loading, the location of each CEA, fuel assembly, and source will be shown on this tag board by a tag carrying its identification number. The tag board in the main control room will be constantly updated by a designated member of the reactor operations staff whenever a fuel assembly is being moved. He will be in constant communication with each area where this is occurring. Also, a licensed operator will be'present in the area where fuel assemblies are being handled to ensure that the assemblies are moved to the correct locations. Fuel assemblies will not be moved unless these lines of communication are available. In addition to these precautions, periodic independent inventories of components in the reactor core, spent fuel, and new fuel storage areas will be made to ensure that the tag board is correct. Al so , at the completion of core' loading, the exposed surfaces of the top end plates are inspected to verify that all assemblies are correctly located. These precautions are included in the core loading procedures which are to be reviewed by appropriate plant personnel. If, in spite of the extreme precautions described above, a fuel misloading does occur the consequences depend on the types and locations of the fuel assemblies that have been interchanged. The misloading of a fuel assembly may affect the core power distribution only slightly, for example, if assemblies of similar enrichments and reactivities are misloaded. Alternatively, if assemblies having very different enrichments or reactivities are misloaded the core power distribution may be affected enough so that core performance would be degraded. In the unlikely event that two assemblies of different enrichments would be interchanged, some misloadings would be detected using ex-core startup detectors and the reactivity computer during the low power physics testing. In these tests a symmetry check is performed in which the reactivity worths of symmetrically located CEAs are compared against one another. The interchange of two or more fuel assemblies with greatly different Ko _'s destroys the octant symmetry of the core flux distribution and would thus produce significant variations in the worths of symmetrically located CEAs. This asymmetry would 1 be corroborated by symmetry checks performed for other symmetric rod groups thereby confirming and possibly even locating a fuel assembly misload. In addition, many misloadings could be detected by either the ex-core detectors directly or the in-core detector channels which are analyzed-at power levels Amendment No. 7 . 15.4-15 March 31,1982 ! 1
\
i greater than 20 percent during the power ascension test at BOC and periodically throughout the cycle. Thus most of the fuel assembly misloadings that can be postulated are easily detectable both during the rod synmatry checks and during power range operation. However, there are .all number of misloadings which are undetectable during the rod symmetry testing or even early in the cycle with in-core instrumentation during power range operation. Of this small class the worst case is the interchange of a shimmed with an unshimmed one at the center of the core. This case, although not detectable at BOL, would cause l local power power peaking as the shims burn out. 1 15.4.7.3 _A_rjalysis of Ef fects and Consequences Several single assembly interchanges of this type were postulated and investigated using the fine-mesh neutronics methods discussed in Chapter 4.3. Most were shown to be detectable when estimates of the symmetric rod worths were calculated. Of those misloads which were not conclusively demonstrated to be detectable during startup at 80Cl, the interchange of assemblies 9 and 50 was shown to result in the highest F DR value (1.72) during subsequent full power operation over the first cycle. The associated power distribution shown in Figure 15.4.7-1 has a calculated minimum DNBR of 1.48. Since this is greater than the minimum acceptable DNBR of 1.19. no clad failure is expected to occur. Furthermore even though these misloads may not be detected during startup at BOC, it is very probable that the anomaly would be detected early in the cycle before the maximum FnR v lue is attained. This is because this type of interchange (i.e. shimmed with unshimmed) tends to produce an increasingly distorted power distribution which would alert the reactor engineer to the possibility of a fuel misloading. 15.4.7.4 Conclusion Those Inadvertent Loading of a Fuel Assembly into the Improper Position Events which are not detected during startup at BOCl do not result in fuel cladding consequences are within 10CFR100 guidelines O Amendment No. 7 March 31, 1982
,5.4-16 1
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/] i Amendment No. 7
, Ma rch 11 1009_
C-E / PLANAR AVERAGE POWER DISTRIBUTION CORRESPONDING TO p; g MAXIMUM F NPRODUCED BY A FUEL ASSEMBLY MISLOADING
<bbN'l / THAT IS UNDETECTABLE DURING STARTUP AT BOC
15.4.8 CONTROL ELEMENT ASSCMBLY (CEA) EJECTION 15.4.8.1 Identification of Event and Causes k A CEA Ejection results from a circumferential rupture of the control element drive mechanism (CEDM) housing or of the CEDM nozzle. 15.4.8.2 Sequence of Events and Systems Operation Table 15.4.8.-1 presents a chronological sequence of events which occur during a CEA ejection transient from the time the CEA and drive shaft are ejected until operator action is initiated. Figure 15.0-1, contains a glossary of SEA symbols and acronyms which may be used with the Sequence of Events Diagram, Figure 15.4.8-1, to trace the actuation and interaction of the systems utilized to mitigate the consequences of this event. Table 15.4.8-2 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient. Table 15.4,8-3 contains a matrix which summarize the utilization of safety systems as they appear in the sequence of events diagram. The success paths in the Sequence of Events Diagram, Figure 15.4.8-1, are as follows: Reactivity Control: Following the CEA ejection a reactor trip is generated by the Reactor Protective System (RPS) on variable overpower-high power condition and the Og CEAs drop in the core. As Reactor Coolant System (RCS) pressure decreases an SIAS is generated adding additional boron to the core by means of the HPSI pumps. A Recirculation Actuation Signal (RAS) occurs on low Refueling Water Tank (RWT) level and opens the containment sump isolation valves to supply the HPSI pumps during the recirculation phase. The operator closes the RWT i discharge valves. l Reactor Heat Removal: All four RCPs coastdown following the loss of offsite power. The depressurization of the RCS brings it to a temperature and pressure below that of the steam generators. The turbine trip and loss of main feedwater pumps following the iou of offsite power, bottle the steam generators up until the operator commences plant cooldown. A CIAS occurs on low pressurizer pressure. For plant cooldown, the operator uses the ADVs and auxiliary feedwater. The SCS is manually actuated when RCS temperature and pressure have been reduced to 350 F and 400 psia. This system provides sufficient cooling to bring the RCS to cold shutdown. Primary System Integrity: The Primary Safety Valves (PSVs) open to limit RCS pressure to an acceptable value. The PSV discharge is contained by the reactor drain tank. The operator ( throttles the HPSI pumps' isolation valves to control pressure during the cool down. Amendment No. 7 15.4-17 March 31, 1982
Secondary System Integrity: I The turbine trips on a reactor trip signal. The MFW pumps are assumed to trip ; on the subsequent loss of offsite power. The Main Steam Safety Valves (MSSVs) l open to disipate the heat transferred from the primary system until the primary system depressurizes. The steam generators then sit bottled up until the operator commences plant cooldown. Cooldown is accomplished by utilizing one feedwater pump designated as " auxiliary" and intended for normal startup and shutdown of the plant 'in conjunction with the ADVs. He may also let the ESFAS regulate the feedwater flow by issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions. See Applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater Systems. l Containment Integrity: ) A Containment Spray Actuation Signal (CSAS) is received on high-high containment pressure. The CS pumps spray water from the RWT into the containment to cool and reduce the pressure of the containment atmosphere. On low RWT level the containment sump isolation valves open to supply water to the containment spray pumps. Combustible Gas Control: Operator actuates BOP systems to control the hydrogen concentration in containment. See Applicant's SAR. Control Room Habitability: CI AS or SI AS or B0P signals may ectuate control room habitability systems. See Applicant's FSAR for details. Fuel Handling Building Habitability: CI AS or SI AS or BOP signals may actuate fuel handling building habitability systems. See Applicant's FSAR for details. Radioactive Effluent Control: l l CI AS isolates various systems to reduce or terminate radioactive releases. CI AS actuates primary, secondary, and containment isolation equipment. Otnar I actions may be initiated by 80P systems. See Applicant's FSAR for details. 1 Restoration of AC Power: A loss of offsite power occurs following turbine trip. The diesel generatorssubsequently start and supply power to the ESF loads. l l l 9 Amendment No. 7 March 31, 1982 15.4-18 1
15.4.8.3 Analysis of Effects and Consequences A. Mathematical Model h d The NSSS response to a CEA Ejection was simulated using the method of analysis described in Reference 16 of Section 15.0. The procedure outlined in Figure 2.1 of Reference 16 was used to determine the energy deposition in the fuel rod. The number of fuel pins predicted to experience departure from nucleate i boiling (DNB) was calculated using the STRIKIN-II computer program described in Section 15.0 with the CE-1 correlation described in Section 4. A matrix relating the initial and ejected CEA peaking factors to a pin census edit is obtained from Step 6 of the C-E Synthesis method and used to calculate the number of fuel pins experiencing DNB. Further conservatism is introduced by assuming that clad failure occurs when fuel rods experience DNB. The time dependent energy deposition in' the RCS was determ'ned from the above analysis and input into the CESEC-II computer program described in Section 15.0 to determine the overall NSSS response to this event. ' B. Input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to a CEA Ejection are discussed in Section 15.0. A spectrum of initial reactor states (including conditions characteristic of the beginning and end of the fuel cycle) was considered. Table 15.4.8-4 contains assumptions regarding the l initial reactor states analyzed for this event. The initial conditions for the principal process variables were varied within the reactor operating space given in Table 15.0-5 to determine the set of conditions which produce the most adverse consequences following a CEA Ejection. Various combinations of initial core inlet temperature, core inlet Oy flow rate, pressurizer pressure and axial power distribution were considered. The initial pressurizer and steam generator water level, as controlled within the operating space, have an insignificant effect on the consequences of the l CEA ejection analysis. For all cases analyzed, an axial power distribution was chosen to maximize the )' energy content in the hottest fuel pellet. The remaining parameters were chosen based on the results shown in Chapter 4 of Reference 16. These parameters were varied in the most adverse direction until a COLSS power operating limit was achieved. C. Results The spectrum of initial reactor states contained in Table 15.4.8-4 was analyzed to show that each case met the criteria established in Regulatory Guide 1.77. All cases resulted in a radial average fuel enthsipy less than 280 cal / gram at the hottest axial location of the hot fuel pin. The case that resulted in the greatest potential for off site dose consequences (i.e., the case resulting in the largest number of postulated fuel failures) was identified as the case initiated from full power (FP) beginning-of-cycle (B0C) initial conditions. i The following paragraphs describe this event in detail. Refer to Table 15.4.8-5 for the initial conditions and assumptions used for this analysis. ! Figures 15.4.8-2 through 15.4.8-6 show the reactor power, heat flux, and clad and fuel temperatures during the significant portion of transient. Table 15.4-19 Amendment No. 7 March 31, 1982
15.4.8-1 contains the sequence of events that occur during a CEA Ejection initiated from full power B0C initial conditions. Ejection of a CEA causes the core power to increase rapidly due to the almost instantaneous addition of positive reactivity. However, the rapid increase in core power is terminated by a combination of Doppler feedback and delayed neutron effects. This increase in power results in a high power trip and the reactor power begins to decrease as the CEA's enter the core. Reactivity effects are shown in Figure 15.4.8-7. In the hot channel, the increase in heat flux is such that DNB is calculated to occur, resulting in:
- 1. A rapid decrease in the surface heat transfer coefficient.
- 2. A rapid decrease in heat flux.
- 3. A rapid increase in clad temperature.
The rapid increase in clad temperature is sufficient to override the decreased surface heat transfer coefficient, resulting in a second peak in the hot channel heat flux. At this time the CEAs are nearly fully inserted, resulting in a rapid reduction in the core power level. The heat flux continues to decrease for the remainder of the transient. Initial RCS pressure for calculation of the limiting fuel performance and radiological release event was 22.00 psia. RCS pressure vs. time for this case is given on Figure 15.4.8-8. The long term RCS pressure response is shown on Figure 15.4.8-10. Initial RCS pressure for the limiting peak pressure case is 2400 psia. RCS pressure vs. time for this case is given on Figure 15.4.8-9. Steam generator pressures, and steam generator safety valve flow rate following l a FPB0C CEA ejection with a postulated loss of offsite power following l turbine trip are shown in Figures 15.4.8-11 through 15.4.8-13. ! The transient behavior of the NSSS following a postulated CEA Ejection is as follows. The steam generator pressure increases rapidly due to the closure of the turbine control vdve following reactor and turbine trip. The steam bypass control system is inoperable on loss of offsite power and therefore is unavailable. The steam generator pressure reaching a maximum of 1348 psia at 4.9 seconds. The pressurizer pressure increases to a maximum of 2525 psia at l 10 3.9 seconds due to the decreased heat removal of the steam generators. Subsequently, the reduced reactor power following the reactor trip, in addition to the postulated break in the primary system, cause the RCS Pressure and temperature to decrease. The steam generator pressure decreases slowly until the main steam safety valves close. The total released through the safety valves is approximately 136,800 lbm. Following a postulated CEA Ejection Event, 9,8% of the fuel is calculated to experience DNB. Regulatory Guide 1.77 recommends that the onset of DNB be used as the basis for predicting clad failure. C-E does not equate caset of DNB with cladding failure. Nevertheless, this criterion was used to determine the percentage of pins that suffer clad failure. I 15.4-20 Amendment No. 10 I June 28, 1985
v The activity released to the containment (through the ruptured CEDM pressure housing), is assumed to be mixed instantaneously throughout the containment and is available for leakage to the atmosphere. (~ lhe activity released from the secondary system is the activity released to the atmosphere from the main steam safety valves and from the atmospheric dump valves during cooldown. The assumptions, parameters and calculational methods used to evaluate the radiological consequences of Chapter 15 events are discussed in Section 15.0-4. Assumptions and parameters that were unique to the evaluation of a CEA Ejection Event are itemized in Table 15.4.8-6. The following paragraphs provide additional clarification to some of the items contained in the table. Item B.1-c Activity available for release from containment at time zero. l The activity available for leakage from containment is based on the following Regulatory Guide 1.77, Appendix B assumptions:
- 1. The activity in the fuel clad gap is 10% of the iodines and 10% of the noble gases accumulated in the fuel at the end of core life, assuming continuous maximum full power operation. All of the activity in the fuel gap for fuel rods that are calculated to experience DNB is assumed to be instantaneously available for release from containment.
- 2. The nuclide inventory of the fraction of fuel which reaches or exceeds the initiation temperature of fuel melting at any time during the transient was calculated; 100% of the noble gases and 25% of the iodines were assumed to be instantaneously available for release from the containment.
