ML20128C434
| ML20128C434 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 01/29/1993 |
| From: | Hoffman D CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.) |
| To: | |
| References | |
| NUDOCS 9302040019 | |
| Download: ML20128C434 (80) | |
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y January 29, 1993 Nuclear Regulatory Commission i
Document Control Desk Washington, DC 20555 LDOCKET 50-155 - LICENSE DPR BIG ROCK POINT PLANT -
REVISION 3 TO UPDATED FINAL HAZARDS
SUMMARY
REPORT (FHSR)
In accordance with 10 CFR 50,71 one original and ten copies of this submittal as specified in 10 CFR 50.4 are enclosed. This revision is submitted on a replacement page basis and is accompanied by a list identifying the current
. pages 'of_ FHSR following page replacement. A " slash" typed in the margin with-
-the change number " Revision 3" in '.ne upper right-hand corner indicates the area changed. ,
I David P H an-Vice President of Nuclear Operations CC: Administrator, Region III, USNRC NRC Resident Inspector - Big Rock Point
. ATTACHMENT'
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ATTACHMENT Consumers Power Company Big Rock Point P1 ant Docket 50-155 REVISJON 3 - FINAL SAFETY HAZARDS
SUMMARY
LIST OF EFFECTIVE PAGES-l-
O January 29, 1993
d..
- UPDATED FINAL HAZARDS- Resision 3
SUMMARY
REPORT.- FHSR Page i of BIG ROCK POINT PLANT V:.. LIST OF EFFECTIVE PAGES QlifJfjg PAGE-. REVISION!
CHAPTER 1 - INTRODUCTION AND GENERAL PURPOSES 1.2-1 Original- '
l.2-2 = Revision 3 / '
1.2-3 _ Original l.2-4 Original 1.3-1: Original. J 1.4-1 ~- Original:
- 1. 5 Original:
1.5-2 Original 1.5-3 Original 1.5-4 Original 1.6-1 Original-1.7-1 Original CHAPTER 2 - SITE CllARACTERISTICS 2.1-1 Original-2.1-2 -Original 2.1-3 Original 2.1-4 -Original 2.1 Original' 2.1-6 Originalz 2.1-7 Original 3O 2.1-8 Original 2.1-9 Original 2.1-10 Original-2.1-11 Original 2.1-12 Original 2.2-1 Original 2.2-2= Original' 2.2-3 Original 2.2-4 Original- 3 2.2-5. Original:
2.2-6 . Original' 2.3 Original
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2.3-10 Original 2.4-1 -Original 2.4-2 Original 2.4-3 Original L 2.4-4 Original J
1: : UPDATED FINAL. HAZARDS Revision 3-
SUMMARY
REPORT -:FHSR Page 2 of 25 BIG ROCK POINT PLANT
' LIST OF EFFECTIVE PAGES CHAPTERS -PAGE REVISION CHAPTER 2 - SITE CHARACTERISTICS 2.4 5 Origilial -
2.4 Or_iginal - ,
2.4-7 Original 2.5-1 Original 2.5-2 ' Original 2.5 =0riginal-2.5-4 Original-
= 2.5-5 Original 2.5-6 Original 2.5-7 Original-2.5-8 Original-2,5-9 Original-2.5 Original 2.5-11 Original-2.5-12 Original 2.5-13 Original - -
2.5-14 . Original 2.5-15 Original 2.5-16 Original
-2.5 Original--
2.5-18 Original 2.5-19 - Original 2.5-20 Original-2.5-21 Original 2.5-22 Original 2.5-23 ' Original 2.5-24 Original 2.5 Original CHAPTER 3 - DESIGN OF STRUCTURES, COMPONENTS, .- __ _
EQUIPMENT AND SYSTEMS 3.1-1; _ Original 3.1-2 Original-3.2-1 _ Original 3'.2-2 Original' 3.2-3 Original-3.2-4 Original 3.2-5 _ Original.-
3.2-6 Original
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UPDATED FINAL HAZARDS 'Revis' ion 3
SUMMARY
REPORT ~- FHSR Page 3 of 25 BIG ROCK POINT PLANT LIST OF EFFECTIVE PAGES-(
CHAPTERS PAGE REVISION- <
CHAPTER 3 - DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT AND SYSTEMS 3.2-15 Original 3.2-16 Original 3.2-17 -Original-3.2-18 Original
-3.2-19 Original 3.2 Original 3.2-21 ' Original 3.2-22 Original 3.2-23. Original 3.2-24 Original 3.2-25 Original 3.3-1 Original 3.3-2 Original 3.3-3 Original 3.3-4 Original 3.3-5 Original 3.3-6 . Original 3.3-7 Original C 3.4-1 Original 3.4-2 Original 3.4 Original 3.4-4 Original-3.4-5 Original 3.5-1 Original 3.5-2 Original 3.5-3 Original-3.5-4 Original 3.5-5 Original 3.5-6 Original 3.5 -Original 3.5-8 Original 3.5-9 Original 3.5-10 : Original 3.6-1 Original 3.6-2 Original 3.6-3 Original 3.6-4 Original 3.6-5 Original--
3.6-6 . Original 3.6-7 Original..
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3.8-1 Original 3.8-2 Original 3.8-3 Original
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UPDATED FINAL HAZARDS
, Revision 3
SUMMARY
REPORT - FHSR Page 4 of 25 BIG ROCK POINT PLANT LIST OF EFFECTIVE PAGES CHAPTERS ._PAGL ' REVISION-CHAPTER 3 - DESIGN OF STRUCTURES, COMPONENTS, - .
EQUIPMENT AND SYSTEMS ? .64 Original 3.8-6 Original' -
3.8-7 Original 3,8-8 Original 3.8 9 Original 3.8-10: Original--
3.8-11 ' Original 3.8-12 Original 3.8-13 - Original ,
3.8 Original 3.8-15 Original 3.8-16 -Original-3.8-17 Original-3.8-18 Original-3.8-19 Original 3.8-20 Original
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3.10-1 Original .
3.11-1 Original' 3.11-2 Original 3.11-3 Original 3.11-4 Original 3.11-5 Original
. 3.11-6 Original 3.11-7 Original-3.11-8 Original CHAPTER 4 - REACTOR 4 .1 - l ' Original 4.1-2 Original 4.2-1 Original 4.2-2 Original 4.2-3 Original
.O 4.2-4 4.2-5 Original Original
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e . UPDATED FINAL HAZARDS- Revision 3'
SUMMARY
REPORT ~- FHSR- 'Page 5 of:25 BIG' ROCK POINT: PLANT W -ljST OF EFFECTIVE PAGES
, {(j CHAPTERS -PAGEi . RLY1SJM CHAPTER 4 - REACTOR 4.2-6 -Original 4.3-1 Original-4.3-2, Original -
4.3-3 Original-4.3 Original-4.3-5 Original 4.3 6 Original:
4.3 Original 4.3-8 Original.:
4.3-9 Original 2 4.3-10 Original
- 4. 4-l _- Original-4.4 Original-4.4-3: Revision.li 4.5-1 Revision 1 4.b Original 4.6 Original!
4.6-3; -
Original 4.6-4 : Original O
4.7-1 Original-4.7-2 Original::
4 .' 7 - 3 -Original-4.7-4. Original 4.7-5 Original 4.7-6~ Original
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4.7-12 Original
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4.7-18 Revision 3 _/.
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4.7 Original-4.7-23 Original 4.7-24 Revision 31 J/?
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a
n-n UPDATED' FINAL HAZARDS: Revision-3
SUMMARY
REPORT:- FHSR Page 6 of 25-BIG ROCK PolNT PLANT l L UST OF EFFECTIVE PAGES CllAPTERS PAGE REVISION CHAPTER 4 - REACTOR 4.7-26 Revision 3 /
4.7-27 Revision 3- -/-
4.7-28 Original-4.7 29' Original 4.7-30 Original 4.7-31 Original 4.7-32 ' Original 4.7-33 Original:
4.7-34 Original -
4.8-1 Original 4.8-2 Original 4.8 Original 4.8-4 Original 4.8 Revision 3. /,
4.8-6 Original _
4.8-7_ Original 4.8-8 Original
-4.8-9 Original CHAPTER 5 - REACTOR COOLANT AND CONNECTED SYSTEMS 5.1-1 -Original 5.2-1 Original
- 5.2-2 Original 5.2-3 Original 5.2-4 Original-
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5.3-6 Original 5.3-7 Original
, UPDATED FINAL HAZARDS Revisibn 3
SUMMARY
-REPORT - FHSR Page 7 of 25' BIG ROCK POINT PLANT. .
LIST OF EFFECTIVE PAGES CHAPTERS PAGEL REVISION CHAPTER 5 REACTOR COOLANT AND CONNECTED SYSTEMS- 5,3 ;0riginal:
5.3 . Original 5.3-10 Original-5.3-11 Original-5.3 Original '
5.3-13 Original:
5.3-14 Original 5.3-15 Original
'5.3-16 Original 5.3-17. Original 5.3-18 Revision-I 5.3-19 _ Revision 1 5.3-20 Revision 1 5.3-21 Revision:1 5.3-22 Revision 1 5.3-23 Revision 1 5.3-24 Revision-l' 5.3-25 Revision 1 ,
5.3-26 Revision 1
, 5.3 Revision 1 5.3-28 -Revision 1
- 5.3-29 Revision 1 5.3-30 Revision 1-5.3-31 Revision 1 5.4-1 Original 5.4-2 Original 5.4-3 Originalf 5.a-4 Original 5.4-5 Original 5.4-6' Revision l3_ /_
5.4-7 Revision:1
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5.4 -Original-5.4-14 Original 5.4-15 Original-
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5.4-18 Original 5.4-19 Original 5.4 Original _'
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a UPDATED FINAL HAZARDS . Revision 3
SUMMARY
-REPORT . FHSR Page 8 of 25 BIG ROCK POINT PLANT
[IST OF EFFECTIVE PAGES gjA_fIlgg PAGE REVISION CHAPTER S - REACTOR COOLANT AND CONNECTED SYSTEMS 5.4-23 Original 5.4-24 Original-5.4-25 Original 5.4-26 Qriginal 5.4 Original 5.4 Original-5.4-29 Original 5.4-30 Original 5,4-31 Original 5.4-32 Original 5.4-33 Original 5.4-34 Original 5.4 Original 5.4-36 . Original'-
5.4-37 Original 5.4-38 Original 5.4-39 Original 5.4-40 Original.
5.4-41.- Original f 5.4-4f8 Original 5,4-43 Original-5.4-44_ Revision.3 /
CHAPTER ENGINEERED SAFETY FEATURES (ESF) 6.1-1 Original 6.1-2 Original 6.1 - 3. Original'-
6.1-4 Original
~6.1 Original-6.2-1 -Original 6.2-2 ' Original 6.2-3 Original '
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6.2-8 Original 6.2-9 Original u 6.2-10 Original 6.2-11 Original 6.2-12 Original 6.2-13 Original 6.2-14_ Original 6.2-15 Original 6.2-16 Original
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r UPDATED FINAL HAZARDS Revision 3 1
SUMMARY
REPORT-- FHSR;- Page 9 of 25 l CIG ROCK POINT PLANT LISJ_QE. EFFECTIVE PAGLS CHAP.11RS PAGE _ REVISION CHAPTER 6 - ENGINEERED SAFETY. FEATURES (ESF) 6.2 Original 6.2 Original 6.2-21: -Original 6.2-22 - Original-
-6.2-23 Original 6.2-24 Revision 3 /1 6.2-25: Original 6.2 . Original 6.2-27 -Original 6.2-28 Original 6.2-29 Original 6.2-30 Revision-3 /
6.2-31 Original 6.2-32 Original 6'.2-33 ' Original
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6.3 Revision 3 /
t 6.3-5 -Revision 3 -/
6.3 Revision 3 6.3-7 Revision 3 6.3-8 Revision 3 6.3-9 Original 6.3-10 Original 6.3-11 Revision 1 6.3-12 Revision l' 6.3-13 Revision 1 6.3-14 Revision 1-6.3-15 Revision 1
-6.3-16 -Revision 1 6.3 Revision 1 6.3-18 Revision 1 6.3-19 -Revision 1-6.3-20 Revision 1-6.3-21 Revision 1 6.4-1 Original-6.4 Original 6.4 Original-6.4-4 Original 6.4-5 Original 6.4-6 Original 6.4-7 Original 6.5-1 Original O 6.6-1 Original
UPDATED FINAL HAZARDS Revision 3
SUMMARY
REPORT - FHSR Page 10 of 25-BIG ROCK POINT PLANT
()
LIST OF EFFECTIVE PAGES CHAP 1ERS PAGE REVISION CHAPTER 6 - ENGINEERED SAFETY FEATURES (ESF) 6.7-1 Original 6.8-1 Original 6.8-2 Original. 4 6.8-3 Original 6.8-4 Revision 2 6.8-5 Revision 1 6.8-6 Revision 1 6.8-7 Revision 1 6.8-8 Revision 1 6.839 Revision 1 6.8-10 Revision 1 6.8-11 Revision 1 6.8-12 Revision 1 6.8 13 Revision 1 6.8-14 Revision 1 6.8-15 Revision 1 6.8-16 Revision 1 6.9-1 Original 6.9-2 Original 6.9-3 Original 6.9-4 Original 6.9-5 Original 6.9-6 Original 6.9-7 Original 6.9-8 Original 6.9-9 Original 6.9-10 Original 6.9-11 Original 6.9-12 Original 6.9-13 Original 6.9-14 Original 6.9-15 Original 6.9-16 Original 6.9-17 0;-iginal 6.9-18 Original l 6.9-19 Original 6.9-20 Original 6.9-21 Original
, 6.9-22 Original l 6.9-~23 Original 6.9-24 Original 6.9-25 Original 6.9-26 Original t
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' UPDATED FINAL' HAZARDS Revision 3
SUMMARY
REPORT - FHSR. Page 11- of_25_
BIG ROCK: POINT PLANT:- 4
.,x
.( ) LIST OF EFFECTIVE PAGES CHAPTERS PAGE REVISION CHAPTER 7 - INSTRUMENTATION AND CONTROLS 7.1-1 Original 7.l 2 Original
.7.1_3-Original
-7.1-4 Original 7.1-5 Original 7.2-1 Original 7.2-2 -Original =
7.2-3 Original 7.2-4 Original 7.2-5 Original 7.2-6 : Original 7.2-7 Original 7.2-8 Original 7.2-9 Original 7.2-10 Revision 1 7.2-11 -Revision 1~
7.2-12 Revision 2 7.2-13 Revision 2 7.2-14 -Revision 1:
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\ 7.3-1 Original 7.3-2 Original 7.3 Original 7.3-4 Original.
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7.5-3 Revision I 7.6-1 Original 7.6-2 _0riginal-
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7.6-4 Revision 1 7.6-5 Revision.1 7.6-6 Revision 1 7.6-7 Revision'l-7.6-8 Revision 1 7.6 9 Revision'l
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' UPDATED FINAL HAZARDS ' Revision 3-
SUMMARY
REPORT.---FHSR- Page 12 of 25 -
BIG ROCK POINT-PLANT: .
1- LIST OF EFFECTIVE PAGES i
CHAPTERS -.__PJ_qll. REVISION CHAPTER 7 - INSTRUMENTATION AND CONTROLS 7.6-12 Revision-11 7.6-13 Revision'1 !
7.6-14 Revision 1 7.7.1 Original-
- 7.7 . Original
-7.7-3 Original 7.7-4_ Original-CHAPTER 8 - ELECTRIC POWER 8.1 -' 1 . . Original- -l 8.1-21 Original
- 8.2-1. Original 8.2-2 Original 8.2-3 . Revision 2 8.2-4 Original 8.2-5 Original-8.2 6' Original 8.2 Original.
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'UPCATED FINAL 11AZARDS- Revision 3
SUMMARY
REPORT - FHSR .Page 13 of.25 BIG ROCK POINT PLANTJ
/m
!q)- LIST OF EFFECTIVE PAGES (HAPTERS PAGE__ REVISION CHAPTER 8 - ELECTRIC POWER- 8.4-10 Original 8.4-11: Revision 1-8.4-12 Original 8.4-13 Original 8.4 14 Original 8.4-15 Revision 2-8.4-16 Original-8.4 17- Original 8.5-1 Original CHAPTER 9 - AUXILIARY SYSTEMS 9.1-1 _ Original 9.1-2 Original 9.1-3= Original 9.1 L0riginal-9.1-5 Original 9.1 Original-9.1-7 Original 9.1 Revision l 9.1 Original bV 9.1-10 9.1-11 Original-
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- ! UPDATED FINAL-HAZARDS:. ,
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SUMMARY
REPORT v FHSRJ Page 14 of 25 BIG ROCK. POINT-PLANT-LIST 0F-EFFECTIVE'PAGES. ,.
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UPDATED FINAL HAZARDS Revision 3
SUMMARY
REPORT - FHSR Page'15 of 25 BIG ROCK POINT PLANT' 1
LIST OF EFFECTIVE-PAGES CHAPTERS- PAGE- REylS10E CHAPTER 9 - AUXILIARY SYSTEMS 9.-l Original 9.5-2 Original 9.5-3 Original
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9.6-3 _ Original 9.6-4 Original 9.6-5 -Original-9.6 6 Original-9.b-7 ' Original 9.6-8 Original.
9.6-9 Original CHAPTER 10 - STEAM POWER CONVERSION SYSTEMS 10.1 -Original 10,1-2 Original 10.1-3 Original 10.2-1 Original; 10.2-2 Revision-2' 10,2-3 (;evision 2-10.2-4 =0riginal 10.2-5 Revision 1 f 10,2 Revision-1 Q). 10.2-7 Revisim 1
UPDATED FINAL HAZARDS ' Revision 3
SUMMARY
REPORT-- FHSR Page 16 of-25 BIG ROCK POINT PLANT-fy
(,l: LIST OF EFFECTIVE PAGES CHAPTERS PAGE REVISION-CHAPTER 10 - STEAM POWER CONVERSION SYSTEMS 10.2-8 -Revision'3 /'
10.2-9 Revision 2 10.3-1 Original-10.3-2 -Original.
10.3-3 Original 10.4-1 Original 10.4-2 Original 10.4-3 Original 10.4-4 Original 10.4-5 Original 10.4-6 Original 10.4-7 Original 10.4-8 L0riginal 10.4-9 Original 10.4-10 Original 10.4-11 Original 10.4 Revision 3 / --
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10.4-15 10.4-16 Original Original 10.4-17 ~0riginal' 10.4-18 Original 10.4 19 Original
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10.4-21 Original 10.4-22. ._0riginal CHAPTER 11 - RADI0 ACTIVE WASTE MANAGEMENT 11.1-1 Original:
11.1-2 Original a 11.1-3 Original-11.1-4 Original- 1 I I .'l- 5 Original; 11.1-6 Original - '
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UPDATED FINAL HAZARDS -Revision 3-
SUMMARY
REPORT - FHSR Page:17 of 25
_ BIG ROCK POINT PLANT LIST OF EFFECTIVE PAGES ,
CHAPTERS' PAGE REVISION l CHAPTER 11 - RAD 10 ACTIVE WASTE MANAGEMENT 11.5-2 Original'-
11.5-3 Original 11.5-4 Originali 11.5-5 Original-11.5-6 Original-11.5-7 Original 11.5-8 Original 11.5-9 Original 11.5-10 -Original 11.5-11 Original 11.6-1 Revision.1 CHAPTER 12 - RADIATION PROTECTICN 12.1-1 Original 12.1-2. . Original 12.1 Original 12.1 Original 12.2-1 Original ,
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CHAPTER 13 - CONDUCT OF OPERATIONS 13.1-1_ Revision 3 ./
13.1-2 Revision 3_ /L 13.1-3 Original.
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13.1 Original 13.1-6 Revision 3 /- 4 13.2-1 Original-13.2-2 Original 13.2-3 Original 13.2_4 Original-15.3-1 Original 13.4-1 Original r 13.5-1 Revision 3 /- ,
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UPDATED FINAL HAZARDS- Revision t 3
SUMMARY
REPORT - FHSR Page 18 of 25 BIG ROCK POINT PLANT <!
LIST OF EFFECTIVE PAGES CHAPTERS- PAGE BEVISION y
CHAPTER 13 - CONDUCT OF OPERATIONS 13.5 3 Original .
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-l ATTACHMENT Consumers Power Company Big Rock Point Plant Docket 50-155-REVISIGN 3 - FINAL SAFETY HAZARDS CUMMARY PAGE CHANGES January 29,-1993
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Revision 3 BRP is the oldest and smallest commercial nuclear power plant still O operating in the US at a electrical output of 75 MWe.
/
/
BRP is a direct cycle, forced circulation boiling water reactor capable of producing 240 megawatts thermal at a nomina operating pressure of 1350 psia. The electric generating capacity is 75 megawatts at this thermal output.
1.7.2.1 Enctor Vessel and Steam Drum The BRP reactor pressure vessel is 30 foot in overall length and 106 inches in diameter. The reactor pressure vessel has 61 penetrations, the largest two being 20 inches in diameter. The active fuel length is 70 inches and there are 32 bottom-entry control rods.
Steam seaaration and feedwater addition occur in a separate steam drum ratier than in the reactor pressure vessel. Subcooled liquid enters the reactor vessel from two constant flow recirculating water pumps near the bottom of the vessel. Each recirculating pump is ,
capable of pumping six million pounds per hour of coolant. As the coolant passes through the core, it is heated to a steam water mixture. Steam baffles, located approximately six feet above the top of the active fuel, force the steam water mixture out six -
14-inch risers. The steam water mixturo travols up the risers to a steam drum located approximately 30 feet above the top of the reactor pressure vessel. The steam drum is 40 feet long and 78 O inches in diameter, it provides three basic functions: (1)' steam separation from the steam water mixture occurs in the drum with turboseparators and screens, (2) feedwater addition and mixing and (3) it supplies a net positive suction head for the reactor recir-culating pumps located 65 feet below the drum. The coolant flows from the steam drum to the recirculating pump suction via four 17-inch downcomers. There are no jet pumps in the BRP reactor pressure vessel and the downcomers are external to-the vessel.
Overpressurization of the primary system is prevented by six spring-operated relief valvas located on the steam drum.- The fir:' relief valve opens at 1,535 psig and the remaining valves open in the 10 psi increments. The safety relief valve discharge is unpiped and relieves directly into the steam drum cavity.
1.2.2.2 fantainment The BRP reactor containment building is significantly different from the current BWR 3, 4 and 5, but similar in design in Dresden 1. The BRP containment is a- spherical steel vessel 130 feet in diameter. -
The s)here extends 27 feet below grade and 103 feet above grade.
The B1P sphere is designed for 41.7 psia internal pressure with the design basis loss of coolant event pressure rating of 37.7 psia.
The sphere free volume is approximately one million cubic feet. The BRP containment is not inerted and has a continuous flow of air.
1,2-2
Revision 3 letter provided the results. The review was conducted in three phase'i, A summarized as follows:
\")
- 1. The structural elements listed under Section 13, Reconsnenc'ations, from the TRC report, applicable to each Category I structure at Big Rock were reviewed and evaluated. Attachment 1 of the f ebruary 10, 1989 letter presents the rcsults of the review. The review concludes that the structural design was so conservatively done -
that the code changes do not significantly impact the margin of safety under the loads considered in the original design.
- 2. The second phase of the review examined those items tabulated with-an 'Ax in the IRC report. The results of this examination are included as Attachment 2 of the february 10, 1989 lotter. The.
examination concludes that the plant structures have an adequate safety margin under the cebined seismic loads, but are vulnerable to the combined tornado wind load (in particular the Turbine building and the Screenhoute/ Diesel Generator building).
Ilowever, the construction cf the Alternaie Shutdown building required to meet Appendix R, and the addition of a portable pump to resolve Wind and Tornado Loading, provides additional safeguards against damage to these two buildings.
- 3. The third phase of the review resulted in an overall examina tion of Appendix A to the fRC report. The results of this examination are presented in Attachment 3 of the february 10, 1989 letter. .
This review concludes that there exist some vulnerabilities from
, tornado loads to the Control Room, the Screenhouse/ Diesel Generator k building and to the Turbine building. Again, due to the Alternate Shutdown building and the portable pumping capabilities that was provided at Big Rock Point, the vulnerabilities of these structuret are less of a weak-link to the safety of the plant than prior to the modifications.
The overall conclusion of this review, as presented below is.that no additional plant modifications are required ~to address the topic of Design Codes, Critoria and-Load Combinations. Modifications already com)1eted for other reasons have adequately compensated for poten- tial l wea(nesses identified in this review. -With this submittal Consumers Power Company considers that all actions related to SEP Topic III-7.B and Integrated Plan Issue BN 051 are now complete.
By letter dated June 12, 1991, the NRC Staff documented their /
resolution of SEP Topic ill-7.B. They concluded that the licensee -/.
had adequately addressed this SEP Topic. -/
[yaluation Conclusions -
Based upon the above evaluation and the following considerations, it can be concluded that changes in code provisions do not affect the safety margin of plant structures.
3.8-21 -
Revision 3 3.9.3 INTERGRANULAR SlRESS CORROSION CRACKING (IGSCC) INSPECTION PROGRAll i
ILKkgrEAd Nuclear Regulatory Commission Generic Letter 84 11, inspections of BWR Stainless Steel Piping, dated April 19, 1984 required Consumers .
Power Company to submit plans relative to inspections for intergranular stress corrosion cracking (IGSCC) of stainless steel piping and to ,
submit a plant specific leakage detection information. Our response to this request was submitted by letter dated May 25, 1984 and additional clarifying information was provided by letters dated '
July 2, 1985 and October 13, 1986, By letter dated February 4, 1986 /
the NRC provided an evaluation of our responses and requested ,
additional information. By letter dated September 30, 1987 CPCo /
submitted an on going IGSCC Inspection Program to be implemented beginning with the 1988 refueling outage. >
On January 25, 1988, the Nuclear Regulatory Commission issued /
Generic letter 88-01 "NRC Position on IGSCC in BWR Austenitic / .
Stainless Steel Piping". This Generic Letter applied to / .
all BWR's with piping made of austenitic stainless steel which /
is four inches or larger in nominal diameter and contains reactor /
coolant at a temperature above 200 degrees fahrenheit during /
power operation regardless of code classification. The final / .
response dated May 24, 1991 was accepted by the NRC'in a /
letter / safety evaluation dated August 1,1991. The 1GSCC /
Inspection Program was updated in a letter dated July-24,1991, /
adding back-up core spray piaing wolds. Section 5.2.3.5 in /
O this updated fHSR outlines tie correspondence between the NRC and Consumers Power dealing with this issue. /
/
PROGRAM
- 1. Summary Big Rock Point has performed IGSCC examinations on 75 of /
the 118 susceptible welds. Many of these welds have been /
examined several times. To date no IGSCC has been found /
on any of the welds covered by Generic Letter 88 01. /
!!. Scope and Schedule /
A. 1992 REFUELING OUTAGE (end of the second ISI interval) /
- 1) During the 1992 Refueling Outage Big Rock ins)ected -/
the 12 welds which are only accessible from tie Reactor /
Vessel interior during the mechanized examination. /
These 12 welds were examined using normal ultrasonic /
test methods because no commercially available qualified /
techniques for IGSCCs existed.
- 2) IGSCC examinations of 1/2 (10) of the 20 Nozzle-to-Safe /
end and Safe End-to-Pipe welds from the Steam Drum were /
performed. /
- 3) IGSCC examinations of 10% of the other 55 Category D / ;
welds were performed. /
3.9-4
Revision 3 B. THIRD INSPECTION INTERVAL 1992 2002 /
Il /
V 1) Perform to Safe EndIGSCC and Safeexaminations End to Pipe we of 1/2 (lds-from the / Ste Drum each refueling outage.
- 2) Perform IGSCC examinations of 10% of the other 55 /
Category D welds each refueling outage.
- 3) Perform IGSCC examinations on 8% (6) of the 85 3" /
reactor clean up system welds each inspection period /
(approximatelyevery3-1/3 years). /
- 4) Perform examinations on the 14' Reactor Yessel Nozzle- /
to Safe End and Safe End to Pipe wolds at the end of the /
first period of the interval. /
- 5) Perform IGSCC examinations on welds 4 RDC 101-9 and /
4-RDC-101-13 each inspection period. /
- 6) Perform IGSCC examinations on 25% of the 24 Category A /-
welds on the Redundant Core Spray Line during the /
inspection interval. <
- /
!!I. REVISION OF SCOPE AND SCHEDULE /
A. If IGSCC is detected during an inspection, the number of /-
/7 welds to be examined will escalate per the requirements /
d of ASME Boiler and Pressure Vessel Code,Section XI, Subsection IWB-2430, 1977 Edition through Summer 1978
/
/
addenda. The NRC shall be notified for concurrence on /
sample size expansion if IGSCC is detected. '/
B. If IGSCC indications are detected, indications will be /
evaluated per ASME Boiler and Pressure Vessel Code, Section /
XI, Subsection IWB 3500, 1977 Edition through Summer 1978 /
Addenda, /
C. If an Indication is unacceptable, repair will be by weld /
overlay reinforcement, partial weld replacement or full weld /
replacement. All flaw repair (s) will be handled on a case by /
basis. Other repair methods may be used if appropriate /
materials and processes are available that offer the repaired ./
weld sufficient resistance to IGSCC. /
D. Indications may be analyzed per ASME Boiler and Pressure. /-
Vessel Code,Section XI, Subsection IWB 3600, 1977 Edition /
through Summer 1978 Addenda. /
E. This program will be amended at the end of the second /
Inservice inspection interval (1992) .to reflect code updates /-
as required by 10 CFR 50.55a.
l IV. QUAllFICATION OF EXAMINATIONS _/
L A. All IGSCC examinations will incorporate qualified examiners /
l and procedures in accordance with Generic-Letter 88-01. /.
3.9 S
Revisiot 's 1 3.9.6 REACTOR VESSEL MATERIAL SURVEILLANCE PROGRAM (Reference 36)
A materials exposure program has been established in the B N %
O Point Nuclear Plant to measure the effect of neutron irradtwo M time at temperature on the mechanical properties of the readtn ,
pressure vessel steel. Base metal specimens were made from nom of the pressure vessel steel, and wold heat-affected zone and weld metal samples were taken from a weldment made from the pressure vesel steel and simulating a >ressure vessel longitudinal weld.
Tensile property changes will )e measured by are and post irradiation tests on small tensile specimens, fracture claracteristic changes will be measured in similar fashion by Charpy V notch impact tests.
The program was planned to cover a 32 year period, with specimens to be removed for test at intervals of 1, 2, 4, 8, 16, and 32 years.
for details on the program, refer to CPCo letter dated June 12, 1978 including attached General Electric, "GECR 4442 Reactor Pressure Vessel Material Surveillance Program at the CPCo BRP Nuclear Plant,"
Report dated December,1963; and the Naval Research Laboratory Report,
- Mechanical Property and Neutron Spectral Analyses of the BRP Reactor Pressure Vessel" published in Volume 11 April 1970 Nuclear Engineering and Design. (Extracted pages 393-415 are included in the June 12, 1978 submittal.)
The Systematic Evaluation Program (SEP) Topic V 6, " Evaluation of the Integrity of SEP Reactor Vessels," was completed by the NRC in October 1979 and published as NUREG-0569 in December 1979. Appendix C of the NVREG provided an Evaluation of Big Rock Point which also O addressed the Material Surveillance Program as follows:
Reactor Vessel fingE g Based upon the Naval Research Laboratory (NRL) calculations, an extrapolated and projected fluence for the BRP 40 year full power service limit of the reactor was 8.1 x 10" n/cm'>0.5MeV, (refer to the NRL Report included in the June 12, 1978 submittal). ,
Additional capsules were removed and analyzed in 1979 and results were reported in Electric Power Research Institute (EPRI) Report 1021-3, submitted to the NRC by letter dated December 18, 1981.
Currently there are two capsules remaining in the reactor vessel, (a partial thermal capsule set and a complete wall capsule), the estimated removal date established for these 1995 based upon the 32 year General Electric Surveillance Program. ,
118.C EvaluatiQn The material surveillance program for Big Rock Point was planned prior to the initial issuance of Appendix H,10 CFR Part 50. -The program is based on ASTM Recommended Practice E-185 dated 1964.
The program consisted of 12 capsules having tensile and Charpy specimens from base, heat affected zone (HAZ), and weld materials.
There were four wall capsules placed at the core midplane at positions where the core corners are closest to the vessel wall. These capsules 3.9-6 )
Revision 3 were located closed to the vessel wall where they would receive O a fluence from 20 to 50 times that on the vessel wall 10. The program also included five thermal control capsules located on top of the baf fle 31ste. These capsules are exposed to the temperature e cycles of tie vessel and to a neutron flux three or four decades lower than the vessel wall. The main purpose of these specimens is -
to monitor any aging affect experienced by vessel materials.
The Big Rock Point material surveillance program conforms to almost all the rules of Appendix H,10 CFR 50. Some of the capsules contained less than the required number of 12 Charpy saecimens for each material type. However, the program contained more t1an the required number of capsules and total number of specimens. Some capsules also contained only two tensile specimens instead of the required three.
From our review of this program, it is concluded that it is very good and will provide sufficient data to monitor the radiation damage on the reactor vessel materials .hroughout their service life.
At the time of issuance of NUREG-0569, five capsules had been removed from the vessel. Accelerated capsules were removed in 1964 and in 1967. Wall capsules were removed in 1964 and 1968. One thermal control capsule was removed in 1968. Tests on these surveillance specimens were conducted at the Naval Research Laboratory.- The two wall capsules received fluences of 1.5 and 7.1 x 10" n/cm'. The two accelerated capsules received fluences of 2.3 x 10" and 1.07 x 10" n/cm. From these tests, we concluded that weld metal is the limiting O vessel material. its RTm increases 135'F at a fluence of 7.1 x 10" n/cm', and increases by 190*F at a fluence of 2.3 x 10" n/cm'.
At the above fluence levels, the upper shelf energy of the weld metal decreasegfromabout90toabout60ft-lbs. At a fluence of 1.07 x 10" n/cm , the upper shelf energy is still almost 60 f t-lbs. The-shelf energy of plate material also drops to about 60 ft-lbs at a fluence of 2.3 x 10" n/cm'. These test results do not show any rate effect on the degree of radiation damage. Thus, the results of accelerated capsules are considered to be comparable to those of the wall capsules.