Item B.2.a-b Activity Release from the Secondary System. Activity released from the secondary system is based upon the secondary activity initially in the steam generators plus primary activity resulting from technical specification steam generator tube leak. Table 15.4.8-7 contains the integrated mass releases from the main steam safety valves and the total primary to secondary leakage. The mass of steam released through the ADVs is given on Table 15.4.8-6. Item B.2.c Reactor Coolant System Activity After Event The RCS activity after the event was based on the assumptions given above, with the following exception. For the fraction of fuel which reaches or exceeds the fuel melting temperature at any time during the event, 50% of the iodines accumulated in the fuel at the end of core life were assumed to be uniformly mixed with the reactor coolant. 15.4.8.4 Conclusicn3 i The rupture of a CEDM nozzle or housing and the subsequent e.iection of a CEA l' will not result in a radial average fuel enthalpy greater than 280 cal / gram at any axial location in any fuel rod. The radiological consequences associated with secondary system steam releases have been conservatively analyzed using q assumptions and models described in the preceeding sections. The whole-body dose due to immersion and the thyroid dose due to inhalation have been analyzed 1 Amendment No. 7 15.4-21 March 31, 1982 i I
for the two-hour dose at the exclusion area boundary and are presented in Table 15.4 3-8. The resultant doses are less than the allowable site boundary dose set forth in 10CFR Part 100. Doses due to containment leakage have not been included in this comparison and will be provided in the Applicant's FSAR. The peak RCS pressure for the CEA Ejection event is 2757 psia. This is less than Service Limit C value as defined in the ASME code. O 1 l O Amendment No. 7 15.4-22 March 31, 1982
9 TABLE 15.4.8-1 (Sheet 1 of 2) SEQUENCE OF EVENTS FOR THE CFA EJECTION EVENT Time Setpoint Success (sec) Event or Value Path 0.0 Mechanical Failure of -- CEDM Causes CEA to Eject 0.03 Core Power Reaches Variable 117 Reactivity Overpower Reactor Trip Control Analysis Setpoint, percent 10 of design power 0.05 CEA Fully Ejected -- 0.08 Maximum Core power, 138.3
% of design power 0.43 Variable Overpower Trip Reactivity Signal Generated Control 9 0.58 Trip Breakers Open --
Reactivity Control 10 0.92 Turbine Trip Occurs -- Secondary Integrity 2.53 Main Steam Safety 1282 Secondary Valves Open, System psia Integrity 2.6 Maximum C Hd Surface 936 Temperature in the Hot Node, F 3.8 Maximum Fuel Centerline 3779 Temperature in the Hot Node, F 3.9 Pressurizer Safety Valves 2525 Primary Open, psia System Integrity O Amendment No. 10 June 28, 1985
TABLE 15.4.8-1 (Cont'd) (Sheet 2 of 2) SEQUENCE OF EVENTS FOR THE CEA EJECTION EVENT Time Setpoint Success (sec) Event or Value Path 3.9 Maximun Pressurizer 2525 Pressure, psia 4.7 Pressurizer Safety Valves 2462 Primary Closed, psia System Integrity 4.9 Maximum Steam Generator 1348 Pressure, psia 39.5 Pressurizer Pressure Reaches 1580 Reactor Heat Safety Injection Actuation Removal Signal Analysis Setpoint, 10 ! psia 40.5 Safety Injection Actua- -- Reactor Heat tion Signal Generated Removal 70.1 Safety Injection Flow -- Reactor Heat Initiated Removal 850 Main Steam Safety 1250 Secondary Valves Closed, psia System Integrity 1800 Operator begins plant -- Secondary , cooldown System Integrity 12230 Shutdown cooling 400/350 Reactor Heat initiated, RCS pressure, Removal temperature, F O Amendment No. 10 June 28, 1985
. TABLE 15.4.8-2 (Sheet 1 of 2)
DISPOSITION OF NORMALLY OPERATING SYSTEMS l l
, FOR THE CEA EJECTION EVENT l \
\a'
%4 Gcw.,%
d, \G l o 9 > #o
' Q vb e 0 . 's - e o Y p #d#og G. g e vD <> 1 9
*p SYSTEM e 'O
- 1. Main Feedwater Control System / 1
- 2. Main Feedwater Pump Turbine Control System * / 1 Turbine-Generator Control System * / 1
- 3. ,
/
- 4. Steam Bypass Control System 1
- 5. Pressurizer Pressure Control System 1 l l /
- 6. Pressurizer Level Control System 1 l 7. Control Element Drive Mechanism Control System / 1
- 8. Reactor Regulating System / 1
- 9. Core Operating Limit Supervisory System / 1
- 10. Reactor Coolant Pumps / 1 l
- 11. Chemical and Volume Centrol System / 1
- 12. Secondary Chemistry Control System * / 1 Condenser Evacuation System * /
- 13. 1
- 14. Turbine Gland Sealing System
- 1
- 15. Nuclear Cooling Water System * / 1
- 16. Turbine Cooling Water System- / 1
- 17. Plant Cooling Water System * / I Condesate 5:orage Facilities * /
- 18. ,
1
- 19. Circulating Water System * / 1
- 20. Spent Fuel Pool Cooling and Clean-Up System * / 1
(^' U
- 21. Non-Class 1E (Ncn-ESF) A.C. Power * / 1
- 22. Class lE (ESF) A.C. Power * / ,
I
*Calance-of-Plant Systems -
~
~
Amendment No. [ March 31, 1982
TABLE 15.4.8-2 (CONTINUED) (Sheet 2 of 2) DISPOSITION OF NORMALLY OPERATING SYSTEMS FOR THE CEA EJECTION EVENT 4 O'
, '?0
'C. G Q %:. p ,, #
% ,. . D Y 9
' %y ,.s % #'o c
', Qj. c,o. c.e '-% (^c -
0 < 's,- O e ,. , o SYSTEM g -
- 23. tion lass lE 0.C. Power * /
- 24. Class 1E D.C. Power * /
fl0TES :
- 1. Loss of offsite power following turbine trip results in loss of power to the Non-ESF loads. The j i
diesel generators start and supply power ; to the ESF loads. l l 1 I I l l I I i i
! l l
1 i i i ie "Dalance of-Plant Systems ij
. _ _ _ _ .= = ---- -
========-
Amendment No. 7 March 31, 1982
TABLE 15.4.8-3 UTILIZATION OF SAFETY SYSTEMS FOR THE CEA EJECTION EVENT O ,
\
Ye 9( 'o & hO c
+%C
\# Yb hb b A
bj
^> c OgQ g 7p
,h o
#0, SYSTDI AT Q'Co
-a z .
- 1. Reactor Protection System /
- 2. DNBR/l.PD Calculator
', 3. Engineered Safety Features Actuation Systems /
} 4. Supplementary Protection System S. ReacLoc Trip Switch Gear /
- 6. Main Steam Safety Valves * /
) 7. Primary Safety Valves /
- 8. Main Steam Isolation System * /
- 9. Emergency Feedwater System * / 1
- 10. Safety Injection System /
- 11. Shutdown Cooling System /
- 12. Atmospheric Dump Valve System * /
- 13. Containment Isolation System * /
- 14. Containment Spray System * /
I15. Iodine Removal System * /
' 16.
Containment Combustible Gas Control System * / l17. Diesel Generators and Support Systems * /
- 18. Component (Essential) Cooling !!ater Systeu* /
- 19. Station Service !!ater System * /
Iotes: 4 1. One auxiliary feedwater pump is used for cooldown. <
-l
- Balance-of Plant Systems -
**A#cRt 3V 1382
' 1 TABLE 15.4.8-4 l INITIAL REACTOR STATES CONSIDERE0 FOR THE CEA EJECTION EVENT
- Initial Ejected Ejected Radial Rod Configuration Rod Worth, (%Ap )
Peaking Factor Bank 5 Inserted 0.002 2.20 Banks 4 & 5 Inserted 0.003 2.65 Banks 3, 4, & 5 0.004 4.90 Inserted Banks 2, 3, 4, & 5 0.007 5.60 Inserted Banks 1,2,3,4 & 5 Inserted 0.010 8.00
*All cases were initiated from BOC and EOC initial conditions.
O 1 i 1 l 9 Amendment No. 7 March 31, 1982
TABLE 15.4.8-5
\d ASSUMPTIONS USED FOR THE CEA EJECTION ANALYSIS FULL POWER BEGINNING OF CYCLE INITIAL CONDITIONS Parameters Assumptions Initial Core Power Level, Mwt 3876 Delayed Neutron Fraction, 6 .00730 Moderator Temperature Coef ficient Section 15.0 Most positive value Ejected CEA Worth, 10-2 Ap 0.2 1 Doppler Weighting Factor, 1.0 Initial Three-Dimensional Fuel 2.31 Pin Peaking Factor Ejected Three-Dimensional Fuel 3.30 Pin Peaking Factor Total CEA Wo "S Available for -3.81 Insertion a eactor Trip,10-2 Ap l Postulated CEA Ejection Time, sec 0.05 l
Core Inlet Coolant Temperature, F 580 Core Mass Flow Rate, 106 lbm/hr 177.6 Reactor Coolant System Pressure, psia 2200 Break Size, ft 2 0.04 l l (O l l Amendment No. 7 l March 31, 1982
7 TABLE 15.4.8-6 (Sheet I of 4) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A CEA EJECTION Parameter Value A. Data and Assumptions Used to Evaluate the Raioactive Source Term
- 1. General
- a. Power Level, Mwt 3876
- b. Burnup E0C (Equilibrium)
- c. Percent of Fuel Calculated 9.8 to Experience DNB, %
- d. Percent of Fuel Calculated 0.0 to Experience Incipient l Centerline Melt, %
- e. Reactor Coolant Activity Table 11.1-2 Before Event l <
- f. Secondary System Activity Section 15.0.4 ;
Before Event l l I
- g. Primary System Liquid 533,700 Inventory, lbm
- h. Steam Generator Inventory 1
- Liquid, lbm per steam generator 159,000 l l
- Steam, lbm per steam generator 15,034 B. Data and Assumptions Used to Estimate Activity Released
- 1. Containment Leakage
- a. Containment Volume, f t 3 Refer to Applicant's SAR
- b. Containment Leak Rate, vol. Refer to
%/ day Applicant's SAR l
- 0 to 24 hours
- 1 day to 30 days l
Amendment No. 7 March 31, 1982
TABLE 15.4.8-6 (Cont'd.) (Sheet 2 of 4) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A CEA EJECTION Parameters Value
- c. Activity Available for Release from Containment at Time Zero, Ci Isotope I-131 1.55(+6)
I-132 2.24(+6) I-133 3.0(+6) 1-134 3.10(+6) I-135 2.79(+6) Kr-85M 3.19(+5) Kr-85 1.59(+4) Kr-87 5.66(+5) Kr-88 8.17(+5) Xe-131M 9.96(+3) Xe-133 3.03(+6) Xe-135 4.53(+5) Xe-138 2.30(+6)
- d. Percent of Core Fission Products Refer to Para-Assumed Released to Containment graph 15.4.5.2.3.C
- e. Credit for Radioactive Decay
- Hold up in Containment Yes
- In Transit to Dose Point No
- 2. Activity Release from the Secondary System
- a. Primary to Secondary Leak Rate, 1.0 (total) gal / min.
- b. Total Mass Release Through the 136,800 Main Steam Safety Valves
- c. Total Mass Release Through the 714,000 ADVs from 30 minutes to 2 hours, lbm I Numbers in parenthesis indicate powers of 10 O
Amendment No. 7 March 31, 1982
i TABLE 15.4.8-6 (Cont'd. ) ( Sheet 3 of 4) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A CEA EJECTION Parameters Value
- d. Reactor Coolant System Activity After Event, Ci Isotope I-131 1.55(+6)
I-132 2.24(+6) I-133 3.0(+6) 1-134 3.10(+6) 1-135 2.79(+6) Kr-85M 3.19(+5) Kr-85 1.59(+4) Kr-87 5.66(+5) Kr-88 8.11(+5) Xe-131M 9.96(+3) Xe-133 3.03(+6) Xe-135 4.53(+5) Xe-138 2.30(+6)
- e. Percent of Core Fission Products Refer to Section Assumed Released to Reactor Coolant 15.4.8.2.3.C
- f. Iodine Carryover Fraction in the Section 15.0.4 Steam Generators 9 Credit for Radioactive Decay in No Transit to Dose Point
- h. Loss of Offsite Power Yes C. Dispersion Data i I
- 1. Distance to Exclusion Area 500 {
Boundary, m i O' Amendment No. 7 March 31, 1982
1 TABLE 15.4.8.-6 (Cont'd.) (Sheet 4 of 4) l PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A CEA EJCCTION I g l I Parameters Value
- 2. Distance to Low Population Zone 3000 ,
Outer Boundary, m !
- 3. Atmospheric Dispersion Factor, 2.00 x 10-3 sec/m
)
D. Dose Data
- 1. Method of Dose Calculation Section 15.0-4 l
- 2. Dose Conversion Assumptions Section 15.0-4
- 3. Control Room Design Parameters See Applicant's i SAR 0
O ol G Amendment No. 7 March 31, 1982 1
TABLE 15.4.8-7 SECONDARY SYSTEM MASS RELEASE TO THE ATMOSPHERE Time Integrated Safety Integrated Primary (Sec) Valve Flow to Secondary Leakage 0.0 0.0 0.0 2.0 0.0 / 0.2 3.0 460 0.3 5.0 5110 0.5 10.0 25490 1.0 20.0 53400 2.0 120.0 93400 12.0 220.0 110522 22.0 320.0 122120 32.0 420.0 127090 42.0
*850.0 136783 85.0
**1800.0 136783 180.0 Main steam safety valve close Operator takes control of plant and begins cooldown utilizing atmospheric dump valves. '
O t t Amendment No. 7 March 31, 1982
TABLE 15.4.8-8 RADIOLOGICAL CONSEQUENCES OF A POSTULATED CEA EJECTION EVENT O From Containment Secondary Systera From Result Leakage: Steam Releases Exclusion Area Boundary Dose (0-2 hours), rem: Thyroid Refer to Applicant's 46.0 Whole-body SAR 6.04 l O O Amendment No. 7 March 31, 1982
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min {jfI 6 STANDARD DESIGN ! N 4 l ' i 7 M9,N-CESSAR !!!' rip,c,1,o, O Volume 12 ,,,,,,,,,y ,,, , ,,,,,,,
v 15.5 INCREASE IN RCS INVENTORY I O 15.5.1 INADVERTENT OPERATION OF THE ECCS d 15.5.1.1 Identification of Event and Causes The inadvertent operation of the emergency core cooling system (ECCS) is assumed to actuate the high pressure safety injection (HPSI) pumps (2) and open the corresponding discharge valves. This operation occurs as a result of a spurious signal to the system or operator error. 15.5.1.2 Sequence of Events and Systems Operation Inadvertent operation of the ECCS is or.ly of consequence when it occurs below the HPSI pump shutoff head pressure. Above that pressure there will be no injection of fluid into the system. Below the HPSI pump shutoff head pressure when the shutdown cooling system is isolated the HPSI flow will increase RCS inventory and pressure until the pressure reaches the pump shutoff head pressure. During shutdown cooling system operation the increase in RCS ' inventory and pressure will be mitigated by the shutdown cooling system relief valves. 15.5.1.3 Analysis of Effects and Consequences Plant operation above the HPSI pump shutoff head pressure will not be impacted by the inadvertent operation of the ECCS. Below the HPSI pump shutoff head pressure when the shutdown cooling system is isolated, there will be an RCS O inventory and pressure increase. This increase will be terminated when the pressure rises above the shutoff head pressure. Due to the pressure increase caused by this transient at low RCS temperatures, there is an approach to thc brittle fracture limits of the RCS. Examination of Figure 16.3.4-2, RCS Temperature-Pressure Limitations, shows that the brittle fracture limits will not be violated for this transient. Should the ECCS inadvertently actuate during shutdown cooling operation, the shutdown cooling relief valves will mitigate the pressure transient so that the limits in Figure 16.3.4-2 are not exceeded. The shutdown cooling relief valves are only isolated when the shut off head of the HPSI pumps is below the pressure temperature limits for brittle fracture of the RCS. 15.5.1.4 Conclusion The peak pressurizer pressure reached during the inadvertent operation of the ECCS is well within 110% of design pressure. Additionally, the pressure-temperature limits for brittle fracture of the RCS are not violated by this transient. The fuel integrity is not challenged by this event. 15.5.2 CVCS MALFUNCTION-PRESSURIZER LEVEL CONTROL SYSTEM MALFUNCTION WITH LOSS OF 0FFSITE POWER 15.5.2.1 Identification of Event and Causes All events and events plus single failures which cause an increase in RCS Q inventory were examined with respect to the Reactor Coolant System (RCS) Q pressure and fuel cladding performance. Pressurizer Level Control System Amendment No. 7 15.5-1 March 31, 1982
l l (PLCS) malfunction in combination with the loss of offsite power as a result of the assumed grid failure when the turbine trips was identified as the limiting ] event. l When in the automatic mode, the PLCS responds to changes in pressurizer level j' by changing charging and letdown flows to maintain the program level. Normally, one charging pump is running with two charging pumps available for automatic startup when a low level setpoint is reached. If the pressurizer level controller fails low or the level setpoint generated by the reactor regulating system fails high, a low level signal can be transmitted to the controller. In response, the controller will start all the charging pumps and close the letdown control valve to its minimum opening resulting in the maximum mass addition to the RCS. 1 The limiting single failure was determined with respect to its impact on fuel performance and system pressure. Regarding the pressure criteria, the major factors which cause an increase in RCS pressure are:
- a. increasing coolant temperature.