The SEP report also concluded, based on the low primary vessel stresses and the use of materials with adequate fracture toughness, that assurance is provided that brittle fracture will n)t occur.
i 3.9.5 REACTOR PRESSURE VESSEL INTERNALS Systematic Evaluat4on Program (SEP) Topic 111-8.C was initiated to provide an evaluat on of Irradiation Damage, Use of Sensitized Stainless Steel, and Fatiguo Resistance of BRP reactor vessel internals.
By letter dated June 23, 1982 the NRC Staff provided the final evaluation on this topic. The final evaluation was based upon the February 5,1980 Staff evaluation and comments submitted by CPCo letter dated December 23, 1981.
O 3.9-7
. = - - - . - - . - - - - - - . . - - - .
Revision 3 i EvaluatinD (Reference 37) l SEP Topic 111-8.C is intended to determine if the integrity of the reactor internal structures has been degraded through the use of sensitized steel, i The effect of neutron irradiation and fatigue resistance on material !
of the internal structures was eliminated from the safety objective of Topic 111-8.C in memorandum to D G Eisenhut from D K Davis and -
V S Noonan dated December 8, 1978.- The memorandum concluded that operating experience indicated that no significant degradation of the '
materials of the reactor internal structures had occurred as a result of either irradiation damage or fatiguc resistance.
The reactor internal structures were described in Sections 4 and 5 of
- the 1961 Final Hazards Summary Report for the Big Rock Point Nuclear Plant. Thu internal components were designed to provide support for the fun 1 and maintain structural clearances during normal and accident conditions. In addition, the internal components provide passageways for the coolant to cool the fuel and means for adequately separating the steam from the coolant water.
Components of the reactor coolant pressure, boundary of the Big Rock Point Nuclear Plant were designed, fabricated, inspected and tested to the requirements of Section I and Section Vill of the ASME Boiler and Pressure Vessel Code, 1959 Edition, including a)plicable code case rulings. Where the Code was not applicable, tio design was O evaluated from the principle described in the U S Navy Bureau of Ship Publication, " Tentative Structural Design Basis for Reactor Pressure Vessels and Directly Associated Components," April,1958. 1 The primary criteria for material selection for the reactor internal components were the mechanical properties, the material stability and corrosion resistance in the reactor environment. The materials used for the construction of the reactor internals were identified in the final Hazards Summary Report as Type 304 stainless steel, inconel, and minor quantities of special purpose materials, such as Stellite, Colmonoy, Graphitar, and 17-4 PH alloy. The structural materials identified have proven adequate for reactor internal construction as a result of extensive tests, prior usage, and satisfactory performance.
As a result of the discovery of a leak in the feedwater inlet nozzle of the Lacrosse reactor vessel in October,1969, and in reply to questions from the staff, the licensee. in letters dated September 11, 1970, and January 12, 1971, identified all the furnace sensitized stainless steel components and the maximum calculated levels to which the components would be stressed in service. The reactor internal components were furnace sensitized, but the maximum level of stress intensity did not~ exceed 907, of the material yield strength (code allowable) at operating temperature.
Experience has shown that at least three elements in combination are necessary to cause cracking in sensitized stainless steel components. :
These are material susceptibility, an oxygenated water environment, and a threshold total stress. The Big Rock Point Nuclear Plant 3.9-8
l Revision 3 reactor internal components contain sensitized stainless steel in O contact with an oxygen saturated water coolant environment. _However, the calculated stresses do not exceed the threshold stress values associated with intergranular stress corrosion cracking. The threshold
~
stress values are near or greater than the 0.2% off set yield stress at temperature, further, in the reactor environment, stress relaxation may occur due to irradiation and temperature effects.
The Licensee Event Reports and the BWR Ruclear Power Experience were reviewed for the Big Rock Point Nuclear Plant with regard to reactor internal materials problems. The events are summarized as follows:
Beginning with the 1965 refueling outage, roller failure was observed in the peripheral control rod blades. The failure was attributed to severe coolant turbulence in these locations.
Stress corrosion cracking was not a factor, in a letter of May 1972, the staff concluded that this failure did not endanger the health and safety of the public.
Stress corrosion cracking caused the failure of Type 304 stainless steel beryllium antimony neutron source capsules (1973). An internal pressure build u) of the helium-tritium occurred from the n, a and n 2n reactions. T1e problem was corrected by replacing the stainless steel with Zircaloy capsules. During the reactor cican-up of beryllium oxide following this failure, the reactor internal components were removed and inspected. The examination showed neither intergranular stress corrosion cracking nor O evidence of material degradation in the components.
The inlet diffusers became loose from the reactor wall in April, 1979. The shoulder bolts holding the diffusers in place failed as a result of mechanical vibration. Stress corrosion cracking was not a factor. As no flow blockage occurred, the health and <
safety of the public was not endangered.
During the period of the diffuser repair in 1979 a remote visual examination of selected areas of the Reactor Vessel Interior was completed. No indications of stress corrosion cracking were noted.
Leakage was observed from Control Rod Drive F-2 during the pre -
startup hydrostatic test conducted in April of 1979. The leak path was determined to be between the CRD Housing and'the Reactor Vessel Wall. Poor welding techniques during construction was cited as the cause of failure. Stress corrosion was not thought to be a factor. As the leakage-was minimal and contained, and the operation of the Control Rod Drive Mechanism was not affected, the health and safety of the public was not endangered.
Conclusions We conclude from our review of the information submitted by the licensee and the operating information in the Licenseo Event Reports together with the BWR Nuclear power Experiences that the stainless steel materials in the reactor internal components are sensitized and 3.9-9
Revision 3 that there is an increased potential for cracking due to operation in i an oxygen saturated water environment. However, the incidence of O stress corrosion cracking are expected to be rare because the total stress level in the internal components is relatively low. In the unlikely event that intergranular stress corrosion cracking should .
occur, operating experience has demonstrated that cracks in the ;
components will be detected by inse vice inspection procedures prior to component failures. We conclude that the use of sensitized stainless steel in the reactor internal com)onents at the Big Rock Point Nuclear Plant is not a hazard to the lealth and safety of the public, furthermore, we conclude that the integrity of the internal structures will be assured by an inservice inspection program in accordance with the requirements of paragraph (g), Section 50.55a, 10 CFR Part 50, Lqose Parts Monitorinq 3.9.5.1 Systematic Evaluation Program (SEP) Topic III-8.A, Loose Parts Monitoring and Core Barrel Vibration Program was evaluated by the NRC Staff in a letter dated March R,1982. Conclusions from the evaluation were:
- 1. A Loose Parts Monitoring Program (ie, detection system and procedures as specified in Section C.2 an C.3 of RG 1.133, Rev 1) as currently required for new facilities does not exist at Big Rock Point.
The portion of Topic III 8.A related to Core Barrel Vibrations O 2.
does not apply to Big Rock Point.
The need to actually implement a loose Parts Monitoring Program will be determined during the integrated assessment.
Intearated Assessment ConclusioJ11 (Reference 1, Section 4.14)
NUREG 0828 Integrated Plant Safety Assessment Systematic Evaluation Program Final Report, May 1984 Section 4.14 addressed this issue as follows:
A loose parts monitoring program could provide for-an early detection of loose parts in the primary system that could help prevent damage to the primary system. Such damage related primarily to:
- 1. damage to fuel cladding resulting from reheating or mechanical penetration ,
- 2. jamming of control rods
- 3. possible d1 gradation of the component that is .the source of the loose part to such a-level that -is cannot properly perform its -
safety-related function.
The following factors were _ considered in making a recommendation that O no modifications be done at this time:
- 1. A summary of 31 representative loose parts incidents at 31 reactors (from the value-impact statement of Revision 1 to.
3.9 10
Revision 3 Regulatory Guide 1.133) indicates that structural damage occurred 7 as a result of loose parts in only nine incidents. None of these (d incidents caused a safety related accident. ;
- 2. Most loose parts can be detected during refueling inspections.
- 3. The limited PRA of this issue for Big Rock Point concluded that eliminat.ing loose parts induced transients by installing a loose parts monitoring system would have no effect on risk. :
r O
1 0
3.9-11
Revision 3 !
CHAPTER 3 REFERENC(ji O Reference (1) Integrated Plant Safety Assessment - Systematic Evaluation Program NUREG-0828. Final Report, May 1984 1 (2) NRC Letter dated April 16, 1982, SEP Topic 111-1, Quality Group Classification of Components and Systems, BRP Nuclear Plant. 3 (DraftSER)
(3) CPCo Letter dated November 23, 1982, SEP Topic 111 1, Classification ofStructures,ComponentsandSystems(SeismicandQuality)
(4) NRC Letter dated September 19. 1983, SEP Topic 111-1, Classification of Structures, Components and Systems - BRP Plant (Final SER)
(5) CPCo Letter dated February 10, 1986, BRP Plant - Integrated Plan issue 90 - Classification of Structures, Systems and Components -
SEP Topic 111-1 (6) CPCo Letter dated August 29, 1986, BRP Plant Integrated Plan issue BN 090 - Classification of Structures, Systems and Components -
SEP Topic 111-1 (7) CPCo Letter dated August 3, 1982, SEP Topic 111-2, Wind and Tornado Loading (CPCo Evaluation)
(8) CPCo letter dated August 8, 1980, BRP Plant Response to Request for Additional Information - SEP Structural Topics (III-2, III 3A, 111-7.8 and III 7.D)
(9) NRC Letter dated December 9, 1982, SEP Topic 111-2, Wind and Tornado loadings - BRP Plant (NRC Evaluation)
(10) CPCo Letter dated February 13, 1987, BRP Plant - Integrated Plan issue BN-025, Wind and Tornado Loading, Revised Risk Evaluation'and Response to Request for Additional Information (11) NRC Letter dated December 2, 1982, SEP Topic III-3.A. Effects of High Water Levels on Structures (Revised Safety Evaluation Report)
(12) CPCo letter lated December 21, 1981, SEP Topic 111 3.0, inservice Inspection of Water Control Structures (Topic Evaluation)
(13) NRC Letter dated October 12, 1982, SEP Topic lil-3.C, Inservice inspection of Water Control Structures (NRC Safety Evaluation Report)
(14) CPCo Letter dated January 14, 1983, SEP Topic Ill-3.C, inservice Inspection of Water Control Structures - Summary of Formalized Inspection Program
1 Revision 3= *
-f GLA2TER 3 REFERENCES (Continued) / :
(15) NRC Letter dated September 22, 1987, Wind and Tornado loadings and.
Tornado Missiles (SEP Topics III-2, III-4.A; HlflEG 0828, Sections 4.5 and 4.8; Integrated Plan Issue BN-025; TAC No. 55068) }
(16) CPCo Letter dated May 4,1982, SEP Topic _III 4.C, Internally Generated '
Missiles (CPCo Evalu6 tion) ,
(17) CPCo letter dated September 13, 1982, SEP Topic III-4 C, Internally Generated Missiles (CPCo Response to NRC Questions)
(18) NRC Letter dated October 14, 1982 SEP Topic III-4.C, Internally Generated Missiles (NRC Safety Evaluation Report)
(19) CPCo Letter dated June 9, 1982, SEP Topic III-4.B, Turbine Missiles (CPCo Evaluation)
, (20) NRC Letter dated November 29, 1982, SEP Topic 111-4.0, Turbine Missiles (NRC Safety Evaluation Report)
(21) CPCo Letter dated March 16, 1982, SEP Topic III-4.A. Tornado Missiles (Response to Request for Information)
(22) CPCo Letter dated June 16, 1982, SEP Topic III 4.A. Tornado Missiles (Response to Request for Information)
(23) NRC Letter dated November 29, 1982 SEP Topic III-4.A. Tornado Missiles-(NRC Safety Evaluation Report)
(24) CPCo Letter dated December 14, 1981, SEP Topic 111-4.0, Site Proximity.
Missiles (Including Aircraft), (CPCo Evaluation)
(25) NRC Letter dated August 12, 1982, SEP Topic-111-4.0, Site Proximity Missiles (Including Aircraft), (NRC Satety Evaluation Report)
(26) CPCo Letter dated June 29, 1973, Technical Specification Change Request (Proposed Change No 39)
(27) CPCo Letter dated May 21, 1982, SEP Topic 111-5.B, Pipe Break Outside Containment (CPCo Evaluation)
(28) NRC Letter dated September 16, 1982, SEP Topic III-5.B. Pipe Break Outside Containment (NRC Safety Evaluation Report)
(29) CPCo letter dated September 30, 1982, SEP Topic III-5.A. Effects of Pipe Break on Structures, Systems, and Components Inside Containment (CPCoEvaluation)
(30) CPCo letter datad June 22, 1983, SEP Topic III-5.A iiigh Energy Line l
Break Inside Containment - Probabilistic Risk Assessment (PRA Evaluation)
Revision 3 QLAflG __S REFERENCES (Continued) /
(31) NRC Letter dated September 22, 1983, SEP Topic Ill 5.A. Effects of ,
Pipe Break on Structures, Systems, and Components inside Containment '
(NRC final Safety Evaluation Report)
(32) CPCo letter dated March 31, 1983, SEP Topic 111-5.0, Pipe Break Outside Containment, PRA Response to final NRC SER (33) NRC Letter dated September 30, 1982, SEP Topic 111-7.B, Design Codes, !
Design Criteria and Load Combinations (Draft Safety Evaluation)
(34) CPCo Letter dated September 2,1982, SEP Topic 111-7.B, Design Codes, i Design Criteria and Loading Combinations (Response to NRC/fRC questions) i i
(35) NRC Lette. dated September 30, 1982, SEP Topic 111-7.B, Design Ccles, Design Criteria and Load Combinations (Draft safety Evaluation Report)
(36) NRC Letter dated March 5,1980, NUREG-0569, Evaluation of the Integrity.
of SEP Reactor Vessets, SEP Topic V 6 (37) NRC Letter dateti June 23, 1982, SEP Topic 111-8.C, Irradiation Damage, ,
Use of Stainio deel and fatigue Resistance (NRC Final Safety _ '
Evaluation)
(38) CPCo letter dated January 28, 1985, BRP and Palisades Plant - Response
( to Generic letter 84 24 EQ Program certification (39) NRC Letter dated November 15, 1985, Safety Evaluation for Environmental Qualification of Safety Related Electrical Equipment (40) NRC Letter dated January 25, 1988, NRC Position on IGSCC in BWR' Austenitic Stainless Steel Piping (41) CPCo Letter dated July 25, 1988, Response to Generic letter 88 01 (42) NRC Letter dated April 18, 1989, Request for Additional Information (43) CPCo letter dated June 23, 1989, Response to Request for Additional Information (RAI) Concerning Generic Letter 88 01 ,
(44) NRC Letter dated December 11, 1990, Concerning Generic Letter 88-01 (45) CPCo Letter dated February 14, 1990, Response to Request for Additional Information (RAI) Concerning Generic Letter 88 01 (46)- CPCo letter dated May 24, 1991, Response to Generic Letter 88-01 (47) NRC Letter dated August 1,1991, Safety Evaluation / Staff Review of IGSCC Inspection Program (48) CPCo Letter dated July 24, 1991, Updating the IGSCC Inspection Program
t Revisten 3 7 was chrome plated in order to improve the galling resistance of (V the guide sleeve.
An additional flange strainer along with a modified two stage' :
upper strainer with improved filtering characteristics were .,
installed to protect against the entrance of foreign material into the drives.
These changes were addressed in CPCo letters dated December 11,_ ;
1964 and December 24, 1965. The Hazards Analysis for those changes are also included in these letters and indicate that:-
The modifications to the upper strainer and the guide sleeve do not change the basic function of those parts and should in no way change the hazards considerations involved. The new strainer at the flange, even if it should br,come completely pluggnd, will not affect the basic drive functions. The relative area of the screen is so much larger than.the aorts in the flange, thatif plugging should occur, t1e screen will merely partially -
tear loose, relieving the blockage and thus permitting normal drive operation. Even under severe conditions it is not expected that any portion of the screep or its frame would become detached and enter the drive.
The modified parts were installed on a Big Rock Point control rod drive and tested extensively in the General 1
- 3) Electric (GE) test facility.in San Jose. About 1700 scram i operations, under a variety of operating conditions and-dirt conditions, were com)1eted with no noticeable effect on the modified parts. 111s testing indicated that a "
significant improvement in drive performance should result from the modification. 1 i
Specification Change 50-87-034 provided for the installation of :
a second seal in series with the existing piston seal ring in the CRD tube and flange assembly. Installation of the second seal assembly improves drive shim operation by reducing internal bypass leakage. Failure of the new seal will not jeopardize drive function, nor will it adversely affect scram capability. Section NB of the ASME Boiler Code,Section III -
1983 Edition was utilized to ensure a conservative analytical' design basis, although the seal is not an ASME Code item. Only one CRD mechanism has been modified for evaluation purposes.
Specification Field Changes-SFC 78 023 and-79-022 were utilized-to address the use of elastomer "0"-rings to seal the attachment of the drive mechanism to the thimble mounting flange in place of the original metal *0"-rings.. The elastomeric "0"-rings provide a more effective seal.
o Specification Change SC-91012 provided additional CRD cooling /-
^ -
water flow by utilizing an orificed plug in lieu of a 1/4 - 20 /
UNC x 3/8 set screw located in the CRD flange. Cooling water /
ports were provided during the original drive construction but /
4.7-18
8 Revision 3
/3 was chrome plated in order to improve the galling resistance of
() the guide sleeve.