- b. decreasing core flow.
- c. decreasing primary to secondary heat transfer. ,
The PLCS malfunction causes a reactor trip, on high pressurizer pressure, resulting in the maximum RCS pressure in the first two to five seconds following reactor trip. Therefore, any single failure which would result in a higher RCS pressure during the transient would have to affect at least one of the above parameters during the first two to five seconds following reactor
-ip.
The single failures that have been postulated are listed in Table 15.0-6. The failures which affect the RCS behavior during this interval are (1) loss of normal AC, (2) failure of the pressurizer pressure control system, (3) failure of the steam bypass control system, (4) failure of the reactor regulating system and (5) f ailure of the feedwater control system. The loss of normal AC power results in loss of power to the reactor coolant pumps, the condensate pumps, the circulating water pumps, the pressurizer pressure and level control system, the reactor regulating system, the feedwater control system, and the steam bypass control system. The effect of losing normal AC power on the PLCS malfunction is as follows. j Loss of the reactor regulating system will have no appreciable affect on the { transient in the first five seconds. Loss of the steam bypass control system I and feedwater control system results in a rapid build-up in secondary pressure and temperature. This reduces primary to-secondary heat transfer and a further decrease in heat transfer is experienced as the reactor coolant pump coast down. The resulting RCS pressure increase is further aggravated as the pressurizer sprays are not available due to the loss of power to the reactor coolant pumps and pressurizer pressure control system. An individual loss of one of the control systems is bounded by the assumption of the loss of normal AC power with respect to RCS pressure increase. Thus none of the single failures listed in Table 15.0-6 will result in a higher RCS pressure than that predicted for a PLCS malfunction with a loss of offsite power as a result of turbine trip. 15.5-2
v o Regarding the approach to the fuel design limit, the major parameter of concern f is the minimum hot channel DNBR. The major factors which cause a decrease in V local DNBR are:
- a. increasing coolant temperature.
- b. decreasing coolant flow. I
- c. increasing local heat flux (including radial and axial power !
distribution effects). The PLCS malfunction causes a reactor trip, and thus minimum DNBR occurs in the first two to five seconds following trip. No single failure was identified from Table 15.0-6 which would have a significant affect on DNBR prior to the reactor trip. Therefore, any single failure which would result in a lower DNBR during the transient would have to affect at least one of the above parameters during the first two to five seconds of the event. The single failures that have been postulated are listed in Table 15.0-6. The failures which affect the RCS behavior during this interval are (1) a loss of normal AC power, (2) a failure of the pressurizer pressure control system, and (3) a failure of the reactor regulating system. The loss of normal AC power results in loss of rower to the reactor coolant pumps, the circulating water pumps, the pressurizer pressure and level control system, the reactor regulating system, and the feedwater control system.
]
The effect of losing normal AC power on the PLCS malfunction is as follows: Loss of power to the condensate and circulating water pumps and the feedwater (i control system initially affect only the secondary system and, thus, do not affect DNBR in the first two to five seconds of the transient. Loss of power to the reactor regulating system pressurizer level and pressure control systems i renders those systems inoperable. This inoperability will have no significant I impact on DNBR during the first two to five seconds. Loss of power to the reactor coolant pumps is the only significant failure with regard to DNBR which results from a loss of normal AC power. Failure of the pressurizer pressure control system or reactor regulating system cannot appreciably affect any of the major factors which determine DNBR during , the first two to five seconds of the event. Thus, none of the single failures { listed in Table 15.0-6 will result in a lower DNBR than that predicted for the ! PLCS malfunction with a loss of offsite power as a result of turbine trip. l 15.5.2.2 Sequence of Events and Systems Operation Table 15.5.2-1 presents a chronological sequence of events which occur during a PLCS malfunction in combination with loss of offsite power fron the initial malfunction until the operator stabilizes the plant and initiates plant cooldown. Table 15.5.2.-1 contain; the sequence of events diagram which, together with Figure 15.0-1 (containing a glossary of SEA symbols and acrcnyms) may be used to trace the actuation and interaction of systems used te mitigate the consequences of the event. Table 15.5.2-2 contains a r.iatrix which describes O the extent to which normally operating plant systeme are assumed to function l during the course of the event. i Amendment No. 7 l 15.5-3 March 31, 1982
v i
)
The success paths on the Sequence of Events Diagram (Figure 15.5.2-1) are described below: Reactivity Control: The excess of charging over letdown and the assumed Pressurizer Pressure Control System operating mode results in the pressurizer pressure reaching the high pressure reactor trip set-point. A reactor trip and CEA insertion follow. Prior to initiating or during manual cooldown the opertor adjusts the boron concentration to insure that a proper negative reactivity shutdown margin is achieved. The boron concentration is adjusted nanually using the charging pumps and letdown if normal power to the ESF buses has been reestablished or using the HPSI pumps and replacing RCS volume shrinkage if normal power to the ESF buses has not been reestablished. Primary System Integrity: The closing of the turbine stop valves, the interruption of the feedwater flow, : and reduction of reactor coolant f70w due to loss of non-emergency AC, results in an increase in RCS pressure which opens the primary safety valves. The reactor drain tank serves as a receptacle for 796.5 lbm of steam released. If non-emergency AC power has been reestablished RCS pressure and level are manually reestablished utilizing the unfailed components in the pressurizer pressure and level control systems. If non-emergency AC power has not been , reestablished, the HPSI discharge valves will be throttled to control the rate I of change of RCS pressure. As the cooldown proceeds, the operator will reduce the safety injection actuation setpoint to prevent the inadvertent generation of an SIAS. When the RCS pressure has been reduced to approximately 650 psia, the operator will vent or drain the SITS to reduce their pressure and will then isolate them. Reactor Heat Removal: l Following loss of power to the non-ESF loads as a result of turbine trip and subsequent grid collapse the reactor coolant pumps coastdown. Reactor heat removal takes place by means of natural circulation. The Shutdown Cooling System (SCS) is manually actuated when RCS temperture and pressure have been reduced to 3500 F and 400 psia respectively. This system provide sufficient cooling flow to cool the RCS to cold shutdown. Secondary System Integrity: Turbine trip results from the reactor trip on high pressurizer pressure. The external grid which the plant is feeding is assumed to collapse because this plant goes off line; therefore, no non-emergency AC is available within the plant. Condenser vacuum is lost therefore the steam bypass system is not available. This causes the main steam safety valves to open and stay open until the operator takes control at 30 minutes. Main feedwater is lost on loss of condenser vacuum. After 30 minutes the operator utilizes the AFWS and the atmospheric dump valves to cool the primary system. O i Amendment No. 7 15.5-4 March 31,1982
The AFWS may be a separate system or may be one emergency feedwater pump I designated as " auxiliary" and intended for normal startup and shutdown of the l plant. He may also let the ESFAS regulate the feedwater flow by issuing and O D withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions. See Applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater systems. As the cooldown proceeds, the operator reduces the main steam isolation actuation setpoint to prevent the inadvertent generation of an < MSIS. Restoration of AC Power: A loss of normal power to ESF loads causes the loads to be shed from the 4.16 KV buses (except 480V load centers). The diesel generators are automatically started and sequentially connected to selected ESF load groups to restore essential AC power. Spent Fuel Heat Removal: 1 Spent Fuel Pool (SFP) cooling is terminated on the loss of normal power to the ESF loads. Spent fuel heat removal is continuously accomplished by utilizing the heat capacity of the SFP water. Pool cooling is restored by manually loading the SFP cooling pumps onto the diesel generators and by aligning the SFP heat exchangers to receive essential cooling water. Table 15.5.2-3 contains a matrix which summarizes the utilization of safety l systems as they appear in this transient analysis. ) 15.5.2.3 Analysis of Effects and Consequences A. Mathematical Mode i The Nuclear Steam Supply System (NSSS) response to PLCS malfunction with loss j of offsite power at the time of turbine trip was simulated using the CESEC-II j computer program described in Section 15.0.3. i B. Input Parameters and Initial Conditions Table 15.5.2-4 lists the assumptions and initial condition used for this analysis in addition to those discussed in Section 15.0. Additional clarification to the assumptions and parameters listed in Table 15.5.2-4 is provided as follows: i Since the pressure transient is due to an increase in primary coolant inventory ! and not to thermal expansion, no power, coolant temperature, or DNB transient l is produced prior to reactor trip. Therefore, the initial conditions for the 1 principal process variables, with the exception of RCS pressure, have no effect on the consequences. Minimizing the initial RCS pressure maximizes time to reactor trip on high pressurizer pressure and maximizes increase in RCS inventory prior to trip. An initial pressure of 1785 psia was chosen which is the icwest possible RCS pressure of the operating range. Initial water volume in the pressurizer was chosen to be 60% of the total volume. > I Since the charging flow through the regenerative heat exchanger exceeds the l l 1etdown flow, the temperature of the makeup water added to the RCS by the V { l : 15.5-5 Amendment No. 7 j March 31,1982
charging pumpe is decreased significantly. Therefore, the most negative value of MTC was selected to maximize the positive reactivity addition from injection of cold makeup water. Tctal charMng flow due to all three pumps is 132 GPM. Considering 16 GPM for the cer.crol bleed takeoff and 30 GPM for the minimun letdown flow, net flow inc. ease to the RCS is 86 GPM. The Pressurizer Pressure Control System (PPCS) is assumed to he in the manual mode with the proportional sprays off preventing the PPCS from suppressing the resulting pressure transient. C. Results The dynamic behavior of NSSS parameters following PLCS malfunction with loss of offsite power at turbine trip is presented in Figures 15.5.2-2 to 15.5.2-11. Failure of the Pressurizer Level Control System (PLCS) causes an increase in reactor coolant system inventory initiated by the startup of the third charging pump coupled with the decrease in letdown flow to its minimum. With the PPCS in the manual mode and the proportional sprays turned off, increase in RCS inventcry results in a pressurizer pressure increase to the reactor trip analysis setpoint of 2450 psia at 1250.1 secoads. The trip breakers open at 10 1251.25 seconds. Since the steam bypass control system is in the manual mode and the rate of closure of the turbine stop valves is faster than the rate of control rod insertion, pressurizer pressure increases to 2561 psia which opens the primary safety valves. Decreasing core heat flux and the opening of the primary safety valves causes the pressure to drop; however, the decrease in primary to secondary heat transfer due to four pump loss of flow causes pressurizer pressure to again increase, reaching a peak value of 2480 psia. The unavailability of the steam bypass valves causes the steam generator pressure to increase, causing the main steam safety valves to open at 1265.5 seconds. The decreasing core power and the safety valves function to limit the steam generator pressure to 1298 psia. The 796.5 lbs of steam discharged by the pressurizer safety valve is contained in the quench tank with no releases to the atmosphere. The main steam safety valves discharge 22,714 lbs of steam to the atmosphere prior to 1800 seconds. At 1800 seconds, the operator stabilizes the plant and initiates plant cooldown, using steam dump valves. 15.5.2.4 Conclusion The peak pressurizer pressure reached during the Pressurizer Level Control System malfunction with a loss of offsite power at turbine trip is 2561 psia and is less than 110% of the design pressure. Since this transient causes an increase in RCS pressure due to an increase in primary coolant inventory the DNBR increases. Therefore, the acceptance criterion regarding fuel performance is met. O 15.5-6 Amendment No. 10 June 28, 1985
l p TABLE 15.5.2-1 SEQUENCE OF EVENTS FOR THE PLCS MALFUNCTION WITH A LOSS OF OFFSITE POWER AT TURBINE TRIP Time Setpoint Success (Sec) Event or Value Path
- 0. Charging Flow Maximized --
A Letdown Flow Minimized 1250.1 Pressurizer Pressure Reaches 2450 Reactivity Reactor Trip Analysis Control Setpoint, psia ; 1251.1 High Pressurizer Pressure -- Trip Signal Generated 10 1251.25 Trip Breakers Open -- Reactivity Control 1251.6 Turbine Trip, Loss of -- Offsite Power 1252.7 Pressurizer Safety 2525 Primary Valves open, psia System O V Integrity 1253.2 Maximum Pressurizer 2561 Pressure, psia 1262.3 Pressurizer Safety 2525 Secondary Valves Close, psia System Integrity 1265.5 Main Steam Safety 1282 Secondary Valves Open, psia System Integrity 1270.3 Maximum Steam Generator 1298 Pressure, psia 1800.0 Operator Initiates -- Reactor Heat Plant Cooldown Removal
\
(G Amendment No. 10 June 28, 1985
TABLE 15.5.2-2 (Sheet 1 of 2) DISPOSITION OF fl0RMALLY OPERATIllG SYSTEliS FOR THE PLCS MALFUNCTION WITH , LOSS OF 0FF-SITE POWER i 1 Q
^ O#
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- 1. Main Feedwater Control System /
- 2. Main Feedwater Pump Turbine Control System * /
- 3. Turbine-Generator Control System * /
- 4. Steam Bypass Control System /
- 5. Pressurizer Pressure Centrol System / l
- 6. Pressurizer Level Control System 1
- 7. Control Element Drive Mechanism Control System /
- 8. Reactor Regulating System /
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps /
- 11. Chemical and Volume Control System /
- 12. Secondary Chemistry Control System * /
- 13. Condenser Evacuation System * /
- 14. Turbine Gland Sealing System * /
- 15. Nuclear Cooling Water System * /
- 16. Turbine Cooling Water System * /
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities * /
- 19. Circulating Water System * /
- 20. Spent Fuel Pool Cooling and Clean-Up System' /
- 21. /
Non-Class lE (Non-ESF) A.C. Power *
- 22. /
Class lE (ESF) A.C. Power
- OBalance-oi'-Plant Systems'-
Amendment No. 7 March 31, 1982 i
TABLE 15.5. 2-2 (CONTINUED)_ (Sheet 2 of 2) 1 I DISPOSITION OF NORMALLY OPERATING SYSTEMS ) r 1 (n) FOR THE PLCS MALFUNCTION WITH LOSS OF 0FF-SITE POWER o . f> ( Q O( , 4, gg o$ #3 h #o 4%3%$4'e % , 1 SYSTEM
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- 23. Non-Class lE D.C. Power * /
- 24. Class 1E D.C. Power * /
Notes:
- 1. Failure in this system is the initiating event.