An additional flange strainer along with a modified two stage upper strainer with improved filtering characteristics were installed to protect against the entrance of foreign material into the drives.
These changes were addressed in CPCo letters dated December 11, '
1964 and December 24, 1965. The Hazards Analysis for these changes are also included in these letters and indicate that:
The modifications to the upper strainer and the guide sleeve do not change the basic function of those parts and should in no way change the hazards considerations involved. The new strainer at the flange, even if it should become completely )1ugged, will not affact the basic drive functions. Tio relative area of the screen is so much larger than the ) orts in the flange, that if plugging should occur, tie screen will merely partially tear loose, relieving the blockage and-thus permitting -
normal drive operation. Even under severe conditions it is not expected that any portion of the screen or its frame would become detached and enter the drive..
The modified parts were installed on a Big Rock Point control rod drive and tested extensively in the Genural n)
(' Electric (GE) test facility in San Jose. About 1700 scram
~
operations, under a variety of operating conditions and dirt conditions, were com)1eted with no noticeable effect on the modified parts. T11s testing indicated that a significant improvement in drive performance should result from the modification.
. Specification Change SC-07-034 provided for the installation of a second seal in series with the existing piston seal ring in the CRD tube and flange assembly. Installation of the second seal assembly improves drive shim operation by reducing internal bypass leakage. Failure of the new seal _ will not jeopardize drive function, nor will it adversely affect scram capability. Section NB of the ASME Boiler Code,Section III -
1983 Edition was utilized to ensure a conservative analytical.
design basis, although the seal is not an ASME Code item. Only one CRD mechanism has been modified for evaluation purposes.
. Specification Field Changes SFC 78 023 and 79 022 were utilized to add nss the use of elastomer "0"-rings-to seal the attachnnt_ of the drive mechanism to the thimble mounting flange in place of the original metal "0"-rings. The elastomeric "0"-rings provide a more effective seal,
. Specification Change SC-91-012 provided additional CRD cooling /
water flow by utilizing an orificed plug in lieu of a 1/4 - /
fs'v) UNC x 3/8 set screw located in the CRD flange. Cooling water ./
ports were provided during the original drive construction but /
4.7-19
.)
i Revision 3 were intentionally plugged when it was' determined that normal /
o)
' internal drive leakage to the reactor was sufficient to cool the drive. Subsequent to the seal welding of the joint
/
/
between the CRD flange and the inner tubr, (SC 91-020), the /
internal leakage was greatly reduced making this specification /
change necessary. /
. Specification Change 50-91 020 provided for the installa- /
tion of a seal weld joining the inner tube to the CRD flange. /
This seal weld provides for elimination of leakage past the /
inner seal ring. Excessive leakage past the inner seal ring /
has resulted in a hydraulic short circuit between the insert /
and withdraw flow paths. Elimination of this flowpath will /
result in enhanced drive performance. It is expected that / ,
certain CRD's will be repaired over several years beginning / ,
in the 1991 Ref uling Outage. /
4.7.4 CONTROL R0D DRIVE HYDRAVLIC CONTROL SYSTEM 4.7.4.1 jlysiraulic Control System Description Normal operation of the drive mechanism is controlled by external hydraulic circuits utilizing demineralized water. Selector valves are supplied for each control rod drive. The circuit is interlocked to 3revent operation of more than one drive at a time except during scram.
Flow is regulated by manually adjusted' orifices to produce the desired
(] positioning speed in both directions of operation. Differential pressure V acting across the )iston provides the operating force for the drives. A -
pressure slightly ligher than reactor pressure is maintained on the bottom of the piston when the drive is not operating to provide leakage flow to cool and flush the drive. The drive system is shown by Drhina 0740G40122.
To raise the rod (decreasing reactivity), water at a pressure a> proximately 200 psi above reactor pressure is admitted below the piston, wiile the water displaced from above the piston is discharged to the drive cooling circuit. When the rod has reached the desired-position as determined by the operator reading the position indicator, the control circuit is shut off, thus equalizing the pressure in the drive. The rod and piston tube then lower by gravity until the next locking groove above the collet reaches the collet. At that point, the collet fingers enter the locking groove, and the piston tube is locked to prevent further downward motion.
To move a rod down, a momentary upward pressure is applied, as described above, to unload the collet-fingers. A " downward" pressure is then applied (the reverse of the " upward" pressure) to hold the collet fingers open and to move the piston rod down to the desired position. - The control valve is then closed to isolate the drive from the control pressure, which permits the collet fingers to enter the locking groove and re-establishes normal pressure throughout the drive mechanism.
Scram or emergency insertion of the rod is accomplished by similar drive flow paths as normal raising of the rod except that the rate ~of control rod insertion is considerably faster.
4.7-19
Revision 3 3
4.7.4.2 Control Rod Drive Accumulators Thirty two gas water accumulators, one for each control rod drivc O'
mechanism, are the sources of the hydraulic pressure required for the scram at low reactor pressures, while a shuttle valve within each drive mechanism admits reactor water to the drive when the reactor pressuro exceeds accumulator pressure. The accumulators are charged with nitrogen gas to a pressure which will deliver enough water to scram a fully withdrawn rod at low reactor )ressures. The charge on each accumulator is monitored continuously )y a pressure switch. The water discharged from the drives during a scram is collected in a scram dump tank which is initially at atmospheric pressure. The accumulators and dump tank are isolated from the normal driving circuit connnected to each drive by scram valves which are held closed by solenoid operated pilot valves.
Scram is initiated by de energizing the scram 1110t valves which allows the scram valves to open, thereby connecting tie drives to the accumulators and scram dump tank. The largo differential piessure between the accumulators and dump tank rapidly drives the rods into the core.
When the scram stroke is completed, the accumulator pressure continues to holu the rods in the reactor. If the accumulator charging system does not function, the internal rod drive shuttle valve shifts and applies reactor pressure under the piston, until the dump tank is filled and system pressures are equalized. When the differential . '
pressure decays to a point where the rods can no longer be supported, O the weight of the rods are supported by the locing m*hanisms which are engaged to hold the rods at the fully inserted position. An interlock in the control system prevents withdrawal of any control rod until conditions have returned to normal, and safety circuits can be reset.
The hydraulic system is thus composed of a central system for driving individual control rods u) and down, and a scram system for rapid :
insertion of all rods. T1e central system is supplied by two full capacity pumps.
Accumulator Gas Pressure CPCo letter dated May 3,1962, in res)onse to NRC questions provided Amendment No.10, Addenda to fHSR Tecinical Qualifications Amendment No. 8. The minimum gas pressure required on the scram accumulators to meet maximum scram timing was addressed as follows:
The final minimum calculated scram accumulator gas pressure is 700 psig (see Technical Specifications, Section 6.2.1). This pressure is to be verified by tests at the site. Since there is a separate accumulator for each drive, the miniumu pressure will vary according to the resistance offered by the piping arrangement and the characteristics of the drive. On the basis of test facility experience the minimum scram accumulator pn-charae gas pressure is expected to be about 500 psig.
Current Technical Specifications in relation to CRD Withdrawal Permissive System Interlocks state:
4.7-20
Revision 3
... Interlocks shall r:> vent control rod withdrawal when any of the following conditions exist:
(a) When any two of the thirty-two scram accumulators are at pressure below 700 psig......
The minimum scram accumulator pre charge gas pressure is approximttely 640 psig. The top portion of the accumulator is then charged with filtered domineralized water from the CRD hydraulic system.
The waterside of the accululator contains a bladder which separates the gas and water. Once the accumulator is charged with gas and water, the charge is sustained for prolonged periods with or without occurrence of scram. A water leak detector is provided along with a pressure indicating switch. The leak detection and tha pressure switch annunciates in the control room and provide local indication at the accumulator. The pressure switch is conservatively set at a pressure above the 700 psia CRD withdrawal interlock pressure.
4.7.4.3 Scram Dumn Tank The scram dump tank serves as a container for water displaced from the 32 drive mechanisms during scram. It prevents draining the reactor after a scram, and will contain the water exhausted from the drive mechanisms. The horizontally-mounted tank has a capacity of 175 gallons which is sufficient to accommodate the maximum amount of water that would be exhausted if scram was initiated with all control rods fully withdrawn. Tank design pressure is 1875 psig at 325'F. The tank O was designed, fabricated, tested, and stamped in accordance with ASME Boiler and Pressure Vessel Code, Section Vill - 1959 under Codo Cases 1270 N and 1273 N. Original design was to an earthquake load of 5% of dead weight.
4.7.4.3.1ScramDischaraeVolume(SDV)
The active Scram Discharge Volume is totally within the Scram Dump Tank. The 175 gallon capacity is in excess of two full scram discharge qualtities. The Scram Discharge Vol ee piping is maintained water filled at all times due to a loop seal immediately ahead of the Scram Dump Tank inlet. This piping is not considered as part of the volume requied to accept scram discharge water during a scram event. The Scram Dump Tank has drain and vent valves which are normally open, and close upon reactor protection system trip. These valves assure full Scram Dump Tank capacity is available for the scram function. Thus, the tank is normally empty and vented to the atmosphere. The tank drains to the enclosure clean sump and vents to the enciosure dirty sump. In response to NRC IE Bulletin 80-17, a continuous atmospheric vent was installed on the vent piping.
Verification of Adeouate Volume As part of CPCo response to IE Bulletin 80-17, a Special Site Test was conducted which verified that adequate volume exists in the Scram Dur.:p O Tank to accept a full automatic scram of all control rods. Also, calculations were made to determine how many full scrams coulc; be discharged into an empty dump tank. The calculations were based on General Electric gel-56217 instructions. It was concluded from 4.7-21
Revision 3 valves. Both pumps are powered from alternating current station ,
power. In the event the CRD pump is to be used as part of the :
Alternate Shutdown System, the No. 1 CRD pump motor may be powered :
\ from the Emergency Diesel Generator.
4.7.4.3.5 Control Rod Drive Booster pumn !
A booster pump was added in the two inch CR0 supply line between the l condensate storage tank and the CRD pumps via f acility Change FC- ;
512. The pump was added to provido not positive suction head (NPSH) to the CRD Pumps supply line to prevent cavitation when the plant is ,
shutdown and a condensate pum) is not running. The CRD booster pump may also be used as part of t,e Alternate Shutdown System and be '
powered from the Emergency Diesel Generator.
4.7.4.3.6 Control Rod Drive ipply Ung_0Mr3bllit.Y_Beouiremenu (Technical Specifications)
The Control Rod Drive supply line into the containment sphere will be open to insure continuous water supply. Backup isolation is ;
provided by two check valves in the common suction line to the control rod drive pumps.
4.7.4.3.7 (gairpl Rod Drive Hydraulic System Instrumentation The operating condition of the control rod hydraulic system is continuously monitored by pressure, level and position monitoring equipment. These devices indicate locally and transmit signals to O the control room for the inlet and outlet scram valve positions, annunciate loss of accumulator gas pressure, water level in the gas '
side of the accumulator and dump tank water level. Hydraulic system flows, reactor differential pressure PR+30 and PR+200, and hydraulic system pressure are indicated on the control console. ,
4.7.4.3.8 Alternate Rod Iniection
/
Section 50.62(c)(3) of 10 CFR Part 50 requires that each boiling /
water reactor must have an alternate rod injection (ARI) system that /
is diverse (from the reactor trip system) from sensor output to final / t actuation device.
By letter dated October 1,1986 Consumers Power Company submitted a _ /
plant specific risk study on the ARI modification. The study concluded /
that the installation of the full ARI provided little benefit beyond /
the risk reduction associated with improving the response of the /
secondary side during transients from full power. As a result of the /'
risk analysis results further studies of the secondary side were -/
conducted to assess a proposed modification to trip a single reactor /
recirculating water pump during load rejection events. In a letter /
dated December 29, 1986 an exemption request from the requirements for /
the ARI was submitted to the NRC. /.
,. In a letter dated May 15. 1990, Consumers power submitted additional /
information regarding a recirc pump trip modification designed to /
enhance the response of the secondary system to a load rejection /
transient. The modification was installed via FC-664, and was not /
designed to the requirements of the recirc pump trip modification /
which Big Rock was granted exemption from March 20, 1986. /
4.7-24
Revision 3 On June 17, 1992 the NRC granted the exemption request for the ARI /
3 modifications at Big Rock, based in part on the installation of the /
recirc pump trip modification, the unique design of the liquid poison /
system and the limited remaining operating lifetime of the facility. /
4.7.5 CONTROL R0D SYSTEM INSTRUMENTATION AND CONTROL hd Withdrawal Limit Conditions in order to insure that the protection system controls operate properly, withdrawal of control rods is prever.ted, when certain conditions are not met, as described in Section 4.7.6.5 of this Updated fHSR and the following:
hd Withdrawal During_Refuelino Interlocks a o provided to prevent all motion with any of the refueling cranes (namely, jib crine, transfer cask winch and monorail crane), which are positioned over the reactor whenever any control rod is not fully inserted in the core during loading or fuel manipulation.
Control Rod Posjftlon Indicatina Svit.mD The position indicating system provides simultaneous-digital read out of the position of each of the control rods. Position indication in three '
inch increments is provided throughout the stroke of each rod. The colored background of the digital readout indicates when a rod is at an "all-out" or "all-in" position.
The position indicators and rod selection pilot lights for each rod are grouped together and arranged on the control room aanel in a )attern simulating the relative locations of the rods in tie core. 111s display is integrated with the in core monitor system readout.
RmL0rjve Test Panel A permanent test panel was installed in the main control room to aid in-drive scram timing tests. Position indication signals from the drive being tested can be selected by manual switching and these signals are then recorded as before by high speed recorders. (Refer to Facility fhange FC-051.)
4.7.6 CONTROL R00 SYSTEM PERFORMANCE REQUIREMENTS 4.7.6.1 [gntrol Rqd Performance (Technical Specifications)
The following limits apply to any control rod which can be withdrawn. It will be permissible to tag and valve out the hydraulic drive water to a fully inserted control rod which is defective or does not meet these limits provided the remaining rods do meet the limits.
The following tests will be performed at each major refueling but not less
,q often than once every 20 months, and prior to startup following any outage Q greater than 120 days in length.
(i) Withdrawal of each drive, stopping at each locking position to check latching and unlatching operations and the functioning of the position indication system.
4.7-25
Revision 3
' Scraa of each drive froa full withdrawn positions. Maximua (11) scram time from system tri,' to 90 percent of insertion shall not exceed 2.5 seconds.
(iii) Insertion of each drive over its entire stroke with reduced hydraulic system pressure to determine that drive friction is -
normal .
P (iv) Continuous withdrawal and insertion of each drive over its stroke with normal hydraulic system pressure. Minimum withdraw time shall be 23 seconds.
4.7.6.2 Core Shutdown Marain Verification (Technical Specifications)
The reactivity of the core loading will be such that it is always possible.
to maintain k,n at less than 0.997 with the most valuable reactivity worth control blade completely withdrawn from the core. The core shutdown margin will be verified by a demonstration that the reactor is subcritical with the most valuable reactivity worth control blade fully withdrawn, plus an immediately adjacent blade withdrawn to a position known to contribute 0.003 k,n of more to the effective multiplication. In the event that the maximum reactivity condition occurs at a temperature greater than ambient, the demonstration will either be performed at that temperature or a suitable additional margin will be demonstrated at ambient.
This verificatitn will be performed prior to startup after any shutdown in '
which the system has cooled sufficiently to be opened to atmospheric q pressure and any of the following situations exist:
. fuel has been added and/or repositioned in a way which is not definitely known to reduce reactivity; or
. Any steel channels have been replaced by Zircaloy channels during the shutdown; or
. A control rod has been changed and presance of poison has not been verified; or
. 35,000 MW, have been generated by the plant since the previous margin demonstration.
During )ower operation, if reactivity and control rod motion data indicate a possiale loss of poison from a control rod, the reactor will be shut down and, if any corrective action is necessary, will remain in shutdown condition until such corrective action has been taken.
4.7.6.3 abnormal Behavior of the Control Rod System (Technical Specification)
An immediate and thorough investigation will be made of the occurrences of any i.bnormal behavior (including inability to verify an control blade) of the control system to determine the cause and safety significance of the occurrence. The reactor will be shut down unless:
- l. It is determined by the investigation that any malfunction which has C occurred neither impairs the ability to control the reactor nor indicates the imminent impairment of the performance of additional components of the control rod system.
4.7-26
~- .
Revision 3 i
- 2. The operating hydraulic water to the defective control rod has been p tagged and valved out to prevent withdrawal of the centrol rod after d an attempt has been made to insert the control rod.
- 3. The core shutdown margin requirement (described in 4.7.6.2 abovs) can be met with the remaining operable control rods. Evaluation of this requirement will be based on previous experimental measurements.
4.7.6.4 Rate of Citange of Reactor Power Durina Power Oper tisj1 (Technical Specifications)
Control rod withdrawal during power operation will be such that the +
average rate of change of reactor power is less than-50 MW, per minute when power is less than 120 MW, less than 20 MW, per minute when power 15 between 120 MW, and 200 MW,, and 10 MW, per minute when power is between 200 MW, and 240 MW,.