I
- Balance-of-Plant Systems Amendment No. 7 March al 1o99
l l' TABLE 15. 5. 2-3__ _ UTILIZATION OF SAFETY SYSTEMS FOR THE PLCS MALFUNCTION WITH LOSS OF 0FF-SITE POWER j
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t '%, *gs, '**$ %,
% %, f
?, he%, Q 9 b, ?p o,Q e $
SYSTEM g Yg AC Fbe
- 1. Reactor Protection System /
- 2. DNBR/LPD Calculator
- 3. Engineered Safety Features Actuation Systems / !
- 4. Supplementary Protection System 1
- 5. Reactor Trip Switch Gcar /
- 6. Main Steam Safety Valves * / l l
- 7. Primary Safety Valves /
- 8. Main Steam Isolation System * /
- 9. Emergency Feedwater System *
- 10. Safety Injection System /
- 11. Shutdown Cooling System /
- 12. Atmospheric Dump Valve System * /
- 13. Containment Isolation System *
- 14. Containment Spray System *
- 15. Iodine Removal System *
- 16. Containment Combustible Gas Control System *
- 17. Diesel Generators and Support Systems * /
- 18. Component (Essential) Cooling Water System * /
- 19. Station Service Water System * /
NOTES:
- 1. Safety backup to safety system.
l I
- Balance-of-Plant Systems -
snenament No. / March 31, 1982
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15.6 DECREASE IN REACTOR COOLANT SYSTEM INVENTORY 15.6.1 INADVERTENT OPENING 0F A PRESSURIZER SAFETY / RELIEF VALVE The Inadvertent Opening of a Pressuri2er Safety Valve event as described in SRP 15.6.1 is evaluated in the Emergency Core Cooling Systems analyses (Section 6.3).
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15.6-1 Amendment No. 7 March 31,1982 l
e----_--__- . _ _ _ _ _ _ _ _ _ _
15.6.2 DOUBLE-ENDED BREAK OF A LETDOWN LINE OUTSIDE CONTAINMENT 15.6.2.1 Identification of Event and Causes l l
Direct release of reactor coolant may result from a break or leak outside containment in a letdown line, instrument line, or sample line. The double ended break of the letdown line outside containment, upstream of the letdown line control valve (DBLLOCUS) was selected for this analysis because it is the largest line and results in the largest release of reactor coolant outside the contain; rent.
The single active f ailure of an isolation valve was not considered in the analysis because the letdown line includes two isolation valves in series situated inside the containment. Hence, failure of one isolation valve does not make the consequences of the event more severe.
A letdown line break can range from a small crack in the piping to a complete double ended break. The cause of "le event may be attributed to corrosion which forms etch pits or to fatigue cracks resulting from vibration or inadequate welds.
15.6.7.2 Sequence of Events and Systems Operation A double-ended break of the letdown line outside containment, upstream of the letdown line control valve releases primary fluid to the auxiliary building at a rate of approximately 50 lbs/sec. This is more than twice the maximum expected letdown flow. The event will set off a number of alarms. Table 15.6.2.-1 lists the alarms that would be noted by the reactor operutv, 'n the control room. ,
Of the alarms listed in Table 15.6.2-1 the first three, that is, the RHX exit high temperature alarm, the letdown line low flow and low pressure alarms, and the low flow alarms in the Process Radiation Monitor and the Boronometer, are going to immediately alert the operator after the initiation of the event. The high RHX outlet temperature alarm in addition to sounding the alarm also initiates isolation of the letdown line by closing one of the two letdown line isolation valves inside the containment. However, no credit is taken for this i isolation action in the analysis. Secondly, the high temperature, high i humidity and high radiation level alarms (see Table 15.6.2-1) in the auxiliary building are expected to be triggered within a few seconds after the event initiation. Thirdly, the pressurizer low level alarms (see Table 15.6.2-1) is expected to alert the operator within one minute af ter the initiation of the event. Finally, the auxiliary building sump high level alarm and the volume control tank low level alarms (see Table 15.6.2-1) are expected to be triggered within a few minutes after the initiation of the event.
The analysis assumes that ten minutes after the first three alarms resulting !
from the DBLLOCUS the operator isolates the letdown line thereby terminating any further release of primary flow to the auxiliary building. Subsequently, l the operator is assumed to take appropriate steps for a controlled reactor shutdown. The assumption of operator action within 10 minutes after the first few alarms are triggered is based on ANS 58.8, ANSI N660, Rev. 2,1981 (" Time Response Design Criteria for Safety-Related Operator Actions"). This is the O
Amendment No. 7 15.6-2 March 31, 1982
l minimum time for the letdown line break event category that shall elapse from the time of .the alarm until operator actions can be considered for initiation of safety functions.
Table 15.6.2-2 presents a chronological sequence of events which occur following a double-ended break of the letdown line until the operator takes ;
action to terminate the primary system fluid loss 10 minutes after the ;
initiation of the event. Figure 15.0-1, which contains a glossary of symbols I and acronyms, may be used with Figure 15.6.2-1 to trace the actuation and I interactions of the systems utilized to mitigate the consequences of this event.
Table 15.6.2-3 contains a matrix which shows the extent to which normally operating plant systems are assumed to function during the letdown line break transient.
Table 15.6.2-4 contains a matrix that summarizes the utilization of the safety systems as they appear in the transient analysis.
The success paths in the Sequence of Events Diagram in Figure 15.6.2-1 are as follows:
Reactivity Control:
The operator diagnoses the event based on alarms specified in Table 15.6.2-1, and generates, a manual reactor trip after isolating the letdown line. The CEAs fall into the core to provide a negative reactivity insertion. The boron concentration is adjusted to insure that a p*oper negative reactivity shutdown margin is achieved prior to cooldown. The boron concentration is adjusted by manually controlling the CVCS.
Reactor Heat Removal:
The SCS is manually actuated when RCS temperature and pressure have been reduced to 350 F and 400 psia, respectively. This system provides sufficient cool'ng flow to cool the RCS to cold shutdown.
Secondary System Integrity:
The turbine automatically trips on the manual reactor trip. The SBCS automatically actuates and opens the steam bypass valves to dump steam to the condense. The FWCS responds to the reactor trip and generates a Reactor Trip Override signal which reduces feedwater to 5% flow. The plant cooldown is controlled by manual operation of the S3CS. The main feedwater pumps are manually controlled and continue to supply feedwater until steam flow to the condenser becomes inadequate. The operator then starts the auxiliary feedwater pump and secures the main feedwater pumps (See Applicant's SAR for details).
Primary System Integrity:
RCS level is controlled by manual operation of the charging pumps. RCS pressure is reduced by manual operation of the pressurizer spray. As the cooldown proceeds, the operator will reduce the safety injection actuation Amendment No. 7 15.6-3 March 31,1982
I setpoint to prevent the inadvertent generation of an SIAS. When the RCS pressure is reduced to approximately 650 psia, the operator will vent or drain the SITS to reduce their pressure and will then isolate them.
Control Room Habitability:
1 B0P signals may actuate control room habitability system due to the high l radiation level in the auxiliary building. See Applicant's FSAR for details.
Fuel Handling Building Habitability: l B0P signals may actuate fuel handling building habitability systems due to the high radiation level in the auxiliary building. See Applicant's FSAR for details.
Radioactive Effluent Control:
The operator diagnoses the event based on alarms listed in Table 15.6.2-1. Ten minutes after receiving the alarms, the letdown line is manually isolated.
15.6.2.3 Analysis of Effects and Consequences 15.6.2.3.1 Core and System Performance A. Mathematical Model The Nuclear Steam Supply System (NSSS) response to a double-ended break of a letdown line outside containment, upstream of the letdown line control valve, was simulated with the CESEC-II computer program described in Section 15.0.3.
The analysis assumes critical flow through the break and accounts for letdown line losses and for operation of the PPCS (Pressurizer Pressure Control System) and PLCS (Pressurizer Level Control System). The model of the letdown line break used is described in Reference 27 of Section 15.0.
B. Input Parameters and Initial Conditions Table 15.6.2-5 lists the assumptions and initial conditions used for this analysis in addition to those discussed in Section 15.0. Conditions were chosen to maximize the primary system mass release for DBLLOCUS. This, in turn, leads to the most conservative predictions of radiological releases.
The initial conditions and NSSS characteristics used in this analysis of the maximum total radiological release for the letdown line break were based on parametric studies. The parameters evaluated were initial core inlet temperature, initial power level, initial pressurizer pressure, initial core inlet flow rate, initial pressurizer liquid inventory, and break size. The maximum total mas release is obtained when the transient is initiated with the following parameters from Table 15.0-5: The maximum core power, maximum {
allowed core inlet temperature, and a low core flow. All control systems are '
assumed to be in the automatic mode to maximize the total primary mass release. The break is assumed to be the full cross sectional area (double-ended) pipe break.
O Amendment No. 7 March 31,1982 15.6-4 l
C. Results The dynamic behavior of important NSSS parameters following a DBLLOCUS are O presented in Figures 15.6.2-2 to 15.6.2-14. The decrease in the primary system mass causes the pre >surizer pressure to decrease exponentially from the initial 2400 psia to about 2230 psia at 600 seconds. During the same time period the pressurizer level decreases from an initial level of 22.1 feet above the lower tap to a new level of 10.2 feet. 1 Ten minutes into the transient the operator isolates the letdown line, terminating the release of primary fluid outside the containment. During this time period no more than 30,766 pounds of primary system fluid is released into ,
the auxiliary building. Some time shortly after the termination of the primary I system mass release, the operator manually trips the reactor. The minimum DNBR !
does not decrease below 1.65 (as calculated using the CE-1 correlation) at any j time during the transient (see Figure 15.6.2-14).
15.6.2.3.2 Radiological Consequences A. Mathematical Model i The DBLLOCUS event is indicated by several alarms l'isted in Table 15.6.2-1.
Ten minutes after the first three alarms, which take place immediately following the initiation of the event, the letdown line is isolated by the reactor operator. During this time 30,766 pounds of primary coolant is I released into the auxiliary building. l The mathematical model used to calculate the inhalation doses at the exclusion area boundary (EAB) is discussed in Section 15.0.4.
B. Assumptions and Parameters The letdown line break outside containment results in the discharge of radioactivity to. the environment. There are some uncertainties in the calculation of resultant radiation doses. These principally arise from !
uncertainties in the reactor coolant activity levels, the quantity of coolant-released, the fraction of radionuclides that become airborne, the fraction of airborne activity that escapes the auxiliary building, and meteorological conditions that exists at the time of the accident. These uncertainties are treated by taking worst case or conservative assumptions. These are:
a) The initial activity level of the primary coolant is assumed to be 4.6 Ci/gm. This correspons to the maximum equilibrium value (with 1%
failed fuel) given in the technical specifications.
b) An iodine activity spike with a spiking factor of 500 is assumed to occur coincident with the initiation of the transient.
The quantity of coolant released outside containment is maximized by assuming most adverse initial conditions and by assuming critical flow through the break.
d) The blowdown decontamination factor (DF) is assumed to be there. That is, one-third of all the iodine contained in the released primary mass Amendment No. 7 15.6-5 March 31, 1982
is assumed to be airborne. This is based on the fraction of primary fluid that flashes to steam in the auxiliary building based on the i enthalpy of the escaping fluid.
e) The auxiliary building DF is assumed to be three. That is, credit is taken for the retention within the auxiliary building and filtration system of two-thirds of all the radioactivity contained in the released primary mass.
f) Ho credit is taken for ground deposition of the activity that escapes the auxiliary building or of decay in transit to the exclusion area boundary.
g) The meteorological conditions assumed to be present at the site during ,
the course of the accident area based on X/Q values which are expected l to be conservative 95% of the time. This condition results in the i poorest values of atmospheric dispersion calculated for the exclusion area boundary or LPZ outer boundary. Furthermore, no credit has been l taken for the transit time required for activity to travel from the I point of release to the exclusion area boundary LPZ outer boundary.
Hence, the radiological consequences evaluated under these conditions areconsegvative The X/Q value conservatively assumed is 2.0 x 10- sec/M C. Results l The radiological consequences resulting from the occurrence of a postulated letdown line rupture have been conservatively analyzed using assumptions and models described in the preceding subsections. The thyroid inhalation dose has been analyzed for the 0 to 2-hour dose at the exclusion area boundary. The 2-hour thyroid inhalation dose is found to be no more than 23.7 rems.
15.6.2.4 Conclusions The double-ended break of a letdown line outside containment upstream of the letdown line control valve results in gradual depressurization of the reactor coolant system. The minimum Departure From Nucleate Boiling Ratio (DNBR) stays above the value at which the fuel pins would be calculated to experience DNB. )
l During the 600 second duration of the transient no more than 30,766 pounds of j primary system coolant is released outside the containment. This results in a two hour thyroid inhalation dose which is a small fraction of 10CFR100 guidelines. t i
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l Ol l Amendment No. 7 15.6-6 March 31, 1982 {
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TABLE 15.6.2-1
(
ALARMS THAT WILL BE I
l ACTUATED FOR THE DBLLOCUS EVENT
- 1. Regenerative Heat Exchanger high exit temperature alarm
- 2. Letdown line low flow and low pressure alarms (downstream of the break)
- 3. Letdown line component low flow alarms a) Process Radiation Monitor b) Boronometer
- 4. Auxiliary building high radiation alarm l
- 5. Auxiliary building high temperture and high humidity alarms l 1
- 6. Pressurizer low level alarm
- 7. Auxiliary building sump high level alarm
- 8. Volume control tank low level alarm l
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l Amendment No. 7 March 31, 1982 t_-_-_____ __ _ _ ____
TABLE 15.6.2-2 SEQUENCE OF EVENTS FOR A DOUBLE-ENDED BREAK OF THE LLIDOWN LINE UUISIDL CONTAINMENT UPSIREAM OF THE LETDOWN CONTROL VALVE Time Setpoint (sec) Event or Value Success Path 4 0.0 Letdown Line Rupture Occurs --
Setting Off Alarms Listed in Table 15.6.2-1 {
i 33 Third Charging Pump Starts 9" below Primary System Initial Integrity Pressurizer Level 74 Pressurizer Backup Heaters 2360 Turned On, psia 600 Operator Isolates the Letdown -- Primary Line And Takes Steps For A System Controlled Shutdown Of The Integri ty Reactor and Reactivity Control l i
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\ ' .?'vfe.Q~-h>$'Sp
'r, ,u c y , , &p
'f, 4 WQ 0,
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g, d- C- 9 , s?n Rp SYSTEM 'T 'g 'g-1
- 1. Main Feedwater Control System /
- 2. Main Feedwater Pump Turbine Control System * /
J
- 3. Turbine-Generator Control System * / l
- 4. Steam Cypass Control System /
g 5. Pressurizer Prcssure Control System /
,( f 6. Pressurizer Level Control System /
l v
?. Control Element Drive Mechanism Control System /
i 8. Reactor Regulating System / ,
1
- 9. Core Operating Limit Supervisory System / '
- 10. Reactor Coolant Punps / !
- 11. Chemical and Volume Control System /
- 12. Secondary Chemistry Centrol System * /
- 13. Condenser Evacuation System * /
l
- 14. Turbine Gland SealJna System * /
l'
- 15. Nuclear Cooling Wat'er System * /
- 16. . Turbine Cooling Water System * /
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities * / l
- 19. Circt.iating Water System * */
3
- 20. Spent Fuel Pool Cooling and Clean-Up System * /
- 21. Non-Class lE (Mon-ESF) A.C. Power * /
O
( 22. Class lE (ESF) A.C. Power
- v .
1
- Balance-of-Plant Systcms - !
L
'\
Amendment No. 7 March 31, 1982 1
TABLE 15.6.2-3 lCOllTil:UED) (Sheet 2 of 2)
_D_ISPOSITIC ; 0_F_ !:9P'1 ALLY OPERATI:iG SYSTEMS l
FOR Tl!E DOUBl.EJ E'iDED DE:'d: OF A "
LLTDOWi! LINE. OUTEILE CO:Li A i:.:'ENT ,
UPSTREA:4 UF ThE LEICO.Hi (L 'IRCL VAL'!ES l 0
%. '0 p d ,
\<,
v - .. s 6{a)
\ ' %). 'y e'Ql$Q'Q
'S~fh$^?G# <.' ':2 - '$. T'f c.v$. 0
. G; t e%. g, A<c'sc $7o ,e y,'o
, s. '$ / , Yo, 4 %
C 1 $>.f&, ^'O,e
.9 -r 'o. 'e o e SYSTEM o \
- 23. flon-Class 1E D.C. Power * /
- 24. Class 1E D.C. Power * /
O 1
1 i
l O
- Balance-of-Plant Systcms Amendment No. 7 March 31, 1982
TABLE 15.6.2-4 UTILIZ.t.TIO.'l 0F SAFETY SYSTE'iS F"0R Nli CC'R,l.ED E"D~D iOET K OF A I
,Ag L El lC_ . '."t' c" .*. , i. " ' s l '.i
"'. . 'i o' .". . " ' I T .
4 i.V 1 UPSTP,EAl1 UF THE LEiDG'.;;l LCl;iR'JL V ALVES i 9e 'd & Sp y b '9 Q Q G,Y
? hq,'b %,
% *o, ?d'o, Qy &
@ $ @ 6, ##
SYSTEM g be i 1. Reactor Protection System /
1
- 2. DNBR/t.PD Calculator
- 3. Engineered Safety Features Actuation Systems / j
- 4. Supplementary Protection Systcm
- 5. Reactor Trip Switch Gear /
- 6. Main Steam Safety Valves * /
; 7. Prim:1ry Safety Valves l
- 8. Main Steam Isolation System * /
- 9. Emergency feedwater System * /
- 10. Safety Injection System /
' 11. Shutdown Cooling Systen /
- 12. Atmospheric Dump Valve System * /
- 13. Containment Isolation System *
- 14. Containment Spray System *
- 15. Iodine Removal Systed*
- 16. Containment Combustible Gas Control System
- i 17. Diesel Generators and Support Systems *
- 18. Component (Essential) Cooling ' dater System * /
- 19. Station Service 'Jater System * /
G: .
i l==#U3lancc-o . . = = = = ,
f-Plan t Systcms -
Amendment No. 7 March 31 p 1982
TABLE 15.6.2-5 ASSUMED INPUT PARAMETERS AND INITIAL CONDITIONS FOR THE DOUBLE-ENDED BREAK OF THE LETDOWN LINE OUTSIDE CONTAINMENT UPSTEAM OF THE LETDOWN LINE CONTROL VALVE Parameters Assumed Value Core Power Level, Mwt 3876 Core Inlet Temperature, F 580 Pressurizer Pressure, psia 2400 Core Mass Flow, 106 lbm/hr 153 Pressurizer Liquid Volume, ft 3 1116 Steam Generator Pressure, psia 1206 Doppler Coeffcient Multiplier 1.15 CEA Worth at Trip,10-2Ap (most reactive CEA -10.0 fully withdrawn)
Break Size (double-ended), ft 2 0.01556 e i l
I 1
l l
O Amendment No. 7 March 31. 1982
G% < .m
$PECIFIC tyfMT LETDChN LINC BREAR OuT5!DE CONTA!VtlNT I
REACTIVITY CONTROL CR v CR RP5 CPERATOR MANUALLY OPfh1 REACTOR Rf,,N (Rit$) 4 TRIP CIRCUlf DREAKIR$ TO OC ENERG!!! ' HA3 I ng P,
. CICM kOLDING C0!L5 h0TE : GP(RAf 0R PERFCRM TH11 ACflG9 BASED ON TM( FOLLOW!:K. ALAA.*$ : (0.34 $ECS)
RfQUIRED g, RES(RAf!W( >( Af IfCM%1R VALUES:
- 350*F SE MIGM EIlf TEWERATURE.
V r$Ag g,g
- 2. LET00lN LINE LOW FLOW AMD LfAd Pet 15uRE.
CIA GWlfY INSERf!0N OF CEA's
- 3. Ltf0 Lf ME COMP 0hENT LOW FLOW ALARMS. p 3.66 $tC$ 702 90$ IN$tti!0N
- s. PR0(t$$ RA01Afl0N MCrlf f0A $J,
- b. 80R0hCH(T ER
- 4. AUI!LIARY BUl(CING HIGH RA0lAfl0N
- 6. AullLIARY SUILCI'IG HIGH T[FP(RATLR( y AND ulGH Html0lif, A
- 4. PAE550RIZER LOW LIVIL.
7, Aus!LIARY Bull 0 LNG WMP HIGH LEVEL. (TRIP)
- 4. V0LLME CONTROL TAAK LOW LEVEL.
c--__.---__1 1
1 I
i U i CR CvC$
A00 SCRCN tr REPLACING RC5 g L 9(CHARGl%)
p 4 VOLUM( $NR!nsAG( WITH SCRATED I
/2 Al8 lC hAfER 2/3 CR l
$!$ ThA0fTLt HPs! 0!sCHARGC L, '
--{> VitVES TO A00 80Refs 8f U i/, i l, Rt'tACING v0tur SaruAGE ,,,,,,,,,,,,,,,,,,,,,,
,a I
y/2 g (TOTAL A GRAVITY FIED LINE FROM $ls
$UCfl0fl LINE TO CHARGl% PUMP t
" VOLUPE)
$UCTION LINE g NOTI: TOTAL VOLUME e g ESF VOLW( +
COLD $wfDcks v0LUPE f_ (f0LUME A#AILABLE WILL DCPEND ON VOLUME LOST RWT PROVIDE WAf!R 70
([$F VOLUME) 4 HPSI PUNP $UCTI01 P
l 5.9, 449,100 9al.
l
. REACT [v IT CONTROL .
($WT00isN) s,, ,,
v
( AFJ LOS$ OF PRl*A41 Sf 5't* Fua'3 0 C .U/1 Of L(f 3M C0hf'0L VALvt 15.4 2 I
l 21ACf04 N(AT Pal f $YSTEM RINOVAL 38II, F--------r----------- i i i 6 UI 6 l _. V l M5 L8 l f p CVCS OlvtRT REQUIRfD FLOW PPCS CONTROL SP8Av5 TO l q SC5 AtlGs LP$las peg MTW CMIPS . P (CHARGING) N TO A1 Bf REGULAfl% E p ($pRAr$) y gggggg pyg pag $$ggg 4 CLO1[ LPil SUCTION TO Ref Llits, l/4 I , CHAACING CONTROL VALV( 1/4 M A e D'Em snur00m COOLING SuCflon unts ,
j 1/2 75AA 9.2. 6.3 0
) Pela 3
b ^
l
'S l ,p
, rxusi Aux. sPtav CONTROL N VALyt 70 RIGULATE P g
V I I
if, ag;0. t.___________
atr0 VAL l '
mfoown f
CR V III A
" THROTTlf NP$l OlsCHARGt (vC5 $ FART AND STOP CHARGlNG P
p 4 VALyts TO ConfROL RC5 g ,(CHARGING) PLFP5 OR *00ulATE CHARGING
/4 A ls PRt15uRg P 4 LINE BACKPR(51uRE VALVE TO
, 1/2 Al0lC MAstuP aC5 volume SHRIRKAGE I
sn 1
6 v AWT PROV10E WATER T0 HPSI P;P, (COLD 5 NUT 00m Op(s vCT ByPa$$ ging
((5F VOLUM()A UCTIONS MUMQ 4 TO C0hhtCf SAMT 015CHAact p M TO CHARGIAG PUMP SuCfl0N i,,,, u.500 sal.
nOft, Tatst sArtty runCTIONs *"0''*
an et Arci,lRio r0R -----------
131( tafAK 11111. TO I SALANCE TH( L(AKAGE. g gg
[
v as CA I PPC$ U$( NEATER 1 TO AIMUST N5 p PPC$
I p (8 AC R.up -CD RAf( Of DiCRIA1( OF P USE HEATER 5 70 A(UU$7 P
l/4 g NEAf(R$) PIA P2[15URE (PROPcR Tion 6L % AAff 0F DECREASE OF l 1/4 g HEAT 145) Pit PRL5$URE l
t L___________ s.v.
l b_____ __ _ _ .___
CA U
p ,' (SFA$ REDUCI P, $(TPolNTS TO PREvttif P GENERAfl0N OF $145 $lGMAL .
gj4 AT 100 Psia A80VI $1 A1 StTPOINT 3/4 THE PRf TRIP 'ALARA SOUND $ AND SITPolwr 11 DECREASID TO 400 Psla
$(LOW DI$flNG Pp CA 515 y , ($lT) OtPRESSURl!! Sif'$ 87 CRAlainG 6 rcs N OR vtMf!'iG AND 150LAf( THE4 A l8 Cl0 butu PRt$5uR( 15 LOW [NCUGH
/\pl3.It,13O^
J RLl EfQUIRED VALUC3: 4/4 F5AA 4.3
{- ((} 9tPAf5)uullinG-P,,,
- 62$ psta n0tm0, . P,, . 00 .. A v
PRIM. $75.
N PRE S$/ttytt
^('3erE.reh}}}C card
*M 8904040456-33 Amendment No. 7 March 31, 1982 C-E / SEQUENCE OF EVENTS DIAGRAM Figure FOR DOUBLE-ENDED LETDOUN LINE BREAK,
[lNS. OUTSIDE CONTAINMENT, UPSTREAM OF LETDOWN CONTROL VALVE 15 2
7
*% m SECDMCAAY 5YSTEM INTEGAITT
- - - _ q l
i V
A '
I#" * 'sg" PowtR BuvR -{> GEntufE5 fr5 0
($FAS 4 GENERA A l8 lC lD Opt 4Af0a mANUAtty Ta!P5 FUR 8tNE [F [T. 5Ja 820 psia P,gt 2/4 psAn y,3 OCES NOT TRIP OM REACTOR TRIP 0 u A l CLOSE TUR8!';E STOP AND I TT5 -{> TGC5 A ADMISSION VALVE 5 CLOSE -
( 3 SEC.] M515 MSI 4 AND M5 t/2 , l, REF. 5.10.2 2/2 g REF. 5.10.3 1
- - - - - - - - - - - - _ - _ , s ALTERMATE PATM IF $8CS 15 l'ICPERATIVE g NOTE: 2/2 REFER $ S(
OR in PMuAL Mo0E I STEAM s i i 5 uiv.tatal 5/Sc.:
F,, Psh . U l l A 51NGLE M58 P,T "
p eve $8C5 REGLtATE T11RBINE g I
_.D 8v/A55 VALVE 5 l COWNm AVAILABLg Al,lcl0El,lqlH l 4 l NOTE: A THRU M IMPLIE5 EIGHT l ggy gg 8/8 FSAA 5.1 Q(3 8y[7,**1 7g P,,H M55V 4 VD REF. 5,10.4 l
,' rs= i0.3.5.5 4
- 3. P. : 2-1782 psta. 21318 psta, g int p55V'S HAVE TWC .
01346 psia FAILURE TO OPEN AMD i D
ggg R5 FSAA 5.5 I ONE ACTIVE FAl LUR g
RTO CLOSES EFCV. AOMST5 0FCV AMD l R FWC5 A FEEDufER PtMP SPEED TO PROVIDE I g
4 lia FEECMTER FILl 2/2 F5Ah 1.7 AP H 4 GENERATE j L"2L 8/*
Al8lCl0 j
- 5. P. : 150 ps td 5.P. : 255 V
ns g J 1
CH -> MIN FEtDWATER SOURCE ,
P l FSAA 10.1,10.4 2-1" E5F AS REF. 5,101,10.4 sg Lsgil 2/4 Al8lCl0
- 5. P. : 150 psid I 5.P. : 255 FSAR 7.3 1
1 i s,i . ;
"5 INITIATE HLO TO RESPECTIVE SG IA 3 II."
4 FWC5 A TO PREVE9? OVERFEEDING .
CLO5E DFCY EF AS-1 I/2 g
" 8 d START EME EFNS i
l L
192 2/2 4 QPI" (w(
VALVE 5 70 l i
l A y 8 3G OLOWDCW I
EFA5-2 1/2 REF. 5.10.4.7.3 E
1/2 l ]
sg!
l "i I REMOVE HLO WEN LEVEL DECREASES y FWC5 - BELOW INITI ATION LEVEL M14L5 A I SMALL DEAD BAMD
- OPEN CFCV TD g A 8 pyg.HLO LEVEL i
L sg2 EI*
f A C57 4 EMERGENCY
[0 '
5.F. ,, aEF. 5.10.4,9.2 ]
%. g a
__ ___-__._-_-____ _ O
6 -
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INNT A - WITHDRAW UA$-2 A$
' eg$ '
' RIQUIRED ESTA5
$.P.t 41$ 4 --> INNT 8 Al0lC l 0 yN[y uA$ 2 As
; F5AA 7.3 q
' N l sg2 2/4 TV'$. OFlV'$. (FIV'S l
$([ A80VE FDA StfPOINTS l
sg!" gj4
' fut 150laf10m 0F fWo IMMIT A - WITHDRAW EFAs.1 A$
5.P, st$ E5FA$ REQUIRED If 5 56 0 t 5 '
Al 8 Cl0 E F5AA 7.3 I
at P E ION NCClublY ST5fLM ,
l l
$tt AROV( FOR stTP0lNTS {
g .
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, l, AS$0CIATED SG A$ REQu D
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vr ' in. 5. i0.4.7.3 j ns.: , ;
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Also Available On Aperture Card
[E!'rll0'3"EDh, l ggrio a Ano isours q l
89 04 0 4 0 4 5 6-3Y ;
Amendment No. 7 UE0t1AflR $(%9CE March 31, 1982 1
C-E f SEQUENCE OF EVEllTS DIAGRAM Figure l FOR DOUBLE-ENDED LETDOW1 LIllE Br.AK, 15.6.2 l S b hS; . OUTSIDE CONTAINMENT, UPSTREAM OF LETD0 f. CONTROL VALVE
-1B l
i _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ . _
7 1
%: ,L,.