4.7.6.5 Egfitrol Rod Withdrawal Permissive System (Technical Specifications)
The Control Rod Withdrawal Permissi_ve System is considered to be encompassed by the Plant Safety and Monitoring Systems.
Interlocks Interlocks prevent control rod withdrawal when any of the following conditions exist:
a)= When any two of the thirty-two scram accumulators are at pressure below 700 psig.
b) When any one of the three power range monitor channels reads:
(1) Less than 1 x 10" power, when reactor power is above the.
operating range of the source range monitoring channels.
(2) Greater than 105% power, or (3) A reactor period less than 15 seconds, c) When the scram dump iank is bypassed, d) When the mode selector switch is in the shutdown position.
Operatina Reouirements The control- rod withdrawal permissive interlocks will_ always be operable.
No_ further withdrawal of control rods will be permitted if one_ of these circuits is found to be inoperable.
Permissive circuits will be functionally tested prior to each major refueling but no less frequently than every 18 months. . Ilowever, the g refueling interlocks will be functionally tested prior to each major g refueling.
4.7-27
Revision 3 a normally open air operated valve (See Drawing _0740G401QI). Indication-O of poison tank pressure is provided to assure that the tank has become pressurized; and poison tant level switches indicate that the tank is emptying.
Temperatures of the poison tank and squib primers are recorded. High temperature on the squib primers is annunciated on a local panel with remote annunciation of a tiouble alarm to the control room. The recorder was initially installed via facility Change FC 265 in /
response to a CPCo December 7, 1973 commitment to monitor squib primer temperatures. This recorder was replaced via Specification Change /
SC-92 014. /
4.8.4 LPS EFFECTIVENESS (REFERENCE 1)
As part of the Probabilistic Risk Assessment results relating to the efficacy of a recirculation Pump Trip, CPCo concluded that the Liquid Poison System will act much more rapidly than described in Section 4.8.2.8 above. The basis for the improved performance characteristics and LPS Evaluation are provided in Chapter 15, Section 15.8.6 of this-Updated fHSR.
4.8.4.1 fault Tree Analysis (Reference 1)
A fault tree analysis was developed to analyze the ability of the LPS to inject poison (borated water) into the reactor vessel following a
( situation in which the control rods have failed to insert into the core (suchasduringanAnticipatedTransientWithoutScram(ATWS) event). This analysis is provided in Attachment 4 of Reference 1.
4.8.5 LPS EQUIVALENT C04 TROL CAPACITY (Reference 2)
Revised rule 10 C?R 50.62(c)(4), Requirements for Reduction of Risk from Anticipated Trandents Without Scram (ATWS) included Equivalent Control Capacity requirements for standby liquid control (BRP LPS) which was defined by the NRC in a letter dated January 21, 1981 (Generic Letter 85-03). The equivalent capacity of 86 gpm of 13 weight % sodium pentaborate was the Equivalent Capacity requirement.
The Big Rock Point liquid poison system exceeds the requirements of this rule. Smaller vessels require proportionally less sodium pentaborate flow to meet the rate of poison injection requirement of 10 CFR 50.62(c)(4) than does the 251 inch diameter vessel on which the rule was based. The Big Rock Point reactor vessel has a diameter of only 106 inches and sodium pentaborate solution is on the order of 19 weight percent. Injection rate with the reactor at power is 132 gpm.
It should be noted that because of unique operating features associated with plant design that the injection rates established by the rule n are probably not appropriate for Big Rock Point. It is useful to get a sufficient amount of poison to the core to shut the reactor down
' U quickly during a Big Rock- ATWS. The effectiveness of the poison .
system in providing a relatively quick shutdown of the reactor and a 4.8-5
Revision 3 5.2.5.7 Reneric_le11tr_84-ll_ - Inspections of BMLSidnless Steel Pinina (Leak Detectiga). (Reference 8)
V Reference 9 provided the CPCo response for the Generic Letter. An NRC inspection of the implementation of the actions set forth in Generic Letter 84-11 dated September 8, 1987 included the following comments:
Leak Detection and Leakage Limits The Big Rock Point (BRP) Technical Specifications for reactor coolant leakage surveillance requirements provide for sump level monitoring every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The guidelines provided in Generic Letter 84-11 however, require that sump level be monitored at 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> intervals. The BRP unidentified leakage limits req 91re a plant shutdown if the coolant system leakage exceeds I gpm. This is considered to be more restrictive than Generic letter 84 11 requirements and is considered acceptable.
5.2.5.8 GentrJL.lfLtier 88 NRC Position on IGSCC in BWR Austenitic /
Stainless _Sigel Pipjag /
Reference 39 details the CPCo response required by the Generic /
Letter. The Staff documented their review in a Safety Evaluation /
dated August 1, 1991, (Reference 40) and found the pro)osed /
program to be acceptabic. The following discussion em)odies /
the content of the Safety Evaluation in regards to leak detection. /
Discuulqn ISSVE 5 The licensee's program documented that leakage monitoring / 4 would be performed daily, not every four hours as described in /
the Generic Letter. /
The licensee informed the Staff that the Technical Specification /
required leakage calculation, involving the use of sum) level /
information and contaiment atmosphere temperature and lumidity /
corrections, was performed overy 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, liowever, containment /
sump pump run time recorders are read and trended every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. /
Alditionally, the Big Rock Point containment is accessible /
during power operations, and operator rounds are performed every /
E hours. Therefore, the licensee's leakage detection frequency /
is adequate. /
ISSE_6 The licensee did not intend to amend the Technical /
Specification to include requirements regarding the operability /
of monitoring instruments as' oatlined in the Generic letter. /
The licenseo committed to revise plant procedures in order to /
assure that leckage monitoring was performed every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> /
using one of the alternate methods if any of the leakage /
detection systems became inoperable. Due to the many diverse /
methods of measuring leakage inside containment (sump level /
O transmitters, manometers, temperature / dew point cells, and run-time recorders) and the frequency of operator rounds through containment, the staff agreed the this requirement
/
/
/
was unnecessary. Additionally, the licensee has committed to /
inform the NRC if any changes are made in the procedures. /
5.2-18
Revision 3 5.2.6 THERMAL STRESSES IN PIPING CONNECTED TO REACTOR COOLANT SYSTEMS CPCo, by letter dated September 26, 1988 in response to Nuclear Regulatory Commission Bulletin 88 08, Thermal Stresses in Piping Connected to Reactor Coolant Systems, dated June 22, 1988, and Supplements 1 and ? to the bulletin, required Consumers Power Company to review unisolable piping connected to the Reactor Coolant System to identify where temperature distributions could result in unacceptable stresses and to take action where such piping is identified. The bulletin also required written confirmation that the actions have been completed. A description of the results of the review are provided below:
A review of systems connected to the Reactor Coolant System (Primary Coolant System - PCS) at Big Rock Point, was performed. Concerns identified by the bulletin were considered during the system evaluation.
Based on industry experience, the Nuclear Regulatory Commission identified the potential for thermal fatigue in unisolable stagnant piping connected to the PCS, Specifically, undesirable stresses resulted when water, which was significantly cooler and at higher pressure than the primary system, leaked through normally closed valves into a stagnant portion of the PCS. The subsequent temperature stratifir .,.9 produced thermal stress cracking in the immediate area.
For the purpose of this evaluation the area of interest was considered to be all primary system ASME Class 1 piping. Interfacing systems within this boundary were reviewed. Vents and drains as well as O' passive piping, such as instrument and sample lines, were considered not applicable and were excluded from the evaluation. Three systems were determined to fall within the criteria of the stated concern.
These systems and their potential to initiate thermal stresses as described in the bulletin are addressed below.
. Feedwater System (FWS)
This system is an extension of the PCS. Its design and operation considers the injection of cooler, high pressure water into the primary system. The results of our evaluation has determined that temperature stratification will not occur at the system interface, therefore, the Feedwater System is not subject to the concerns stated in the bulletin.
. Liquid Poison System (LPS)
This system is designed to inject a sodium pentaborate solution into the PCS. The solution is maintained at-a higher pressure and cooler temperature than the PCS. Leakage into the PCS is not probable by design. System inlet and outlet are provided'with positive acting squib valves which preclude inadvertent leakage.
Additionally, the inlet is supplied by a check valve to prevent reverse flow, while the outlet includes a control valve capable of isolating LPS injection. The LPS piping is designed to O. operate at the same pressures and temperatures as the primary system. Any leakage of solution into the primary system would be 5.2-19
Revision 3 i
readily detectable as a result of the negative reactivity effects of the sodium pentaborate as well as various alarms associated (a) with the system. The results of our evaluation has determined that temperature stratification Will not occur at the system i
interface, therefore, the Liquid Poison System is not subject to :
the concerns stated in the bulletin.
. Control Rod Drive Systeni (CRQ1 Various CR3 system flow paths operate at higher than reactor pressure. The two flow paths of interest are the-cooling path through the CRD mechanisms to the bottom of the reactor and the return line to the PCS utilized during control rod manipulation.
The cooling line is adjusted to reactor pressure )1ut. 30 psi. It provides 0.1 gpm to 0.5 gpm of cooling water to tie control rod drive to prevent temperatures from exceeding 250'F.- The cooling water passes through the drive mechanisms into the bottom of the reactor vessel. The reduction of thermal stress established by -
this flow is an inherent design of both the system and reactor vessel. In addition, the CRD mechanism is capable of being isolated.
The return line provides a path for displaced hydraulic water during the normal manipulation of a control rod drive. Its pressure is adjusted to reactor pressure plus 200 psi. It discharges into the return line of the Reactor Cleanup System. A-thermal-sleeve is installed at this branch connection with the cleanup system because of 3revious concerns similar to those-raised by the bulletin. Tils design consideration precludes establishing the conditions needed to induce cracking. In addition, this piping is capable of being isolated by various valves. The results of our evaluation has determined that temperature stratification will not occur at the system interface,-
therefore, the Control Rod Drive System is not subject to the concerns stated in the bulletin.
Conclusion In conclusion, it is determined that for all systems evaluated, either thermally induced stress was a design consideration, or the conditions needed to initiate cracking as stated in NRC Bulletin 88-08 does not exist. Subsequently, and in accordance with the-direction provided by the bulletin, no additional action is required.
O 5.2 20
Revision 3 I 5.4.1.2 Load Re_1ection/ Automatic Recirculatina Pumo Trio in November 1990, Consumers Power Company installed a reliability O based RPT scheme designed to trip one selected reactor recirculation pump upon either a turbine load rejection or high reactor pressure condition resulting in emergency condenser o)eration. The intent of thi. modification is to lower reactor power )y approximately 40% and place the reactor at a power level near that for which a successful l load rejection has been demonstrated (-38 MWe) and by computer I modeling, indicates that tripping of one recirculation pump has a beneficial effect on keeping feedwater available during such ,
transients. '
Automatic tripping of one reactor recirculation pump acts to 1) I lower the reactor power and associated steam flow to the turbine / main condenser, 2) lessen the perturbations in the main !
condenser associated with load rejection and 3) reduce feedwater flow requirements. These three resultant action tend to eliminate secondary side instabilities inherent to load rejections occurring at higher power icvels.
The intent of the second feature of this scheme (ie, tripping of one reactor recirculation pump upon emergency condenser operation) is to reduce reactor power as an anticipatory action following reactor scram in the event that a multiple rod insert failure has occurred.
The automatic tripping of one pump supplants the correct operator action to reduce reactor power in a more rapid fashion, thus, giving the operator more time to combat this scenario. This change was O completed via FC-664.
On June 17, 1992 theNRCgrantedanexemptionfrom10CFR50.62(c)(3) /
which required that a alternate rod injection system be installed at /
all boiling water reactors. The exemption was based in part upon the /
installation of the recirc pump trip modification. /
5.4.2 STEAM DRUM AND STEAM DRUM REllEF VALVES The steam drum, with its piping, is mounted high up inside the enclosure to perform the following functions:
Separate the steam from the steam water mixture generated in the reactor core. The design criteria calls for drum exit steam quality of 99.9%.
Provide water storage to accommodate surges of water level and pressure between the reactor vessel and the drum.
Provide natural circulation driving head to maintain flow in case the recirculating pumas are inoperative. It has been calculated that it will be possi)1e to run at over 50% load on natural circulation alone with both pumps inoperative but free to rotate.
Assure net positive suction head for the recirculating pumps to meet their design requirements. Drum water level is 65 feet above the O- center line of the pump suctions. The static head is sufficient to maintain flow during normal operation without pump cavitation; during transient conditions limited pump cavitation may occur.
5.4-6
~ . - - - - _ ______ - __ , __ _ . . _
Revision 3 CHAPTER 5 REFERD(Cl$
em b 30. NRC letter dated September 10, 1982, BRP-SEP Topic V-10.B. RHR Reliability, V II.8, RHR Interlock Requirements and Vll 3, Systems Required for Safe Shutdown (Final Evaluation).
- 31. NRC letter dated Decemba;r 15, 1982, $EP Topics V-11.A, Requirements For Isolation of High and Low Pressure Systems and V-11.B. RHR Interlock Requirements (Revised Final Safety Evaluation Report).
- 32. NRC letter dated October 27, 1982, Resolution of NUREG 0737 Item ,
ll K.3.25, Effect of Loss of AC Power on Pump Seals (NRC Safety Evaluation).
- 33. NRC letter dated January 25, 1988, NRC Position on IGSCC in BWR /
Austenitic Stainless Steel Piping. /
- 34. CPCo letter dated July 25, 1988, Response to Generic letter 88 91. /
- 35. NRC Request for Additional Information (RAI) dated April 18, 1989. /
- 36. CPCo letter dated June 23, 1989, Response to a Request for /
Information (RAl) concerning Generic letter 88-01. /
- 37. NRC letter dated December 11, 1990, Request for Additional Information /
concerning Generic Letter 88 01. /
O /
Q 38. CPCo letter dated February 14, 1990,- Response to a Request for Additional Information concerning Generic letter 88 01. /
- 39. CPCo letter dated May 24, 1991, Response to Generic letter 88-01. /
- 40. NRC letter dated August 1,1991, Staff Review / Safety Evaluation /
of Big Rock Point's IGSCC Inspection Program. /
- 41. CPCo latter dated July 24, 1991, Updating the IGSCC Inspection /
Program. /
O 5.4-44
Revision.3 a
handling accident, by causing rapid containment ventilation isolation which thereby reduces the offsite release to well below 10 CFh 100 limits. Further information concerning " Radiological Consequences of Fuel Damaging Accidents," is located in Section 15.7.1 of this Updated FHSR.
Operability Reouirements Requirements for closure of the two 24 inch ventilation. openings -
within 6 seconds on high radiation at either of two--area monitors in the fuel storage area were added by Technical Specification Amendment ,
dated October 9, 1981 in response to Three Mile Island (TMI-2)
Lessons Learned. .
Information on these monitors is provided in Chapter 11 of this /
Updated FHSR. These monitors provide gamma monitoring of the fuel storage areas and refueling operation.
In the event that both of these monitors become inoperable during power operation or fuel handling activities, the containment ventilation isolation valves shall be closed.
The High Radiation trip closure of the containment ventilation isolation valves will be routinely tested as required in the Technical Specifications.
6.2.4.1.9 [_ontainment Vacuum Relief The original plant design utilized only one vacuum relief path. The ,
system was modified (via Facility Change FC-425) to provide a secondary vacuum relief path and to eliminate single failures that existed in
+he single vacuum relief scheme. Containment vacuum relief is provided to prevent excessive external aressure on the containment sphere due to atmospheric changes or otler causes, the two valves in the ventilation supply line and the two valves in the ventilation exhaust line will automatically open and stay open whenever the differential pressure exceeds 1 psid, overriding all other signals.
The valves will reclose when the internal pressure is still slightly below atmospheric. Therefore,-if the vacuum relief feature actuates, the air flow would be into containment and no external release would occur.
The containment design ratings and vacuum relief set points are provided in Section 3.8.1.3 of this Updated FHSR as are the operating requirements for the bottled nitrogen provided for emergency operation of the ventilation valves in.the event of loss of instrument air.
CPCo internal analyses indicate that vacuum relief is necessary for-0.63 ft', 0.05 ft , and 2
for 50 and 75 lb/sec. ' Steam Line Break from the combined effects of enclosure spray actuation from heat transfer during post-accident cooldown. (Reference Action Item Record A-NL-85-17.)
l 6.2-24
a ,
' Revision 3!
.j u
g =.
S'~# D Containment Automaticilsolation_ ValvesLinclude valves inithec ^i l 1 Jventilation system which have dual automatic: functions of ,
- isolation directlysinhibiting a: radiation release, and. ant . -
pyerriding function of opening for containment:high vacuum to d
. protect the containment structure. The circuit design for=
opening by operator action following isolation _ closure presently. meets- the-subject bulletin's criteria (refer to CPCo -
. letter to the NRC dated November 29,1978).,!Since-vacuum-relief might be required following condensing ~of steam during aL o i
LOCA, it would not be appropriate..to modify-this equipment to require _ manual switch action.:
The Containment Automatic Ventilation Isolation valves will; automatically reclose when the vacuum 1 signal-is no longer -
j present.