S f 1
4 1 V
's' f' fd 7 MS SUPPtf MTER TO STEM M N ---(> GINtRATOR($) FOR C00tDCWN I
A g 0F RCS Legge Leg 2 2/2 FSAR 7.7 g
_____________.J V
N3 CH -- 'a-{> MAls Ft[0kAT[A SOURCE P
4 F$AR 10.1.10.4 P sg A!F 5.10.1.10.4 U
h5
[
gggrgg q{g (ggDgT(A PUMPS x1 FWC$ gy 200 psia ABOV( M$l$ $ffP01NT i M 4 W4EN STEM FLOW l$ INSUFFICIENT AN ALARM l$ $0UNDED AND THE TO DRIVE YURB14($
stTPolNT !$ DECREASED 200 psis A 9 BELOW III$ TING P,9 2/2 FSAR 7.7
_____q -
CR l si hs DUPP $ftM TO CCNDit$IR I
p 9 --D9 SOCS 70 CtxtXht RCS un'!L 4 $HL'TWi COOLI'iG (NTM g l k 7,g COND!tlCNS ARE REACHED }
AlBlCh tl7lG)H COM0(NS(R AVAILABLL gjg pggg 7,y, jg,4 f N07t: A THRU N l#PLl($ (IGHT TUR$!NEl BVPAl$ VALV[$. [ACH s 75 CAPACITY I I l
89 IRAP STE AM TO ATMCSPHERE P A50$ TO C00LDohs RCS UNT!L SHUT'acWN 8 4 4 ""-C> C00Li'tG [NTRT CONDIllan$ ARE (
T eve Al6lCl0 REACHED j i
1/41 F$AR 7.4.10.3 I NOTE: THERE ARE TWO ADV'$ i l FOR (ACH STEAM GENERATOR l
l '
. _ _ _ _f 1
.q l l l
1 i
I j l A CA O PROVIDE FLEC'aAfta 70 STIAM EFWS
- GENERATOR ($) TO C00LDCw18 RC1 l
sg U$lMG BOTH MOTDR & STEAM l A lB ORIVEM PUMP 1 l 1/2 EEF. 5.10.4 CR U A l g
j n$ START AuIILIARY Fl!DwAT[R PUPP.
OPEN AullLIARY FttCwATER ISCLATION I l
ag
"$ VALVES. $UPPLY WATER 70 STEAM i l 4 l i
GENERATOR ($) FOR C00LDOWN OF pC$ g i
AEF. 6.10.4 g E8 CR b
SECUnt $7 TAM ORIVEN PLMP -
WHEN STEAM FLCW I$ NO LONGER sg E sg IINI N AVAILABLE. USE MOTOR OdIVEN i N PUMP AND CONTROL OF EFW j ISOLATION VALVES TO MAINTAIN i 1/1 R(F . 5. 10. 4
"'I' "" *
- l
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I
______________-______-_--___-______--___.__O
EF ROL hA 7 FE!DWATER 30uRCg
' REF. 8.10.4 b Y CR CVCS OPtRATOR CLO5t$ LET0mm 4[ ) ,
2 A Il I SUILDING 4 REDUCI P,, SITPolNTS 70 PRIVENT GENERAfl0N OF M513 SIGNAL .I (C l 0 4 V
D fu OL N 1
' U I. AEGENERAT!vt utAt (IchAEEA MIGH EXIT TEMPERAtyAE, E5 E.
J. (0 LINE CmPONENT lgs FLOW t ="r"#"" "*""
- 4. AUXILIARY BUILDING NIGH RADIATION
- 5. MIL Y8 HIGH TEMPERATURE
- 6. PRES $URIZER LOW LEVEL.
- 7. AUXILIARY BUILDING 5 UMP MIGH LEVEL.
- 8. ValME CONTROL TANK LOW LEVEL, 1
SI APERTURE CARD ,
Also Available On Aperture Card 1
l, 8904040456.-3 7 j i
i 1
Amendment No. 7 March 31, 1982 C-E p/ SEQUENCE OF EVENTS DIAGRAM Figure FOR DOUBLE-ErlDED LETDOWil LINE BREAK, 1 .2 OUTSIDE CONTAINMENT, UPSTREAM 0F LETDOWN CONTROL VALVE rNS.E.'5_.h
,s
{ 120 ., , , , ,
100 - _
a.
d 80 - -
2 y60 - _
u cz
- a. 40 - -
U 8
20 - _
' ' I i i 0
0 100 200 300 ~400 500 600 TIME, SECONDS Amendment No. 7-March 31, 1982 C-E OUTSIDE CONTAINMENT rigor, LETDOWN LINE UPSTREAM 0F LETDOW BREAK, N LINE CONTROL VALVE 15*6 2 -2 CORE POWER vs TIME
120 i i i i i e
g 100 - -
2 d
2 1 8 80 - -
sx l 55 i Mb 1 ts I 60 - -
1 58 a4 i
1 r\ C" ^
U 6h x
g 40 - -
g ]
W u
o 20 - -
1 0 i I ' ' '
0 100 200 300 400 500 600 TIME, SECONDS Amendment No. 7
. T March 31, 1982 C-E LETDOWN LINE BREAK OUTSIDE CONTAINMENT, Figure UPSTREAM OF LETDOWA LINE CONTROL VALVE S CORE AVERAGE HEAT FLUX vs TIME 15.6.2-3
~
i O 2500 , , . . .
l l
2400 -
g 23M - -
E d'
8 2200 - -
m E
a.
$2100 - -
E2 O a O
g 2000 1
1900 -
1800 I ' ' ' '
0 100 200 300 400 500 600 TIME, SECONDS Amendment No. 7 March 31,1982 C-E LETDOWN LINE BREAK OUTSIDE CONTAINMENT Figure UPSTREAM 0F LETDOW,N LINE CONTROL VALVES, S PRESSURIZER PRESSURE vs TIME 15.6.2-4
\
680 i i ' '
MO - -
d k M0 OUTLET g - -
W s ,
W s
Z 620 - -
$ AVERAGE O i 8 600 - _
l INLET 580
' ' i i '
560 0 100 200 300 400 500 600 TIME, SECONDS Amendment No. 7 O C-E LETDOWN LINE BREAK OUTSIDE CONTAINMENT' March 31, 1982 Figure UPSTREAM 0F LETDOWN LINE CONTROL VALVE E CORE COOLANT TEMPERATURES vs TIME 15.6.2-5
4 O 1400 , , , , ,
1300 - -
l E l g 1200 - -
5 a
u I1100 - _
f2 O
- 5 g 1000 - -
b:'
w
\
900 - -
' 800 i i i i I 0 100 200 300 400 500 600 TIME, SECONDS Amendment No. 7 l
O C-E LETDOWN LINE BREAK OUTSIDE CONTAINMENT, March 31,1982 r;8u,,
UPSTREAM 0F LETDOWN LINE CONTROL VALVE S S1EAM GENERATOR PRESSURE vs TIME 1162-6
l 1
45.0 , , , i i
$37.5 - -
q
- a 1
at S 30.0 - -
I Pn E
22.5 - -
8 u
O D
$15.0 - -
E a.
O W
$ 7.5 - -
0.0 0 100 200 300 400 500 600 TIME, SECONDS 1
O C-E Amendment No. 7 March 31, 1982 ETDOWN LINE BREAK OUTSIDE CONTAINMENT, rigur.
UPSTREAM 0F LETDOWN LINE CONTROL VALVE S INTEGRATED PRIMARY C00lANT DISCHARGE vs TIME 15.6.2-7
f} 24 i i i i i 20 - -
i l
s u_
16 - ~~
.2 W
'._5 x
b!
g 12 - -
x N
O E g8 -
e o_
4 -
0 I ' ' ' '
O 100 200 300 400 500 600 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E OUTSIDE CONTAINMENT Figure LETDOWN UPSTREAM OFLINE LETDOBREAK,WN LINE CONTROL VAL
- 15. 6.2~8 PRESSURIZER WATER LEVEL vs TIME
O 560 i .i i i i s 540 - -
d520 o
W E
s 500 - -
b m
O m
@480 8
x 0
o 25 460 -
x 440 ' ' ' ' '
0 100 200 300 400 500 600 TIME, . SECONDS Amendment No. 7 St March 31, 1982 J
CE LETDOWN LINE BREAK = OUTSIDE CONTAINMENT, Figure UPSTREAM OF IfTDOWN LINE CONTROL VALVE REACTOR COOLANT SYSTEM INVENTORY vs TIME 15.6.2-9
(O/ __
I i s. i 3 1
35 -
b W 28 - _
b e
W
$ I x 21 - _ r g '
O !5 I
g 14 W
w 1
7 l
I I i i i 0
0 100 200 300 400 500 600 TIME, SECONDS Amendment No. 7 March 31, 1982 i
C-E LETDOWN LINE BREAK OUTSIDE CONTAINMENT' F""
UPSTREAM OF LETDOWN LINE CONTROL VALVE g STEAM GENERATOR WATER LEVEL vs TIME 15.6.2-10
R i
O :
3000 , i i i i ,
8 10 2500 - -
5 a
x' 12
;lE 2000 - -
E o
- E h1500 - -
O x Ed 1000 - -
3 M
a f500 0 i i i i i 0 100 200 300 400- 500 600 TIME, SECONDS Amendment No. 7-O Ma rch ~ 31, 1982 U I C-E LETDOWN LINE BREAK OUTSIDE CONTAINMENT, Figure UP STREAM OF LETDOWN LINE CONTROL VALVE TOTAL STEAM FLOW vs TIME 15.6 .2 - 1 1
i f%
b 3000 , , , , ,
S 2500 - _
m E l e'
@2000 e
W u
- s
< 1500 - _ ,
W m
i
)
3 !
S 1000 -
l
' i i
e W
h500 l
0 i i i i i 0 100 200 300 400 500 600 TIME, SECONDS g] Amendment No. 7
( March ll, lQR2 C-E , OUTSIDE CONTAINMENT rigure LETDOWN UP STREAM 0FLINE LETDOBREAK,WN LINE CONTROL VALV SEEP 8 // FEEDWATER FLOW vs TIME 15.6. 2 - 1 2
___.----.-_-_---a
1 O
LJ ;i 600 , , , , ,
500 -
i
- E
$400 - -
E2 co d
d300 -
iE z
h200 -
ti! .
100 -
0 i I ' ' i 0 100 200 300 400 500 600 TIME, SECONDS Amendment No. 7 '
Ma rch . 31, 1982 c-t LETDOWN LINE BREAK OUTSIDE CONTAINMENT Figure S UPSTREAM 0F LETDdWN LINE CONTROL VALVf FEEDWATER ENTHALPY vs TIME . 5.6. 2-B
O 3.0 , , i i i l
I I
2.0 - -
E E -
E
- E E i O 5 i
- 1. 0 -
i 1
i 0 ' ' ' i 8 0 100 200 300 400- 500 600 TIME, SECONDS ,
1 O C-E o":"g* ' vn,'
LETDOWN LINE BREAK OUTSIDE CONTAINMENT, Figure UPSTREAM 0F LETDONN LINE CONTROL VALVE S MINIMUM DNBR vs TIME 5.6.2-14 .
E-_---------------------------------- - -
15.6.3.2.3 Analysis of Effects and Consequences A
'd 15.6.3.2.3.1 Core and System Performance A. Mathematical Model The mathematical model used for evaluation of core and system performance 10 i is identical to that described in Section 15.6.3.1.3.1.
B. Input Parameters and Initial Conditions The input parameters and initial conditions used for the evaluation of core and systems performance are similar to those described in Section i 15.6.3.1.3 and are given in Table 15.6.3-9. Both the initial core mass flow rates and the one pin radial peaking factor were chosen to:
(1) maximize the primary-to-secondary integrated leak, and the steam ;
releases through the main steam safety valves, and (2) at the same time, obtain a simultaneous reactor trip on a low DNBR (=1.19) as well as a low pressurizer pressure. Consequently, a slightly lower core mass flow rate (104% instead of 116%) as well as a slightly lower radial peaking factor (1.53 instead of 1.55) were employed in the analysis.
C. Results l The dynamic behavior of important NSSS parameters following a steam generator tube rupture with a loss of normal ac power are presented in Figures 15.6.3-19 through 15.6.3-34.
A)
+
'v Prior to reactor trip, the dynamic behavior of the NSSS following a I
i steam generator tube rupture with a loss of offsite power is similar l to that following a steam generator tube rupture without a-loss of offsite power which is described in Section 15.6.3.1.3. At 1186.75 seconds after the initiation of the tube rupture a reactor trip signal 10 is generated due to exceeding the CPC low pressure boNdary.
Subsequent to the reactor trip, the RCS pressure begins to decrease rapidly, and the pressurizer empties at about 1201 seconds due to the continued primary-to-secondary leak. After the pressurizer empties, the reactor vessel upper head begins to behave like e pressurizer and controls the RCS pressure respon:e. Due to the loss of offsite power, the reactor coolant pumps begin to coast down reducing the core coolant flow rate, and the mass flow into the upper head r2gion. This region becomes therma 1 hydraulically decoupiad from the rest of the RCS, and due to flashing caused by the depressurization and boiloff from the metal structure to coolant heat transfer, voids form in this region at about 1196 seconds. The void formation is enhanced by the decoupling effect, since the RCS pressure reduction due to primary system cooling is felt in this region, while the RCS temperature reduction is not. The significant impact of voids in the upper head ragion is a slower RCS pressure decay resultin actuation signal (SIAS)g at in the generation 1563.2 of the seconds and the safety injection initiation of the 10 v
15.6-7 Amendment No. 10 June 28, 1985
The sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event. All actions required to stabilize the plant and perform the required repairs are not described here.
The sequence of events and systems operations described below represents '
the way in which the plant was assumed to respond to the event initiator.
Many plant responses are possible. However, certain responses are limiting with respect to the acceptance guidelines for this section. Of the limiting responses, the most likely one to be followed was selected.
Table 15.6.3-2 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the course of the event.
Table 15.6.3-3.contains a matrix that summarizes the utilization of safety systems as they appear in the transient analyses.
The success paths in the Sequence of Events Dagram (Figure 15.6.3-1) are as follows:
Reactivity Control:
The pressurizer pressure decrease results in the generation of a CPC low pressure boundary trip and the CEAs drop into the core. Subsequently, the RCS pressure decreases more rapidly and a Safety Injection Actuation Signal (SIAS) is generated on low pressurizer pressure. As a result, additional negative reactivity is added to the system, in the form of borated water from the refueling water tank. Once the plant parameters have been stabilized, the operator adjusts the boron concentration to insure that a proper negative reactivity shutdown margin is achieved prior to cooldown. The boron concentra-tion is adjusted by manually throttling the HPSI discharge valves to replace RCS volume shrinkage.
Reactor Heat Removal:
During the initial part of the transient, reactor heat removal is accomplished in the normal manner. Additional cooling capability is available through the injection of relatively low enthalpy RWT water, on the generation of the SIAS. On the initiation of the cooldown phase, the operator secures the Reactor Coolant Pumps (RCPs) in the loop associated with the affected j steam generator to minimize heat transfer to the generator. Following the i cooldown phase, the Shutdown Cooling System (SCS) is manually actuated when {'
RCS temperature and pressure have been reduced to 350 F and 400 psia, respectively. This system provides sufficient cooling flow to cool the RCS to cold shutdown. )
i Primary System Integrity:
Prior to initiating cooldown procedures, the operator must reestablish the pressurizer water level. During the cooldown phase, the HPSI pump discharge valves are throttled to control RCS pressure.
i When the RCS pressure has been reduced to approximately 650 psia, the '
operator will vent or drain the SITS to reduce their pressure and will then isolate them.