The off-gas isolation _ valve will1 return to the open position: ;)
following a reduction of the high' radiation ~ initiating-signal-only _if_ the trip reset on the-initiating monitor is manuallyj reset. -The off-gas _ isolation valve does not have a: manual .-
control switch.' The intent of this equipment, as stated in;the original FHSR,- Section-12.5.11', was to cause automatic shutdown:
in order to7 keep personnel expos'ure at acceptable limits.= w' Technical: Specification Amendment 14, dated June 21,1977:
modified the-requirement to cause shutdown.and. substitutes- "s greatly reduced radiation-limits and administrativo: shutdown ofc
' the plant. Thus, it is not deemed _necessary to modify the-circuit to provide an additional reset feature, o
Equipment controlled by the high radiation monitor are:
Major Equipment - SV-4857 for off-gas isolation valve CV_-
4015
. Associated Equipment - Alarn forloff-gas timer:
-Drain lme. valves in off-gasi is01ation : system SV-4868'for CV 4030 -
SV-4872'for CV-4035-SV-RL27 (Drain to. turbine-sump) . ..
SV-4938 (Drain,to.radwaste sump): ;/L x
. . Action Recuested
-2. Verify the actual installed instrumentation and controls at the facility are consistent with the' schematics reviewed in: Item _1 above by conducting:a test.to demonstrate that all equipment-remains- in its emergency mode upon removal = of the actuating = +
signal and/or manual . resetting of thel various isolating _or-actuation signals.
6.2-30
Revision 3 line are commanded to open. The valves receive a signal to open when there exists a coincident trip signal of reactor low water (s 2'9" above the; top of the active fuel) and reactor low pressure (s 200 x' - psig. The diesel driven and the electric fire pumps provide water /
for core spray (reference Section 9.5.1 of this FHSR for fire pump /
design specifications). Both of the fire pumps can provide the ECCS /
specified pressure and flow rate. The primary (spray ring) system is
_ /
designed to deliver 400 gpm flow at-a nozzle-pressure of 115 psia.- /-
The backup (nozzle) system is designed to deliver _470 gpm at a nozzle pressure of 115 psia.
The minimum acceptable bundle spray flows are indicated in Amendment 26 to the Operating License, dated April- 10, 1979. The minimum spray-flows are based on conservative estimates of the highest bundle radial peaking factor and worst reactor vessel pressure conditions.
Under the most limiting conditions, the ring spray provides 292 gpm /-
and the nozzle spray provides 296 gpm to the core at a reactor - /
pressure of 75 psig. A test program was undertaken to demonstrate /
both the nozzle spray and ring spray flow adequacy and acceptable /
performance characteristics (Reference CPCo submittals dated /
March 28, 1979 and August 9, 1977, results of NUS Corp core spray tests). The tests performed resulted in an optimized core spray sparger aiming pattern which delivered maximum bundle spray flow at all LOCA usage conditions. Two bundles received flows slightly below the minimum acceptable spray flow limit. However, the Technical Specifications specifying maximum bundle power was developed with sufficient conservatism to ensure that the reactor will operate within the capability of either the ring or nozzle spray. Among the conservatisms incorporated into the calculation of maximum bundle iO power were use of.a power reduction factor of 1.2 to lessen the calculated bundle power, the assumption of no core spray flow until time of rated spray is reached, and the assumption that all buqdle power at the time of rated spray must be removed by vaporization (Reference Amendment 26, April 10, 1979).
An evaluation of the Big Rock Point Emergency Core Cooling System /
(ECCS) MPR-557, MPR Associates, August 1977 (resubmitted by letter /
dated July 25, 1979),.was performed to determine the hydraulic /
performance of this system under various LOCA conditions. This /
analysis is the basis for all subsequent BRP ECCS analyses. An /
internal analysis (Reference EA-BRP-ECCS-88016-GFP, September 21, /
1988, of Deviation Report D-BRP-86-150) evaluated RDS valve /
differential pressure operation in relation to ECCS flow require- /
ments. This analysis concludes that the ECCS is adequate based /-
on a differential pressure of 35 psi between the reactor vessel /
and containment. The most limiting flow condition in this /
evaluation is governed by failure of the diesel fire pump. /
The above analysis indicated that rated core spray occurs below /
reactor pressures of 65 psig (ring) and 64 psig (nozzle) rather than /
75 psig as previously used; this only affects time to reach rated /
spray since the flow requirements remain the same. For analyzed /
breaks of .244 f t' and smaller the time to rated core spray is /
O limited by reactor pressure; for breaks of .375 ft and larger /
V the time to rated spray is governed by the core spray valves' /
opening times. The additional time required to reach rated spray /
6.3-4
Revision 3-flow for breaks .244 ft' and smaller is not significant to cause /
-F additional fuel damage, The .375 f t' break was shown to be the /
( limiting break with peak' clad temperature determined to be 2138'F /
(Reference XN-NF-78-53 submitted July 25,1975) while the peak /
clad temperature for the .244 ft' break was calculated to be /.
180l*F. In the long term, reactor pressure will not exceed 55 psig /
prior to subsequent operation of RDS valves, based on-a containment /
3ressure of 20 psig and a RDS differential pressure of 35 psid /
3etween containment and the reactor vessel. /
An internal analysis performed subsequent to MPR-557 described above indicated that rated core spray occurs at a reactor pressure of 65 psig (ring) and 68.8 psig (nozzle) rather than 75 psig- This does not affect the time to rated core spray flow for analyzed breaks of -
.375 ft' and greater since the time to rated flow for large breaks-is governed by the core spray valves opening times. The .375 f t' break was shown to be the limiting break with peak clad temperature determined to be 2138'F (Reference XN-NF-78-53 submitted July 25,1975). For the next smallest analyzed break (.244 ft') and all smaller breaks the time to rated core spray becomes limited by reactor pressure.
The peak clad temperature for the .244 ft' break was calculated to be 1801*F. Internal analysis indicates that by assuming rated ring spray flow takes place at 65 psig rather than 75 psig the time to rated flow will increase by 1.65 seconds. In the short term prior.to the initiation of the RDS the additional heat-up occurring in the fuel during the 1.65 seconds should not jeoparidize its integrity any further. In the long term, following RDS blowdown, containment O' pressure will remain less than or equal to 15 psig. With RDS initiation occurring upon a differential pressure of 50 psi between containment and the reactor vessel, reactor pressure will not exceed 65 psig prior to the onset of RDS and the reactor core will experience rated core spray flow.
6.3.1.3.2 Core Sorav Recirculation To mitigate the effects of a loss-of-coolant (LOCA) accident, the core spray system brings water from the plant fire protection system to the sparger ring and the nozzle array within the reactor and sprays water directly on the core. In order to-protect the containment sphere from increasing water level, transfer from the injection mode to the recirculation mode of emergency core cooling occurs when level in containment reaches 587'. Because Big Rock Point does not have the capability of automatic transfer, switchover to recirculation cooling is actuated manually from the control room. In the recirc-ulation mode water to the sparger ring and nozzle array is provided -
by two core spray pumps. Water addition to.the containment sphere is manually stopped before the accumulated water level reaches an elevation of 596', above which containment integrity-could be jeopardized by reaching a stress limit (reference NRC Safety Evaluation Report for Systematic Evaluation Program (SEP) Topic VI-7.B ESF Switchover from Injection to Recirculation dated May 20,1982).
6.3.1.3.3 Enclosure Soran L The enclosure or containment spray system serves to maintain containment temperatt.res below the Electrical Equipment Qualification (EEQ) 6.3-5
)
Revision-3 temperature envelope in the event of a LOCA which releases steam to containment. Containment response to a LOCA was calculated using a computer code that models the containment sprays by removing from^a Os superheated atmosphere that quantity of energy required to raise the 70*F spray water to saturate steam at containment conditions.- A delay ,
of 75 seconds was assumed to account for starting of the fire pumps and-
- filling of the spray line. A spray flow of 50 gpm was chosen to establish minimum flow. Computer calculations show a 50 gpm spray flow is sufficient to cool the superheated atmosphere. The computer code used modeled containment as a single compartment. However, the steam drum cavity is actually a separate room with a leakage -area of approximately 100 square feet to the rest of containment. Since nearly all steam lines are located within the steam drum cavity, a steam-line ,
break is more probable ir, this area. The net effect of this is that for a total spray flow of 50 gpm the temperature outside the steam-drum cavity will be less than predicted by the single compartment model while those temperatures inside will be somewhat greater than predicted. The atmospheric temperature following a large steam line break will exceed 235'F for less than two minutes. For this short period, the thermal capacity of vital equipment within containment is considered sufficient to assure their operability for the period required. It should be noted that containment air temperatures exceed 235'F only for the hypothetical large steam line break and not for the more probable small breaks (Reference CPCo December 5, 1980 submittal). Hydraulic analysis of /
the ECCS result in containment spraws of more than 50 gpm to areas /-
of containment both inside and out.ide the steam drum cavity /
(reference EA-BR-ECCS-88016-GFP, September 21,1988). /
For small steam line breaks with flows of 50 lb/sec or less containment pressure will not reach the containment high pressure trip setpoint of 1.0 psig due to the containment ventilation system which acts to maintain containment pressure. For this class of breaks the reactor must be manually scrammed and containment sprays manually initiated.
Containment response to this size break is addressed in Section 6.2.1,3,4 of this Updated FHSR. The analysis and containment response took no credit for operator action before 10 minutes after onset of the break. Reactor coolant-pressure boundary leak detection components are addressed in Section 5.2.5 of this Updated FHSR. The operator is-expected to take appropriate action based upon the leak detectors and alarm settings in the event of a leak.
In addition to these indications, the operator would probably hear the small break; particularly if the break were large enough to cause rapid heating of the containment and still not cause automatic containment isolation (ie, 50 lbm/sec steam leaks). For breaks of this size, containment air and dew point temperatures both inside and outside the steam' drum cavity would rise very rapidly causing an immediate high-temperature / dew point recorder alarm labeled " Containment Building High-Temp.", on the control room front panel. The loss of-steam to the turbine would result in an approximate reduction of 10 MWe in turbine generator output and partial closing of the turbine control valves. These changes would result in step changes on the steam flow and turbine cam position charts.
Feedwater flow would probably stay the same. The operator would respond at once by noting the chart readings and power output of the 6.3-6
. _ _ .- .~ m _ _. m . .. _ ._ _.. .. .
> Revision 3
.t generator._ With the control panels'and console situated asuthey are in ;the control- room.at Big Rock Point, a11' indications can;be seen p from one: location, iThe farthest distance between charts is about 20-V feet. .. The containment pressure indicator as Lwellias;the control, switches: for scram, emergency. condenser, and enclosure-spray are within five feet; therefore, the actual- time.to perform necessary actions would be short and well within 10 minutes. .
Nevertheless, no credit-is taken for operator action before110- . ,
minutes and the results of this action at 600-seconds is depicted on Figure 3-4 in Chapter 3 of this Updated FHSR.- ,
The containment sprays were originally expected to function as. a'-
means to provide iodine washout. Analysis has' indicated, however, that post-LOCA dose rates are less than 10 CFR 100 thyroid exposure' ~i limits even when no credit is taken for washout.by containment: sprays (Reference CPCo Submittal dated June' 2,1982- for Systematic Evaluation '
Program (SEP) Topic'XV-19). As'such, containment sprays are no-longer assumed to provide an iodine washout function and secondary ,
sprays are activated in the event of a failure of the primary spray-system. <
6.3.2 SYSTEM DESIGN [
6.3.2.1 Component Description 6.3.2.1.1 Core Sorav
.h As indicated previously, water for-the core . spray system.'is.provided by the Fire Protection System. A description of the fire pumps is given in Section 9.5.1 of this Updated FHSR. The two: isolation valves located in the primary core spray line are de motor operated valves which can be operated manually from the control room. .-The two .
backup core spray isolation valvas-are ac motor operated valves and q can also be manually operated trom the control rocm.-
The core spray sparger is constructed of two inch diameter: Type 316;
- stainless steel piping. It is octagonal in; shape and clamped to the reactor vessel steam baffle assembly. The sparger ring _contains 36--
nozzles aimed at the core.
The nozzles attached to the sparger are 15'tinjector type full jet nozzles. The nozzles were-originally designed to use an interior-spinner. However, to prevent jamming or locking 'oflthef spinners -
during operation, the spinners were tack welded in:a.setiposition. .
.In addition,.the exit' orifice of=each nozzle was reamed to:0,221 inch .
diameter. For further details, refer to CPCo. March 28, 1979. submittal and Facility Change FC-464.
The core spray nozzle array through which the backup core spray'-line:
provides water to the core is1 based upon a multiple nozzle concept.
The nozzle ~ assembly consists of twelve identical one inch nozzles.
The twelve one inch! nozzles are arranged in two concentric circular '
.3 arrays. The outer array consists of eight nozzles each mounted in a 90' street ell. The street ells are equally spaced around a plane circle protruding from a central hub-type manifold. The nozzles are 6.3-7
f Revision'3; threaded intolthe street ells and tack welded.to lock them against? .
4 rotation. Each nozzle is aimed in a-clockwise direction lookings y down, and elevated to an angle of 55' from.the vertical axis using
~- ~
the' face of the nozzle -as a reference.- l The ells are' tack welded to.:
the manifold to lock them against rotation. The: central array 9' consists of four nozzles ~ mounted tangentially' int a circle with a- - - -
- diameter of- approximately three inches. These nozzles are?also aimed in a clockwise direction and elevated to anLangle of 25' from the *
-- vertical axis, _The four central nozzles are also tack welded tot prevent their. rotation. For further. details refer to,CPCo August 9.- '
1977-Test Report and Facility Change.FC-444.
6.3.2.1.2 [ pre Soray Recirculation Long-term post-accident cooling will be'provided by two core spray pumps. The pumps which take suction from the lower' levels of .
containment are vertical-centrifugal four-stage pumps.which'each have 'a capacity of 400 gpm at a head of 324 feet at 140 ps,ig. They are' equipped with 50 hp, 480 V motors. Each pump has the ability tocprovide-core cooling under post-accident conditions and-as such only one pump would be in operation at any time.
The core spray recirculation flow path consists of only:non-electrically operated check valves. Therefore, during: power operation:the core spray l recirculation system is normally pre-aligned for' service such thatt recirculation flow will begin whenever one.of the core spray pumps is-started (reference Systematic Evaluation Program -(SEP)_ Topic-VI-7. A.3 -
Safety Evaluation dated August'20, 1982). !
The core spray pumps discharge to a heat exchanger with-a-two-cross flow-pass on the shell side with four passes on the tube: side. It is. .
designed for a pressure of 210 psig on-the tube side and'150 psig shell-side both at a design temperature of 235 degrees. The inlet line of the heat exchanger is equipped with a pressure switch and-alarm which sounds at 50 psig to warn the operator of low discharge pressure on the core -
spray pumps.
6.3.2.1.3 Enclosure Sorays As is the case with the core spray system, enclosure spray water is provided by the fire protection system. The primary spray isolation valve is an automatic de motor ~ operated valve.- Upon o)eningiof the isolation valve, spray to the containment will- occur t1 rough;six spray nozzles lo::ated on the primary enclosure spray header. -The: nozzles will-provide a hollow-cone spray pattern with uniform distribution. In the-event that the primary spray headerLfails to provide spray. flow to:
containment, the secondary spray isolation valve, a: remote manual-ac =
L motor operated valve will be opened from:the control: room. The
- secondary enclosure spray header als'o contains six' nozzles. Five of-the.
! nozzles are identical in design.to those found:on the primary header.;
i, The sixth' nozzle on.the secondary header is a fog nozzle set to provide L a solid: 20' conical fog spray. The fog nozzle-is located on-the northi
! side of the header.
'q' Two spray nozzles common to both headers are located inside the . steam
.-.Q drum cavity. The nozzles are of a one piece body construction and will-provide a full cone spray pattern-(reference Facility Change FC-515)..
These sprays are depicted on Drawina-0740G44008.
[ 6.3 ,
Revision 3 n
8.3.3.3 Thermal-Overload Protection for Motors of M0V's /
b SEP Topic Ill-10. A " Thermal-Overload Protection for Motors of Motor-Operated Valves" was evaluated for Big Rock Point to provido assurance that the application of thermal-overload protection devices does not result in needless hindrance of the performance of valve safety functions.
In a letter (Reference 21), CPCo justified the present design for most M0Vs on the basis that they are not required to function during an accident. For the remaining six (6) valves listed below, modifications' were completed via facility Change FC-573 which permits bypassing of the thermal overloads during normal operation. Taermal overload circuits are administrative 1y controlled to only be in service during surveillance and testing.
M0-7052, M0-7062: Emergency Condenser Inlet Valves M0-7070, M0-7071: Back-up Core Spray Valves M0-7066, M0-7080*: Firewater to Core Spray Heat Exchanger M0-7068: Back-up Containment Spray Valve
- This valve was added via Facility Change FC-578.
p Accordingly,-the staff concluded that Big Rock Point satisfies the
( current licensing criteria for safety-related valve functions (Reference 12).
8.3.4 EMERGENCY DIESEL GENERATOR 8.3.4.1 Description The Emergency Diesel Generator (EDG) provides three phase 480 volt ac emergency power to the 480 volt ac emergency bus, MCC-2B, to support essential loads in the event of a loss of off-site power. Equipment in addition to those on the 2B bus can be powered from the emergency diesel generator via selective manual breaker manipulations.-provided that the emergency diesel generator output rating is not exceeded.
The emergency diesel generator output can be manually disconnected from the 480 volt emergency bus MCC-2B and connected to the alternate shutdown system should the 2B bus become inoperable due to fire.