Amendment No. 7 15.6-8 March 31,1982 L_
)
Secondary System Integrity:
Following the generation of a turbine trip on reactor trip, the Main Feedwater O Control System (FWCS) enters the Reactor Trip Override.(RTO) mode and reduces main feedwater flow to 5% of nominal full power flow. Since the Steam Bypass Control System (SBCS) is assumed to be in manual mode with all bypass valves closed, the Main Steam Safety Valves (MSSVs) open to limit secondary system pressure there by removing the heat generated and/or stored in the core and the RCS. Following closure of the MSSVs, the FWCS is prevented from over-feeding the steam generators by the High Level Override (HLO) which terminates feedwater flow until the steam generator level decreases to its nominal value. Due to the primary-to-secondary flow, the main feedwater flow to the affected steam generator is terminated.
before that of the unaffected steam generator. This time difference may be used by the operator to identify the affected steam generator. Once this has been accomplished, the operator will manually isolate the damaged steam generator and will initiate cooldown using main feedwater, the SBCS, and the unaffected steam generator.
When steam pressure decreases to a' point where the main feedwater pump can no longer be used, the operator secures the main pumps. Cooldown is continued by utilizing one feedwater pump designated as " auxiliary" and intended for normal startup and shutdown of the plant in conjunction with the SBCS. The operator may let the ESFAS regulate the feedwater flow by issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions.
See Applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater Systems. .
Radioactive Effluent Control:
A Containment Isolation Actuation Signal (CIAS) is generated subsequent to )
the SIAS. CIAS isolates various systems to reduce or terminate radioactive '
releases. CIAS actuates primary and containment isolation equipment.
Other actions may be initiated by B0P systems. See Applicant's FSAR for details.
Upon identification of the affected steam generator, the operator isolates the steam generator and shuts off the reactor coolant pumps in that loop to minimize release from the affected generator.
15.6.3.1.3 Analysis of Effects and Consequences 15.6.3.1.3.1 Core and System Performance A. Mathematical Model The thermalhydraulic response of the Nuclear Steam Supply System (NSSS) to the steam generator tube rupture without a concurrent loss !
of offsite power was simulated using the CESEC III computer program 1 described in Reference 27. The thermal margin on DNBR in the reactor core was determined using the TORC computer program described in Section 15.0.3 (Refer ence 18) with the CE-1 critical heat flux correlation described in CENPD-162 (Reference 19).
k Amendment No. 7 March 31, 1982 15.6-9
B. Input Parameters and Initial Conditions The initial c,nditions and parameters assumed in the analyses of the system response te a steam generator tube rupture without a concurrent loss of offsite power are listed in Table 15.6.3-4. Additional discussion on the inpJt parameters and the initial conditions are provided in Section 16.0. Conditions were chosen to maximize the primary to secondary mass releases during the SGTR transient. This, in turn, leads to the most conservative predictions of radiological releases.
The initial reactor operating conditions were varied over the operating space given in Table 15.0-5 to determine the set of conditions which would produce the most adverse consequences following a steam generator tube rupture without a concurrent loss of normal ac power. Various combinations of initial operating conditions were considered. These included, initial core inlet temperature, initial power level, initial RC5 pressure, initial core coolant flow rate, initial pressurizer liquid level, initial steam generator liquid level, and fuel rod gap thermal conductivity. A scram reactivity consistent with the axial power distribution was employed in the parametric studies. Decreasing the initial core inlet temperature increases the primary to secondary leak rate and integrated leak, but reduces the releases via the main steam safety valves. Since the steam generator pressure and temperature would be initialized at lower values compatible with the lower core inlet temperature, the steam generator pressure may not increase enough to challenge the main steam safety valves. Decreasing the RCS pressure hastens the low pressurizer pressure reactor trip and results in lower releases due to a lower leak rate. Increasing the core inlet flowrate results in a lower enthalpy for the fluid entering the steam generator, resultant increased leak rate, and higher releases from the main steam safety valves. Thus, the parametric studies indicated that ,
the maximum total mass release is obtained when the transient is initiated l with the maximum allowed RCS pressure, maximum initial pressurizer j liquid volume, maximum initial steam generator liquid volume, maximum l core power, maximum core coolant flow, nominal core coolant inlet I temperature, and a low fuel rod gap thermal conductivity.
The radiological consequences for the SGTR transient is also dependent on the break size. For break sizes resulting in a reactor trip during the first 30 minutes of the accident, the initial leak rate decreases from that value. equivalent to a double-ended rupture, and the offsite dose also decreases due to the drop in the integrated leak. The decrease in break size also delays the time of reactor trip. As the break size is decreased further, the integral leak is reduced for the 30-minute operator action interval and the radiological consequences will be less severe. Therefore the most adverse break size is the largest assumed break of a full double ended rupture of a steam generator tube.
C. Results The dynamic behavior of important NSSS parameters following a steam generator tube rupture is presented in Figures 15.6.3-2 to 15.6.3-17.
Amendment No. 7 15.6-10 March 31,1982
v
,- For a double-ended rupture, the primary to secondary leak rate exceeds the
/ \ capacity of the charging pumps. As a result, the pressurizer pressure !
( gradually decreases from an initial value of 2400 psia. The primary to secondary leak rate and drop in pressurizer water level causes the third CVCS charging pump to turn on. Even with all three CVCS charging pumps on line the l pressurizer pressure and level continue to drop. This results in the pressurizer heaters being de-energized at 560 seconds. At 1148.3 seconds a l10 reactor trip signal is generated due to exceeding the CPC low pressure boundary. The pressurizer empties at approximately 1151 seconds. At 1181.8 10 )
seconds a safety injection actuation signal is generated, and the safety injection flow is initiated. After the pressurizer empties, the reactor ,
vessel upper head begins to behave like a pressurizer, and controls the !
reactor coolant system pressure until the pressurizer begins to refill at approximately 1447 seconds. Due to flashing caused by the depressurization, and the boiloff due to metal structure to coolant heat transfer, small amounts of voids form in the reactor vessel upper head at about 1151 seconds.
Consequently, the RCS pressure begins to decay at a lower rate at this time.
However, under the combined action of safety injection and charging flows, and reduced primary to secondary leakage, the upper head voids completely collapse '
at about 1447 seconds. Prior to this time, the RCS pressure begins to slowly increase helping to collapse the reactor vessel upper head voids. The I pressurizer water level is reestablished at about the same time due to the net j mass influx which increase the RCS inventory. j i
Following reactor trip and with turbine bypass assumed to be unavailable ]
(i.e., in the manual mode), the main steam system pressure increases until the j (q main steam safety valves open at 1209 seconds to control the main steam system pressure. A maximum main steam system pressure of 1283 psia occurs at 0.1 seconds after the MSSVs open. Subsequent to this peak in the pressure, the j
l '
nain steam system pressure decreases, resulting in the closure of the main steam safety valves at 1316 seconds.
- Prior to reactor trip, the feedwater control system is assumed to be in the j autcmatic mode and supplies feedwater to the steam generators such that steam j generator water levels are maintained. Following reactor trip, the feedwater :!
flow decreases to approximately 5% of the full power flow rate. Since the steam flow out of the steam generators is less than this feedwater flow, the ,
liquid inventory in the steam generators gradually increases. At 1690 seconds a HLO mode terminates feedwater flow to the damaged steam generator. At 1778 l seconds a HL0 mode terminates feedwater flow to the intact steam generator. ;
i After 1800 seconds, the operator identifies and isolate the aff' cted e steam generator by closing the main steam isolation valves and by securing the i reactor coolant pumps in the affected loop. The operator then initiates an l orderly cooldown via the steam bypass system and the condenser, and with j manually-controlled feedwater flow to the unaffected steam generator. After !'
the pressure and temperature of the reactor coolant are reduced to 400 psia and 350 F respectively, the operator activates the shutdown cooling system and isolates the unaffected steam generator, n
15.6-11 Amendment No. 10 June 28, 1985
. 1 t
The maximum RCS and secondary pressures do not exceed 110% of design pressure following a steam generator tube rupture event without concurrent ,
loss of offsite power, thus, assuring the integrity of the RCS and {
main steam system. The minimum DNBR of 1.22 indicates no violation of J the fuel thermal limits (see Figure 15.6.3-17 ).
Figure 15.6.3-12 gives the main steam safety valve integrated flow versus time for the steam generator tube rupture event without concurrent loss of offsite power. At 1800 seconds, when operator action is assumed, no more than 6617 lbm of steam from the damaged steam generator and 6609 lbm from the intact steam generator are discharged via the main steam safety valves. Also, during the same time period, approximately 75,275 lbm of primary system fluid is leaked to the damaged steam generator. Subsequently, the operator begins a plant cooldown at the technical specification cooldown rate (100 F/hr) using the intact steam generator, the steam bypass system, the feedwater system, and the condenser. For the first twg hours following the initiation of the event, a total of 6.516 x 10 lbm (5.58 x 10 lbm) through the turbine and 936,000 lbm through the bypass system) of steam flows to the condenser from the steam generator. For the two to eight hour cooldown period, an additional 907,000 lbm of steam is discharged through the bypass system.
15.6.3.1.3.2 Radiological Consequences A. Physical Model The evaluation of the radiological consequences of a postulated steam generator tube rupture without a coincident loss of offsite power assumes a complete severance of a single steam generator tube while the reactor is operating at full rated power. Occurrence of the accident leads to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result of low pressurizer pressure at approxi-mately 1148 seconds after the event initiation. The reactor trip automatically trips the turbine.
Subsequent to reactor trip the steam generator pressure will increase rapidly, resulting in steam discharge as well as activity release through the main steam safety valves. Venting from the affected steam generator, i.e., the steam generator which experiences tube rupture, continues until the secondary system pressure is below the main steam safety valve setpoint. At this time, the affected steam generator is effectively isolated and, thereafter, no steam or activity is assumed to be released from the affected steam generator. After 1800 seconds the operator initiates a plant cooldown at the technical specification cooldown rate (100 F/hr) using the unaffected steam generator, steam bypass system, feedwater system, and the condenser.
The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondary system activity as well as primary system activity leaked from the tube break. The inventory of iodine and noble gas fission product activity Amendment No. 7 15.6-12 March 31,1982
j l
available.for release to the environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in A) '
s the core, and the mass of steam discharged to the environment.
tive assumptions are made for all these parameters.
Conserva- 1 B. Assumptions and Conditions The following assumptions and parameters are employed to determine the activity releases and offsite doses for a steam generator tube rupture (SGTR).
- 1. Accident doses are calculated for two different assumptions: (a) assumes a generated iodine spike (GIS) coincident with the initia- l tion of the event and (b) assumes a pre-accident iodine spike (PIS).
- 2. Technical specification limits are employed in the dose calculations for the primary system (4.6 pCi/gm) and secondary system (0.1 pCi/gm) activity concentrations. I
)
- 3. Following the accident, no additional steam and radioactivity are !
released to the environment when the shutdown cooling system is l placed in operation.
- 4. Thirty minutes af ter the accident, the af fected steam generator i.s isolated by the operator. No steam and fission products I I
activities are released from the affected steam generator thereafter.
t
( 5. A spiking factor of 500 is employed for the event generated j iodine spiking (GIS) calculations.
- 6. For the pre-accident iodine spiking (PIS) condition, the technical
)
specification limit (60 pCi/gm) for the primary system activity concentration is employed.
- 7. Techr.ical specification limit (1 gpm) for the tube leakage in the unaffected steam generator is assumed for the duration of the transient.
- 8. Steam jet air ejector release is assumed throughout the transient with a decontamination factor (DF) of 100.
- 9. A fraction of the iodine in the primary-to-secondary leak is !
assumed to be immediately airborne, if a path is available, with a partition coefficient of 1 (Maximum fraction ~ 5%). l
- 10. A partition coefficient of 100 is assumed between the steam generator water and steam phases.
- 11. The total amount of primary-to-secondary leakage through the rupture is 75,275 lbm.
6 O 12. The two hour steam flow to the condenser is 6.516 x 10 lbm, and an additional 907,000 lbm of steam flows to the condenser during the two to eight hour time period.
15.6-13 Amendment No. 7 March 31, 1982
- 13. Theatmgspherigdispersionfactorsemployedintheanalysesage:
2xlg sec/m for the exclusion area boundary and 1.5 x 10 sec/m for the low population zone.
C. Mathematical Model The mathematical model employed to analyze the activity released during the course of the transient is described in Section 15.0.4.
D. Results The two-hour exclusion area boundary (EAB) inhalation doses and the eight-hour low population zone (LPZ) bounoary inhalation doses for both the generated iodine spike (GIS) and the pre-existing iodine spike (PIS) are presented in Table 15.6.3-5. The calculated EAB and LPZ doses are well within the acceptance criteria, 15.6.3.1.4 Conclusions The radiological releases calculated for the SGTR event without a concurrent i loss of offsite power are well within the 10CFR100 guidelines. The RCS and secondary system pressures are well below 110% of the design pressure limits, thus, assuring the integrity of these systems. Additionally, no violation of the fuel thermal limits occurs, since the minimum DNR remains above the 1.19 value throughout the duration of the event.
The plant is maintained in a stable condition due to automatic actions, and af ter thirty minutes, the operator employs the plant emergency procedure for the steam generator tube rupture event to cool down the plant to shutdown '
cooling entry conditions.
l l
I i
O Amendment No. 7 l 15.6-14 March 31, 1982
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15.6.3.2 Steam Generator Tube Rupture With a Concurrent Loss of
. ,.m Offsite Power
( )
(f 15.6.3.2.1 Identification of Event and Causes The significance of a steam generator tube rupture accident is described in Section 15.6.3.1.1. As a result of the loss of normal ac power, electrical i power would be unavailable for the station auxiliaries such as the reactor coolant pumps, and the main feedwater pumps. Under such circumstances the plant would experience a loss of load, normal feedwater flow, forced reactor l coolant flow, condenser vacuum, and steam generator blowdown system. The loss of offsite power subsequent to the time of reactor trip and turbine /
generator trip-is assumed in the analysis, since it produces the most ,
adverse effect on the radiological releases. The plant is operating at ]
full power for a period of approximately 20 minutes before the consequences !
of the primary-to-secondary leak cause the reactor trip. Thus, during this time period the radioactivity concentration in the steam generator increases before the main steam safety valves open, releasing radioactive materials to the atmosphere.
15.6.3.2.2 Sequence of. Events and Systems Operation Table 15.6.3-6 presents a chronological list of events which occur during the steam generator tube rupture event with a loss of offsite' power, from the time of double ended rupture of a steam generator U-tube to the attainment of cold shutdown canditions. The corresponding success paths are given in the sequence of events diagram (SED), Figure 15.6.3-18. The SED may be g used together with Figure 15.0-1 (containing a glossary of SED symbols and acronyms) to trace the actuation and interaction of the systems used to mitigate the consequences of this event. Additionally, Table 15.6.3-7 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the course of the event. The utilization of safety systems as they appear in the transient analysis is summarized by the matrix contained in Table 15.6.3-8.