This transfer is accomplished via a manual transfer switch located in -
the emergency diesel generator room.
Provisions for full load testing of the emergency diesel generator are provided.
The diesel engine is rated at 319 horse power at 1800 rpm. The generator has a full load rating of 200 kW (ie, 250 kVA at an 80 i percent power factor) at the rated generator speed of 1800 rpm. A ;
static exciter is an integral part of the generator, providing.18.5 l
.l 1
8.3-5
g \
- Revision-3; g
~
- 3. - By verifying that each pump;will develop a flow of atjleast 10002 3
O gpm atia:systemt head of-llo: psi .
V 4.. - Sebjecting the diesel driver to an;: inspection in- accordance withi k '
' procedures prepared;in connection with its manufacturer's recommendations for the classLof service.: - -
- e. Once' per 3 years;by 'performingz flow tests toimeetEor: exceed: the:
< requirements of. Section 11, Chapter,5 of the= Fire: Protection! -
- Handbook,14th Edition published by National Fire Pr_otection Association. -
Fire Sucoression System Bases ,
The operability of the fire su pression systems ensures that adequate firei suppression capability is avai able to confine:and extinguish fires occurring in-any portion of the facility where safety related-equipment is located. The fire suppression system consists'.of the water system, s 3 ray and/or sprinklers, and fire hose-stations.; The coll _ective capa)ility of the fire suppression-system-is adequate' to-minimize potential damage to safety-related equipment and;is a majorf element in_the facility-fire protection program..
- In the. event that-portions of the fire suppression system are inoperable, alternate backup fire fighting equipment is required tof ,
be made available in the affected areas until the : inoperable equipment ;
is restored to service.
In the event the- fire ' suppression water system becomesiinoperable, a immediate corrective measures must be taken since this-system provides:
the major fire sup)ression capability of the plant. The requirement '
for a twenty-four 1our report to the Commission provides:for prompt' adequate: fire suppression capability for the continued protection of 1 the nuclear' plant.
In the case of_ the core spray system,1 water _ flow from th~e fire suppression .
suppression system for fire suppression or_ for. normal usesvand: testing fori +
which the time and flow are restricted has a negligible effect on availability and is.not a cause for declaring the system inoperable.
- 9.5.1.2.2 Fire'Pumos Both the electric and diesel vertical centrifugal fire pumps haveL a1 h rated capacity of 1000 gpm at 110 psig (254-foot head). L Appendix 1A, /"
Item E.2(e) of Branch Technical Position APESB 9.7;1"" Fire Protection /?
Water Supply Systems", requires that:the flow rate of:the fire' system.
./L c be calculated on the basis of the longest expected flow rate- for.a-
~
-: / .--
period of two hours, b_ut not less than 300,000 gallons 1(2500 gpm).. J/ *
- Since the largest open head deluge system:(Switchyard): requires ' '/c
-.1160 gpm at- 52 psig combined with .1000.gpm for. manualL hose streams - !/-
totals approximately:2160 gpm, the c500-gpm evaluation criteria is
~
/>
f
~
4 assumed.
M Y ,
9.5 ,
. - , ,..s- , , ( .,.y,
Revision 3 Each of the two fire water pumps'is capable of delivering /
approximately 1500 gpm at 72 psig. Therefore a combined pump flow /
r] rate of approximately 3000 gpm at 72 psig,-available from ' /
V Lake Michigan is considered adequate to meet this criteria. /
The pumps are separated by about 15 feet at their suction lines-in the screenhouse water bay and are separated by a sheet metal radiant energy shield.
An electric jockey pump and an accumulator are provided to maintain.
pressure on the fire water system. The fire pumps are arranged to start-automatically when the fire loop pressure drops due to a large water demand.
The diesel fire pump driver was replaced via facility Change FC-607 when parts could no longer be obtained for the original. This change was reported by CPCo letter dated January 9,1987.
Fire Pumos Sinale Active Failure Analysis There are two redundant fire pumps, one electric driven pump and one diesel driven pump. A single failure in either pump, driver, power
- upply, discharge check or isolation valve will not affect the redundant pump. A failure of a discharge check valve in the open position will bypass flow from the other pump and may require manual closure of the associated isolation valve, c Certain fire operability, surveillance, and bases requirements for
( operation are addressed under the Fire Suppression System in 9.5.1.2.1 above.
IE Bulletin 79-15: Deep Draft Pumo Deficiencies In letter dated October 17, 1990, the NRC provided a safety evaluation which concluded that safety concerns regarding the two Worthington fire pumps installed at Big Rock Point were resolved. A review of test data collected from the past five (5) years showed no signs of performance degradation in either pump thus providing the basis that the Bulletin 79-15 deficiencies did not adversely impact these pumps.
Diesel Fire Pumo Surveillance Reautrements l The fire pump diesel starting 24-volt battery bank and charger shall be i
demonstrated 0PERABLE:
l-
- a. At least once per 7 days by verifying that:
- 1. The electrolyte level of each battery is above the plates, and i
- 2. The overall battery voltage is ;t 24 volts.
- b. At least once per 92 days by verifying that the specific gravity is appropriate for continued service of the battery.
- c. At least-once per 18 months by verifying that:
- 1. The batteries and battery racks show no visual indication of
! physical damage or abnormal deterioration, and 9.5-8
4 Revision 3 g- can be accomplished when the individual performing the refueling
( will not receive a radiation dose in excess of 25 rem.
. Relocate the backup emergency diesel to the area near the well water storage tank. The post-accident dose rate in this area will allow the unit to be placed in service locally and refueled -
as needed.
. The fuel supply for the diesel-driven fire pump was converted from the original 275 gallon tank to the 1000 gallon tank which previously supplied the EDG.
The diesel fuel tank changes for the EDG and fire pump were accomplished-via facility Change FC-511A and relocation of the backup diesel generator was accomplished via FC-511c.
Drawina 0740G40123'provides details of the 5000 gallon EDG and 1000 gallon diesel fire pump fuel oil storage tanks.
The standby diesel generator is supplied from its own 600 gallon tank located inside the semi-trailer.
9.5.4.1 Emeraency Diesel Caperator (EDG1 Fuel Storaae level The EDG consumes fuel at approximately 16.5 gallons per hour (reference Special Site Test SST-17), when loaded at 190 1 10 KW.
O The 5000 gallon storage tank is assumed to have 8 inches of unusable /
D fuel level (reference Facility Change FC-511A), in the lower portion of the tank for a deduction of 295 gallons. Thus, with a full tank, /
4705 gallons are available which provides an approximate 11-1/2 day /
supply. The tank is refilled when about 3,554 gallons or an equvalent minimum administrative level of 50 inches remains. Thus, 3259 gallons are available which provides an approximate 8.2 day /
supply. These levels are well in excess of Standard Review Plan Guidance for a seven day total capacity, and Technical Specification requirements for a ten day total capacity and three day operating limit.
9.5.4.2 Diesel Fire Pumo Fuel Storace level The diesel fire pump consumes fuel- at approximately 6.4 gallons-per hour (reference Facility Change FC-607), based on manufacturers similarity testing report. The 1,000 gallon storage tank'is assumed to have 6 inches of unusable fuel in the lower portion of the tank for a deduction of 74 gallons. Thus, with a-full tank, 926 gallens are available which provides an approximate six day supply. The tank is refilled when about 554 gallons or an equivalent administrative level of 26 inches remains. Thus, 480 gallons are available which provides a three day supply.
For fire protection, only a te h ur supply is required (reference p
gl Appendix R to 10 CFR 50).
9.5-20
Revision 3-e overcurrent, utilizing two independent sensors and coincident logic, f while maintaining the engine overspeed trip as is.
Conversations with the emergency diesel generator manufacturer indicate that diesel generator destruction, under loss of oil pressure, would occur rapidly; therefore, the necessity to retain this trip is mandatory. Presently, there are two oil pressure sensing units in use in the dietel control circuitry, the original unit and-a redundant scheme added in 1971. By use of auxiliary and spare contacts a coincident logic scheme will be provided fer both of the low oil trip circuitries, and each circuit will utilize two independent sensors, (these changes were accomplished via FC-401). /
Because of past problems associated with high emergency diesel generator cooling water temperatures (Reference CPCo letters April 15, 1976 and June 9, 1976), it is prudent to retain this trip function.
In order to meet the Branch Technical Position an additional temperature switch will be installed in the diesel cooling water jacket. This switch will be connected in series with the existing temperature switch making it necessary for both elements to sense a high . temperature condition prior to diesel generator trip. This scheme meets the dual sensor and coincident and logic criteria, (an additional temperature /
switch was added via FC-401). /
The final trip that will be maintained is the overcurrent trip. The emergency power system at Big Rock Point is an underground three-phase O. system. Original design allowed a single overcurrent relay (single-phase fault) to trip the emergency diesel generator. This was modified (via Facility Change FC-401) to require a two-phase fault (phase-to-phase short) for a trip to occur. This would eliminate any trip caused by a single signal, such as a relay failure or single phase-to-ground short, but still prevent major damage should a dual phase fault occur. A time delay relay (installed via facility Change FC-670) is in series with the overcurrent trip network allowing a bus fault to clear, while maintaining the generator on-line.
Concerning the diesel driven fire pump, the only parameter that could -
cause a unit trip is engine overspeed which was not utilized on the original fire pump diesel driver and consequently was not connected on the new diesel fire pump driver installed via Facility Change FC-607, (reference Section 9.5.1.2.2 above).
The NRC evaluation and review of the protective trips was documented in Technical Specification Amendment 15 dated October 17, 1977 which concluded:
Based on our review, the modification to the emergency diesel generator are acceptable because they: (1) satisfy the criteria of BTP EICSB 17, (2) significantly enhance the reliability of the onsite power system, and (3) comply with Section (3)(iii) of the Memorandum and Order, dated May 26, 1976, s
9.5-24
. - , - - - - . . ,. - . - . - - ~ - . - - - .. . .. -
' Revision-3 An analysis of condenser hotwell/feedwater system' characteristics has been completed. As 'a result _of this analysis, a-modification-
' was installed _ in November 1990, to provide an automatic reduction-D in reactor power in the event of a. load rejection.. A reliability.
based recirculation pump trip scheme designed to trip'one selected reactor recirculation puma-(providing both are in service) upon-load rejection provides_t11s automatic power reduction.- Tripping:
of one reactor- recirculation lump will110wer reactor power by-approximately 40% and place tie reactor at a power level near that for which a successful load. rejection has been demonstrated..
Computer modeling-of the plant secondary systems indicate that tripping of one recirculation pump has a beneficial effect'on keeping feedwater available during such transients.
Automatic tripping of one recirculation pump acts to 1) lower the reactor power and associated steam flow to the turbine / main condenser, 2) lessen the perturbations in the main condenserr ,
associated with-lead rejection and 3) reduce feedwater flow ,
requirements. These three resultant actions tend to eliminate secondary side instabilities inherent to load rejections occurring at higher power levels. This change was completed via Facility =
- Change FC-664.
As an enhancement to the= recirc pump trip modification, .FC-680 was /-
initiated which replaced the then existing manual valve VTG-144:with _ /.
- automatically controlled CV-4136. The original purpose of VTG-144- /
-was to allow-an additional ~ amount of sealing steam for the turbine. /
seals in the event that leakage was in excess of theEsteam seal- -/
O t regulator capacity. During low. power o)eration (about 10 MWe or
.or less), the position of VTG-144 was slown to have Lan adverse
/
/
effect on condenser vacuum. To preclude a-loss of vacuum causing- /
a loss of the secondary side the manual valve was. replaced with an '/ s automatic valve-which receives a.close signal: upon a load-rejection. '/
/-
or closure of the main steam-stop valve.
10.2.5 TURBINE ROTOR DISC INTEGRITY AND_0VERSPEED PROTECTION An evaluation of the turbine-generator. was completed as~ part of-thel .,
Systematic-Evaluation Program (SEP) Topic _III-4.B - Turbine Missiles.
i Results-and conclusions in regard to turbine rotor integrity and __
adequacy of overspeed protection are-provided in Section.3.5 of this.
Updated FHSR along with the -turbine' rotor surveillance schedule basis.
10.2.6 TURBINE STOP VALVE-I The turbine emergency stop valve is an oil operated, spring closed.
valve controlled from the following devices: -
- 1. - Mechanical Low Vacuum Trip
- 2. -Electrical Trips
- a. Turbine. Thrust Bearing Failure
- b. Hand Trip in Control Room c.. Low Vacuum Switch
- d. Reactor Scram Auxiliary e.- Generator Lockout Relay 10.2-8
= -
Revision 3'
- d. Additional anion resin was added to improve-length of each run.
- (}
.v
- e. An additional air sparger was-installed to obtain better mixing in order to improve the low pH of the effluent.
In addition, Facility Change FC-642 was completed in 1992 to provide /
better system reliability. This modification added numerous flow /
meters to allow more accurate flow control and added two (2)- /
pressure sensors to supplement predictive maintenance of system /
piping. /.
Domineral.izer Resin Carryover The December 24, 1965 Semi-annual Report Number 3 stated that in-an -
effort to eliminate all possible avenues for inadvertent entry of demineralizer resins into the primary system, the following strainers were installed (Reference Facility Changes FC-33, 34, 35 & 36):
- a. A "Y" strainer in the demineralized waterline to the clean-up demineralizer, ,
- b. A "Y" strainer in the inlet line to the clean-up demineralizer.
- c. A strainer in the demineralized water supply line to the sphere,
- d. A strainer in the " treated waste" line to the sphere.
Make-up Water Control System The water levels in the demineralized water and the condensate storage tanks are indicated locally and in the control room with abnormally high or low level annunciated on the main annunciator panel. High level in the demineralized water tank also closes the raw water supply to the make-up demineralizer.
The make-up demineralizer system is arranged for manual or automatic start with automatic shutoff at high level in the storage tank, as noted above. Automatic shutoff also occurs at high effluent conductivity or completion of a preset flow cycle, either of which indicates a requirement for regeneration of the demineralizer bed.
Instrumentation for the make-up demineralizer system is provided on a local control panel, on the turbine operating floor. -Regeneration is arranged for manual start with automatic regeneration cycle shutoff and employs a conventional technique using sulfuric acid and caustic soda as regenerants. Full flow regulation in the make-up water to the demineralizer is accomplished by remote manual control from the local demineralizer control panel.
Pressure Vessel Desian O
V Pressure vessels for this system are designed in accordance with the-ASME Boiler and Pressure Vessel Code for 75 psig at 90*F.
10.4-12
i -Revision 3 13.1- 0JGANIZA110NAL STRUCTURE 13.1.1 MANAGEMENT AND TECHNICAL SUPPORT ORGANIZATION The offsite organization for management and technical support is described in the " Consumers Power Company Quality Assurance Program Description for Operational Nuclear Power Plants, CPC-2A," which is
" Incorporated by Reference" as part of this Updated FHSR, as described in Chapter 17.
The offsite and onsite organization are further described in the
" Big Rock Point Plant Technical Specifications," which is
" Incorporated by Reference" as part of this Updated FHSR, as described in Chapter 16.
13.1.2 OPEPATING ORGANIZATION RESPONSIBILITIES The Plant organization is depicted on Fiaure 13.1, and the following provides a general discussion of responsibilities:
The Plant Manager is responsible for overall plant safe operation and has control over those onsite activities necessary for safe operation and maintenance of the plant. He will delegate in writing the succession to this responsibility during his absence.
The Operations Superintendent is responsible for plant /
operation. The Engineering Superintendent is responsible /
for mechanical / civil and electrical engineering, security and a new procedure development / upgrade group. The Maintenance Superintendent is responsible .for mechanical / electrical and instrumenta'. ion and control. maintenance, material services and outage planning and scheduling. The Chemistry / Health Physics Superintendent is responsible for radiation protection, plant chemistry, radioactive wastes and emergency planning. The Technical Engineer is responsible for Plant licensing interfaces.
The Reactor Engineer is responsible for the reactor engineering :/
and Probabilistic Risk Analysis groups. The responsibilities- /
of others reporting to the Plant Manager are self explanatory.
The Shift Supervisor will be responsible for the shift command
-function. A Management directive to this effect will be issued annually by the Vice President - Nuclear Operations.
13.1.3 QUALIFICATIONS OF NUCLEAR PLANT PERSONNEL Staff qualifications are established consistent with the intent of ANSI Standard 18.1-1971 and are described in the Plant's Administrative Procedures.
- a. Each member of the plant staff will meet or exceed the minimum qualifications of ANSI N18.1-1971 for comparable positions.
13.1-1
Revision 3
- b. The Chemistry and Health Physics Superintendent will meet- /
or exceed the qualifications of Regulatory Guide 1.8, September _-
1975. For the purpose of'this section, " Equivalent," as utilized in_ Regulatory Guide-1.8 for the bachelor's degree requirement, may be met with four years of any one or combination of the following: (a) Formal schooling in science engineering, or (b) operational or technical experience /trainirg in nuclear power.
- c. The On-Call Technical Advisor _ (OTA) will have a bichelor's degree or equivalent in a scientific or engineering discipline with specific training in plant design, and response and analysis of the-plant for transients and accidents.
- d. The Operations Superintendent will hold an SR0 (Senior /
Reactor Operator License) and meet or exceed the minimum qualifications of ANSI-N18.1-1971 for the comparable position of Operations Manager. An SR0 License is required /
to be responsible for directing the activities of _ licensed -
operators.
13.1.4 PLANT ADDITIONAL SUPPORT A. To support the Plant Organization shown on Finure 13.1, personnel q knowledgeable in the following areas identified in ANSI N18.7-1976/
v ANS 3.2 will report at-the discretion of the Plant Manager:
- 1. Nuclear Power Plant Mechanical, Electrical and Electronic Systems
- 2. Nuclear Engineering
- 3. Chemistry and Radiochemistry
- 4. Radiation Protection (Reports to Chem /HP Superintendent)
B. Quality Assurance / Control activities will be in accordance with Consumers Power; Company's Quality. Program Description /.
for Operational Nuclear Power Plants, (CPC-2A, as revised),
(reference Chapter 17 of this Updated FHSR).
C. The Security Force will be supervised as described in the Security ~
Plans (reference Section 13.6 of this Updated FHSR).
D. Fire Protection responsibilities for the Plant Fire Protection Program implementation are as described in the BRP Fire Plan and the Fire Protection Summary - BRP Plant Manual. Refer to Section 9.5.1 of this Updated FHSR.
pd 13.1-2
- a o ; Revision 3-D -e. All core alterations, after the' initial fuel loading,;will either!
M be:' performed by a licensed Reactor Operator under the general.
supervision ~of a Senior Reactor Operator or a nonlicensed Operator directlyzsupervised by a-licensed Senior Reactor Operator;(or Senior Operator. Limited to Fuel Handling) who has no~other
, concurrent responsibilities during this operation.- *
- f. Fire Brigade composition and requirements are-described in -
Section 9.5.14 of this Updated FHSR 1The Fire Brigade will not , J includel2 members of the minimum shift' crew necessary-for safe shutdown of the plant and any personnel required for other essential functions during a fire emergency.
- g. The minimum refueling crew during: refueling operations will .be _ _
four men. There will be a licensed operator in the control room att all times, and the Shift- Supervisor _ will be-in charge.
13.1.6 OVERTIME LIMITS AND GUIDELINES ,
4 Administrative procedures will in be effect to limit the working:
hours of plant staff who' perform safety-related operation functions; a ie senior reactor operators, reactor operators, auxiliary operators,-
health physicists and key maintenance personnel. .
Adequate shift coverage will be maintained without routine heavy _use of overtime. However, in the event that unforeseen-problems require:
O substantial amounts of overtime to be used,.the following guidelines:
will be followed:
- 1. An individual should not be permitted to work more-than 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />s- 1 straight, excluding shift turnover time.
- 2. An individual should.not be permitted to work more than '16' hours in any 24_-hour _ period, nor more than'24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />stin:any_48-hour period,-
nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> -in any 7-day ~ period,- all excluding shift
' ~
-turnover time.
~
- 3. A break, including shift turnoveritime, of at least eight hours should be allowed after- continuous work. periods of 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />s-L duration.
- 4. Except during extended shutdown periods, the use of overtime;should-
~
be considered on an individual basis and not for the entire staff.
on a shift.
o Deviation from the above guidelines' will be authorized by the '/-
Plant-Manager or his alternate'(0perations or _ Maintenance' . /
Superintendents), or higher levels of Management 'in accordance t
with established procedures and with-documentation of-'the basis for granting the deviation.
O ,
13.1-4 1 y- 94 w -
J- - e
J BIO ROCK PQl W PLART Orga tratica Chart
() _
Plant Manager Staff Secretary Engineering Supt __
Operations Sdpt Elect. Mech I&C O Exp On Call Tech Advisor Sch Coord, flt Pe,rf F1 re
& Prop Prot, Spec roj Supervisory Engineer Maintenance Supt PRA Elec &Service Mech,teria's I&C Maint Reactor Engr Ma Janitora Services Administrative Supvisor __
Outage Planning Admin i 7 Payroll DCC Text
'# Processing, Conlroller &
Budgeting Functions Plant Human Resource Dir __
Public Affaiss Director Personnel Activities Public Affairs Union Relations Employee Communications Personnel Safety Chemistry / IIP Supt Technical Engineer Licensing Interfaces Rad Protect, AIARARadwaste Shippine Special Projects Dosimetry, Em, erg Pla,nning Executive Engineer -
v 1
Revision 3~
13.5 -11 MT PROCEDURES 13.5.1 ADMINISTRATIVE PROCEDURES 13.5.1.1- Conformance With Reaulatory Guide 1.33 - Ouality Proaram /
Reouirements (0.ggration1 CPCo complies with the regulatory position of Regulatory Guide 1.33 - (2/78, Revision 2) as modified by the. exceptions stated in the Quality Program Description (QPD) for Operational /
Nuclear Power Plants (CPC 2A). The QPD provides Policy -/
Implementation requirements for Instructions, Procedures and Drawings, and will not be repeated in this Updated FHSR .The following provides general and specific information on Administrative Controls in addition to or supplementing that specified in CPC-2A.-
13.5.1.2 Administrative Control Reauirements and Standards The duties and responsibilities for each operating position will be clearly set down in writing.
Decision-making authority will be defined for the varicus-operating position levels and reservations of decision-making authority specified.
0 Minimum standards will be established for the performance ~of various operational programs.
All repetitive operations such as startup, shutdown, and routine maintenance will be carried out according to normal operating procedures. Specific procedures will-be prepared as necessary for-non-routine operations.
13.5.1.3 Measures is ! .m :a en Followina incidents To prevent or limit adverse consequences following incidents, it will be standard procedure to:
- a. Investigate all_such incidents.
- b. Suspend any unsafe operation pending an investigation,
- c. Establish any additional procedures necessary to prevent recurrences.
Notification will be made to the NRC as required'by the Facility Operating License or by 10 CFR Part 20.
13.5.1.4 Administrative Procedural Controls All procedures and procedure revisions are to be approved by the O Plant Manager prior to use.
13.5-1
x 1 -Revision-3 In' the event continued of ?any:itsituation operatione which may.
will be-required conspromise procedure to_ shut tthe p1 safetfe.
ant of-f -
- down and>to take othd planned emergency action to protect equipment:
- and'the health and safety of workervand the publics -
13.5.2.2 _ Descriojien of Operatino-Procedures Tho Operations procedures a're divided.or grouped-into six areas-as follows; details-on each of these. areas?are provided in subsequent' ,
sections:=
- a. GQ2 =- General Plant OperatingL Procedures - provide; instructions ?
for integrated operation of the Plant _during Plant start-up ~
operation and complete shutdown of the Plant,
- b. 10f . Plant System Operating' Procedures - provide . instructions -
for energizing, filliag, venting,: draining, starting-up,;
shutting down, changing modes of operation, Land other instructions appropriate for the operation.of Plant systems.- -j
- c. ALE - Alarm Procedures _-- correcting abnormal. ala'rm conditions"-
provides a description of all annunciators, their respective
- sensor designations, the trip setting which is-associated with the alarm, along with the corrective action which-is expected of--
( - the Operator. Memorization of Operator actions is. not .
- L .
required. -
- d. ONP - Off-Normal Procedures - provide Operator -instructions $or placing the Plant in a stable condition. Immedia action
- steps.will be memorized -
/ c
- e. E0E 0 - Emergency Operating Procedures-- provide Operator with instructions, in -flow. chart form, ~ for . correcting
/ :
emergency condition ~s. Entry conditions to.E0Ps will /-
be memorized.
13.5.2.3 General Operatina Procedures- .
General Operating Procedures shall. include. procedures:to control ~
- equipment, to maintain personnel and'reactori safety, and to avoid-unauthorized operation of equipment. Operating procedures shall include:
13.5 2.3.1 Start-up Procedures
- Start-up procedures to provide for starting the' reactor from hot or cold conditions,: establishing power operation with the. generator synchronized to-the line and recover from reactor trips.
, n- -
Q 13.5-4 q e . N --- Is a--, :- -,, s
- Revision 3 s
t 13.5.2.3.2 [old Start-up After Extended Shutdown-Procedures are in place to ensure-that all plant-systems and instrumentation necessary for safe operation are operational and ready for service.
(a) To ensure that the overall plant is in a state of readiness, a start-up checklist shall be followed-prior to beginning the actual start-up so that applicable equipment and systems shall be-in condition for start up. Containment sphere integrity provisions shall be in effect.
(b) To ensure that the checklists are correctly accomplished ./
and documented a review will be performed by the Shift Supervisor prior to plant startup.
(c) To ensure that the reactor reactivity control is in a state of readiness, each control rod shall be exercised and scrammed as a a check of the control rod hydraulic system and the reactor safety system. A coupling verification check shall be included w prior to or during start-up.
(d) To ensure that the cut of core neutron monitoring instrumentation is functioning propcrly and actually monitoring neutron multiplication the source range monitor shall indicate a
-O minimum of three counts per second with a signal-to-noise ratio
(/ of 3 to 1. This will be accomplished by withdrawing the proportional counter to a region of lower flux and observing the reduction in count rate.
In the event that neutron source strength is insufficient to produce the required count rate, special approved procedures will be developed to utilize incore instrumentation for making the initial critical approach with the reactor head removed.
A similar special procedure for less- than 3 counts per second-as outlined in the Technical Specifications may be necessary for reactor start-up.
(e) To ensure that adequate neutron multiplication and reactor power level monitoring is carried out-throughuut the entire plant startup, critical approaches will be monitored using source range monitors. The startup rate will be restricted to demonstrate that the wide range neutron power level monitors overlap the readings of the source range monitor prior to the source range monitors becoming saturated.
To ensure that control rod reactivity worth are maintained
- within limits such that accidental reactivity insertion do not jeopardize fuel integrity, control rod withdrawal sequences will be spec 1'fied and rod worth accordingly limited.
R) 13.5-5
I Revision 3 13.5.2.3.4 Shutdown Procedures Shutdown procedures to guide operations during and following controlled reactor shutdown or reactor trips, and to establish'or maintain hot standby or cold shutdown conditions.-
For extended shutdowns the following precautions will be in. place.
To ensure that systemat.c control is maintained on the reactor and its primary heat sink as cell as the turbine generator, reactor power shall be reduced by henipulation of the control rods, and the main generator load shall be decreased simultaneously._ The turbine-generator shall be separated tcom the system.
To ensure that the reactor is in a cold shutdown ' condition all-control rods shall be inserted.
To ensure the reactor vessel metal remains ductible and free of excessive thermal stress, the removal of reactor decay heat and .the reduction of reactor pressure shall be accomplished by controlling reactor steam flow. The rate of cooling of the reactor vessel .
shall not be allowed to exceed 100*F per hour. Any-two temper _ature measuring points on the reactor or any two on the steam drum are not to be allowed to exceed a differential temperature of 1150*F.
/N To ensure a means of reactor decay heat removal, the reactor-C) shutdown cooling system shall be placed in operation whenever reactor pressure drops below a pressure sufficient to maintain ,
turbine seals. This system will complete the cooling of the reactor water to <212*F. /.
To ensure continuous monitoring of the reactor power level, a minimum of one source range monitor channel and-one power range monitor channel shall be left in operation. All instrumentation pertaining to control of activity. release shall be left in operation.
13.5.2.3.5 ILo_wer Operation and Load Chanoina Procedures-Power operation and _ load changing procedures provide for steady-state power operation and _ load changes, including response to unanticipated load changes, use of control _ rods or any- other -/
system available for long- or short-term control-of reactivity, making deliberate load changes, responding to unanticipated load changes, and adjusting-operating, parameters.
For normal power operation the turbine initial pressure regulator will maintain the react _or pressure at its normal value by operating the turbine admission valves. The turbine load will be established '
by the reactor control rod positions. The principal functions of the operating personnel during this period will be the maintenance j- of a continuous watch in the control room for prompt attention to X -
13.5-7
Revision 3L D
iA g.= Collect data from radiation monitoring equipment to assureLthat such data are available for determining subsequent action.
Action By Plant Manaoement The-senior member of plant management present will _ be responsibl_e for- ;
the following actions
- a. Determine extent and severity of the radiological hazard-
- b. Order partial or complete evacuation of the site as required
- c. Formulate and initiate appropriate co_urse of action -
- d. Notify State and local officials -as appropriate-
- e. Notify off-site Consumers management -
- f. Notify NRC as required by the operating license or:by 10_CFR,. :
Part 20.
'~
13.5.3 Doeratina Procedural Safeauards The following procedural-safeguards are established to assure the 1 operating safety of the Big Rock Point Plant.
O Oetailed writtee Prece8<.res fer ei, eermai an8 emereencx ePeratiens which may involve nuclear safety are_ prepared:and issued-prior to
- startup of the plant. -
Instructions for _ normal operations consist of detailed procedures . _.
required for the operation of. systems and equipment associated with the plant.
The' shift operating personnel are directed to follow the approved'.
-procedures unless deviation is required to preventLinjury to personnel or_ damage to equipment orfthe environment, -
Operator aids' are posted in appropriate ' plant locations to. assist the operator _ and administrative controis-have been-established for; these operator aids. ,
Short term directions from Plant management.to the Operators are conveyed via Operations Memos-and Daily _ Orders'.- Administrative controls have been established for these' Memos > and- Orders.
The _ Off-Normal Operating Procedures are- separated into, four . /:
parts. The first part describes _the_ symptoms,ithe second the automatic actions,-the third the immediate: actions which are to be ~taken to shut the' plant down and to~ place it in a safe condition. 'The fourth part describesLthe follow-up actions.
O which are to be taken to maintain _the plant in a safe condition. It is recognized that action after placing 13.5-12 p
Revision 3' the plant-in a_ safe condition will be dictated largely by the O circumstances existing at the time and that to this extent prepared procedures cannot cover all; conditions and thus in all cases will not substitute'for the responsible judgment of plant management personnel. In addition to the Off-Normal procedures related to
/
plant operations, procedures and precautions related to emergencies postulated for any industrial plant, such as fire, earthquake, tornado and flood, have been developed. These procedures include s 3ecific instructions as to special precautions and procedures w11ch must be followed because of the potential presence of radioactivity.
13.5,4 Measures to Prevent Operatina Error Thorough training of the operating staff and systematically planned operating and maintenance procedures will combine to keep to a minimum the possibility of operator errors.
Each operator will be well acquainted with his specific duties and responsibilities and the action to be taken in the event of off-standard conditions. The following paragraphs discuss the design measures and administrative contr91s which will promete the safety of plant operation.
13.5.5 Other Procedures (V Other procedural requirements for the following. categories of procedures are described in the QA Program Description (CPC-2A):
Equipment control procedures.
Plant radiation protection procedures.
Instrument calibration and test procedures.
Chemical-radiochemical. control procedures.
Radioactive waste management procedures.
Maintenance and modification procedures.
Material control procedures.
Temporary procedures.
Surveillance test procedures.
Procedural requirements for Security procedures are addressed _
in the Security Plans discussed in Section 13.6 of this Updated'FHSR.
Emergency Preparedness procedures are addressed in the Site Emergency Plan discussed in Section 13.3 of this Updated FHSR.
13
. ()
13.5-13
Revision 3 i
In additions to the anticipatory trip signal to a recirculation pum,a,
)_ circuitry is also provide to trip a recirculation pump should both emergency-condenser outlet valves be opened (conditions indicative of a high pressure transient)..
15.8.1.1 Plant Design Features important During ATWS The primary system of Big Rock Point incorporates the reactor vessel, a steam drum, six external risers and two external recirculation loops. Normal steam flow from the primary system during full power operaticn is approximately-IE+6 lb/hr whereas normal recirculating water flow is approximately ten times greater at lE+7 lb/hr. Tripping one of the two recirculating pumps reduces flow to the point that reactor power drops to 60% of its former -
level while tripping the second pump results in a much more limited drop of only 10% initial power.
Located on the steam drum are six spring loaded code safety valves-each rated at over 100 lb/sec steam flow with the primary system at 1870 psia (110% of design). The size and number of safety valves permits the primary system to remain w1 hin code allowable' limits even if the reactor is isolated at full power, failure of the reactor /
to scram occurs and no mitigating systems function.
The primary system contains approximately 100,000 lbs of coolant inventory at full power operation, with 35,000 lbs above the low O reactor water level setpoint. This setpoint is-important from the standpoint that on attaining this reactor water level. Reactor Depressurization System (RDS) actuation can be expected. In newer BWRs, actuation of the auto depressurization system would be precluded by the operation of the high' pressure injection system.
Big Rock Point has no high volume high pressure injection system other than the motor driven feednter pumps, and so on loss of feedwater or isolation of the primary system from the main condenser, lowering of the water level to the RDS setpoint can be expected unless reactor shutdown is effected. Actuation-of RDS has several effects. First the core is uncovered which has the temporary effect of terminating power operation, and second, the low pressure core spray is permitted to operate providing core cooling.
However, mixing of the liquid poison is assumed to be restricted under this configuration and at least limited core damage is expected if the reactor is permitted to return to power on unborated core spray reflood. As a result of the design of RDS, timing of plant response and operator actions to shut the reactor down are largely dependent on the time to reach RDS actuation on low reactor water level.
Big Rock Point is al'sa equipped with an emergency condenser consisting of two independent tube bundles, each capable of removing about 5% of normal reactor power with the primary system near normal operating temperature. During ATWS, operation of the emergency condenser has the beneficial effect of limiting the amount of steam 15.8-3
__