Prior to reactor trip, the systems and reactor operation are identical to that described in Section 15.6.3.1.2. As a result of the reactor trip, the turbine / generator trips within one second after 'he CPC low pressure boundary reactor trip signal. Subsequently, offsite power is assumed to be lost due l to grid instability. A 3 second delay between the time of turbine trip and the time of loss of offsite power is conservatively assumed in the analysis, based on the discussion that follows. j The loss of a power generating unit causes frequency deviations in the i electical power grid which normally operates at 60 Hz. Under certain ,
conditions the resulting grid instability will cause loss of offsite power j to that unit. The degree of instability is characterized by the rate of I grid frequency degradation which is dependent on the magnitude of the load 1 mismatch and the physical parameters of the grid. The physical response of the grid is dependent on the available spinning reserve and the stiffness of the grid, i.e., the ability to damp out frequency oscillations through load damping. Load shedding is also utilized to restore the balance between l load and power generation and to return the grid frequency to 60 Hz. When the corrective action is not sufficient to avert frequency degradation, loss of off-site power to the plant can occur as a result of 15.6-15 Amendment No. 7 March 31, 1982 i
l l
that plant tripping of f line. Most plants are automatically disconnected I from the grid between 56-58 Hz, to prevent underfrequency damage to the 1 plant components. For System 80 plants, a frequency of 57.6 Hz is taken as the setpoint at which a loss of offsite power occurs.
In order to determine the conservative lower bound for the time delay between turbine trip and loss of offsite power, the grid system for the j Florida Penninsula was employed. This grid can tie into only the Georgia j and Alabama grid systems, which can make up only 400 MWe through the trans- j mission lines to Florida. Therefore, the Florida grid becomes an " electrical i island" for a generation deficiency caused by the loss of a 1300 MWe unit. '
On the curves of grid frequency response for this grid system, the effects of a generation deficiency caused by the tripping of a System 80 plant was ,
superimposed. Based on this evaluation, a 3.1 seconds time lag between 1 turbine trip and loss of offsite power was calculated. This time delay is a conservative lower bound since the evaluation assumed:
(1) No credit for spinning reserve and load shedding, (2) The Florida grid " island" conditions (no support from neighboring grid sytems),
(3) Loss of a System 80 plant as a 10% generation loss which is a much higher percentage than the actual loss (less than 3.5%), and (4) Loss of offsite power at 57.6 Hertz for all System 80 plants.
Subsequent to reactor trip, stored and fission product decay energy must be ,
dissipated by the reactor coolant and main steam systems. In the absence of forced reactor coolant flow, convective heat transfer into and out of the reactor core is supported by natural circulation reactor coolant flow.
Initially, the residual water inventory in the steam generators is used and the resultant steam is released to atmosphere via the main steam safety valves. With the availability of standby power, emergency feedwater is automatically initiated on a low steam generator water level signal. The operator can determine which steam generator has the tube rupture based on information from the radiation monitors prior to trip and the difference in the post-trip steam generator water levels. The operator can isolate the )
damaged steam generator and cool the NSSS using manual operation of the l emergency feedwater system and the atmospheric steam dump valves of the l unaffected steam generator any time after reactor trip occurs. The analysis l presented herein conservatively assumes operator action is delayed until 30 minutes after first indication of the event. ]
The primary source of the emergency feedwater is the condensate storage tank. The capacity of the storage tank is 300,000 gallons which is sufficient j feedwater to maintain the plant at hot standby for 8 hours. The condensate l storage tank is provided with an atmospheric vent to maintain atmospheric !
pressure inside the tank y The maximum condensate radioactivity concentration l is 0.1 pCi/lbm (2.2 x 10 pCi/gm) dose equivalent I-131. 1 Ol Amendment No. 7 15.6-16 March 31, 1982
15.6.3.2.3 Analysis of Effects and Consequences 15.6.3.2.3.1 Core and System Performance A. Mathematical Model The mathematical used for evaluation of core and system performance is identical to that described in Section 15.6.3.1.3.1.
B. Input Parameters and Initial Conditicns The input parameters and initial conditions used for the evaluation of core and systems performance are similar to those described in Section 15.6.3.1.3 and are given in Table 15.6.3-9. Both the initial core mass flow rates and the one pin radial peaking factor were chosen to:
(1) maximize the primary-to-secondary integrated leak, and the steam releases through the main steam safety valves, and (2) at the same time, obtain a simultaneous reactor trip on a low DNBR (=1.19) as well as a low pressurizer pressure. Consequently, a slightly lower core mass flow rate (104% instead of 116%) as well as a slightly lower radial peaking factor (1.53 instead of 1.55) were employed in the analysis.
C. Results The dynamic behavior of important NSSS parameters following a steam generator tube rupture with a loss of normal ac power are presented in Figures 15.6.3-19 through 15.6.3-34.
Prior to reactor trip, the dynamic behavior of the NSSS following a steam generator tube rupture with a loss of offsite power is similar to that following a steam generator tube rupture without a loss of offsite power which is described in Section 15.6.3.1.3. At about 1187 seconds after the initiation of the tube rupture the CPC low pressure boundary of 1785 psia is reached. resulting in a reactor trip signal.
Subsequent to the reactor trip, 4 he RCS pressure begins to decrease rapidly, and the pressurizer empties at about 1201 seconds due to the continued primary-to-secondary leak. After the pressurizer empties, the reactor vessel upper head begins to behave like a pressurizer and controls the RCS pressure response. Due to the loss of offsite power, the reactor coolant pumps begin to coast down reducing the core coolant flow rate, and the mass flow into the upper head region. This region becomes thermalhydraulically decoupled from the rest of the RCS, and due to flashing caused by the depressurization and boiloff from the metal structure to coolant heat transfer, voids form in this region at about 1196 seconds. The void formation is enhanced by the decoupling effect, since the RCS pressure reduction due to primary system cooling l is felt in this region, while the RCS temperature reduction is not. l The significant impact of voids in the upper head region is a slower RCS pressure decay resulting in the generation of the safety injection actuation signal (SIAS) at 1613 seconds. The High Pressure Safety Injection (HPSI) pumps begin delivery of safety injection fluid to the 15.6-17 Amendment No. 7 March 31, 1982
1 safety injectior flow. As a result, the upper head voids begin to 10 l
collapse at about 1677 seconds.
Following turbine trip and loss of offsite power, the main steam system pressure increases until the main steam safety valves open at about 1197 seconds to control the main steam system pressure. A maximum main steam system pressure of 1310 psia occurs at about 1205 seconds. Subsequent to this peak in pressure, the main steam system pressure decreases resulting in the closure of the safety valves at 1721 seconds.
Prior to turbine trip, the feedwater control system is in the automatic mode, and supplies feedwater to the steam generators to match the steam flow through the turbine. Following turbine trip and loss of offsite power, the feedwater flow ramps down to zero. Consequently the steam generator water levels decrease due to the steam flow out through the main steam safety valves, and a low steam generator level signal is generated at 1714.6 seconds. Subsequently, at 1759.6 seconds, emergency 10 feedwater flow is initiated, an' the steam generator water levels begin to recover.
After 1800 seconds, the operator identifies and isolates the affected steam generator by closing the main steam isolation valves. The operator then initiates an orderly cooldown by means of the atmospheric dump valves and emergency feedwater flow to the unaffected steam generator.
After the pressure and temperature are reduced to 400 psia and 350 F, respectively, the operator activates the shutdown cooling system and isolates the unaffected steam generator.
The reduction in the RCS pressure due to the loss of primary coolant through the ruptured steam generator tube results in a reduction in the thermal margin to DNB (ree Figure 15.6.3-34). The transient minimum DNBR of 1.19 occurs at the time of reactor trip. The DNBR shows an increasing trend after reactor trip due to the rapidly decreasing heat flux. The RCPs do not begin their normal coastdown until after the loss of offsite power three seconds after turbine trip. However, there is a slight decrease in the core flow during the three seconds immediately after turbine trip and prior to the loss of offsite power due to decreasing pump speed caused by frequency degradation (approximately 1 Hertz /second) of the electrical grid. The resultant calculation demonstrates that no violation of the fuel thermal limits occurs, since the minimum DNBR stays above the value of 1.19 throughout the transient.
The maximum RCS and secondary pressures do not exceed 110% of design 1 pressure following a steam generator tube rupture event with a concurrent loss of offsite power, thus, assuring the integrity of the RCS and the main steam system.
Figure 15.6.3-29 gives the main steam safety valve integrated flow rates versus time for the steam generator tube rupture event with a loss of offsite power. At 1800 seconds, when operator action is assumed, no more that. 54,936 lbm of steam from the damaged steam generator and 54,730 lbm from the intact steam generator are discharged O
15.6-18 Amendment No. 10 June 28, 1985
~
via the main steam safety valves. Also, during the same time period approximately 80,500 lbm of primary system mass is leaked to the y damaged steam generator. Subsequently, the operator begins a plant cooldown at the technical specification cooldown rate (100 F/hr) using the intact steam generator, the atmospheric dump valves,and emergency feedwater system. Forthefirsgtwohoursfollowingtheinitiationof f the event, a total of 5.76 x 10 lbms of steam flow to the condenser j through the turbine (up to the time of loss of offsite power), and )
about 843,300 lbms of steam are released to the environment through the atmospheric dump valves. gorthetwotoeighthourcooldown period an additional 1.81 x 10 lbms of steam are released via the atomspheric dump valves.
15.6.3.2.3.2 Radiological Consequences A. Physical Model The evaluation of the radiological consequences of a postulated steam generator tube rupture assumes a complete severance of a single steam generator tube while the reactor is operating at full rated power and a loss of offsite power three seconds after turbine trip. Occurrence of the accident leads to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result of low pressurizer pressure at approximately 1187 seconds after the event initiation. l The reactor trip automatically trips the turbine.
The steam generator pressure will increase rapidly, resulting in steam discharge as well r,s activity release through the main steam safety j valves. Venting from the affected steam generator, i.e., the steam !
generator which e)periences tube rupture, continues until the secondary system pressure is below the main steam safety valve setpoint. At this time, the affected steam generator is effectively isolated, and .
thereafter, no steam or activity is assumed to be released from the I affected steam generator. After 1800 seconds, the operator initiates a plant cooldown at the technical specification cooldown rate (100 F/hr) using the unaffected steam generator, atmospheric dump valves, and the emergency feedwater system.
The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondi.q activity as well as primary system activity leaked frem the tube break. The inventory of iodine and noble gas fission product activity available for release to the environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in the core, and the mass of steam discharged to the environment. Conservative assumptions are made for all these parameters.
B. Assumptions and Conditions The assumptions and parameters employed for the evaluation of radiological releases are identical to those described in Section 15.6.3.1.3.2 with L the following exceptions and/or additions.
\
"mendment No. 7 15.6-19 March 31,1982
l l
- 1. For steam release through the atmospheric dump valves, a decontamin-ation factor (DF) of 1 is assumed.
- 2. The total amount of primary-to-secondary leakage through the rupture is 80,500 lbm.
- 3. The steam flow through the condenser is 5.76 x 106 lbms. The half hour to two hour steam flow through the atmospheric dump valves is 843,300 lbms. An additional 1.81 x 10 lbms of steam are discharged to the environment through the atmospheric dump valves during the two to eight hour time period.
C. Mathematical Model The mathematical model employed in the evaluation of the radiological ,
consequences during the course of the transient is described in Section !
15.0.4. l D. Results The two-hour exclusion area boundary (EAB) and the eight-hour low population zone (LPZ) boundary inhalation doses for both the event generated iodine spike (GIS) and the pre-existing iodine spike (PIS) are presented in Table 15.6.3-10. The calculated EAB and LPZ doses are well within the acceptance criteria.
4 15.6.3.2.6 Conclusions I The radiological releases calculated for the SGTR event with a loss of offsite power are well within the 10CFR100 guidelines. The RCS and secondary system pressures are well below the 110% of the design pressure limits, .
thus, assuring the integrity of these systems. Additionally, no violation. )
of the fuel thermal limits occurs, since the minimum DNBR remains above the i 1.19 value throughout the duration of the event. )
i Voids form in the reactor vessel upper head region during the transient, l due to the thermal hydraulic decoupling of this region from the rest of the RCS. The upper head region liquid level remains well above the top of the hot leg throughout the transient. Therefore, natural circulation cooldown j is not impaired during the transient. Furthermore, the upper head voids '
begin to collapse upon actuation of the safety injection flow, indicative I of stable plant conditions. After thirty minutes, the operator employs the '
plant Emergency Procedure for the steam generator tube rupture event to l
cool down the plant to shutdown cooling entry conditions.
l O
Amendment No. 7 15.6-20 March 31,1982 1
o_________________ _ _ _ _ _ _ _ _ _ _ - _ _ _ - . _ _ _ _ - - - _ . _
l p TABLE 15.6.3-1 (Sheet 1 of 2)
SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE Time Setpoint Success (Sec) Event or Value Path 0.0 Tube Rupture Occurs --
l
)
30.0 Third Charging Pump Started, feet -0.75 Primary below program level System Integrdty 30.0 Letdown Control Valve Throttled -0.73 Primary l Back to Minimum Flow, feet below System program level l
53.8 Backup Heaters Energized, psia 2360 Primary System Integrity l
l 560.0 Pressurizer Heaters De-energized 400 g due to Low3 Pressurizer Liquid Volume, ft
;Vi 1148.3 CPC Low Pressure Boundary Trip -- Reactivity 10 Signal Generated Control i
Feedwater Flow Starts Ramp Down to 5% of Initial Full power Flow 1148.45 Trip Breakers Open --
Reactivity 10 Control 1149 Turbine Tripc Stop Valves Start --
Control to Close --
Secondary i System l Integrity l 1151 Pressurizer Empties -- --
1152 Turbine Stop Valves Closed --
Secondary System Integrity 1180.8 Pressurizer Pressure Reaches Safety 1578 Reactor injection Actuation Signal (SIAS) Peat Removal 10 Analysis Setpoint, psia N
1 Amendment No. 10 June 28, 1985
l TABLE 15.6.3-1(Cont'd.)(Sheet 2of2)
SE0VENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE WITH A G )i '
LOSS OF OFFSITE POWER Time Setpoint Success I (Sec) Event or Value Path 1181.8 Safety Injection Actuation Signal Reactivity Generated Control and .
Reactor Heat I Removal i 10 1181.8 Safety Injection Flow Initiated -- )
1181.8 Letdown Isolation Valves Closed on -- Prima ry SIAS System Integrity 1209 Main Steam Safety Valves Open, psia 1282 Secondary I System Integrity 1210 Maximum Steam Generator Pressure, 1283 psia ]
10 l
1316 Main Steam Safety Valves Close, psia 1218 Seconda ry System Integrity 1447 Pressurizer begins to refill --
1690 HLO Mode Terminates Feedwater Flow 80 Seconda ry to Damaged Steam Generator, % wide System range Integrity 1778 HLO Mede Terminates Feedwater Flow 80 Secondary to Intact Steam Generator, % wide System range Integrity 1800 Operator Isolates the Damaged Steam --
Reactor Heat Generator and Initiates Plant Cooldown Removal at 100*F/hr for the 1.5 hour time period 28,800 Shutdown Cooling Entry Conditions 400/350 Reactor Heat are Assumed to be reached, RCS Removal Pressure, psia /RC}}