ML24340A007

Updated Safety Analysis Report Rev.28, Chapter 5, Reactor Coolant System and Connected Systems

ML24340A007
Person / Time
Site:	River Bend
Issue date:	07/30/2023
From:	James Drake NRC/NRR/DORL/LPL4
To:	Entergy Operations
References
Download: ML24340A007 (1)

Text

RBS USAR Revision 27 5.1-1 CHAPTER 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS 5.1

SUMMARY

DESCRIPTION The reactor coolant system includes those systems and components which contain or transport fluids coming from, or going to, the reactor core. These systems form a major portion of the reactor coolant pressure boundary (RCPB). This chapter of the USAR provides information regarding the reactor coolant system and pressure-containing appendages out to and including isolation valving. This grouping of components is defined as the RCPB as follows.

RCPB includes all pressure-containing components such as pressure vessels, piping, pumps, and valves, which are:

1.

Part of the reactor coolant system, or

2.

Connected to the reactor coolant system, up to and including any and all of the following:

a.

The outermost containment isolation valve in piping which penetrates primary reactor containment

b.

The second of the two valves normally closed during normal reactor operation in system piping which does not penetrate primary reactor containment

c.

The reactor coolant system safety/relief valve piping up to and including the safety/relief valves (SRVs).

This chapter also deals with various subsystems to the RCPB which are closely allied to it.

Specifically, Section 5.4 deals with these subsystems.

The nuclear system pressure relief system protects the RCPB from damage due to overpressure.

To protect against overpressure, pressure-operated relief valves are provided that can discharge steam from the nuclear system to the suppression pool. The pressure relief system also acts to automatically depressurize the nuclear system in the event of a loss-of-coolant accident (LOCA) in which the high-pressure core spray (HPCS) system fails to maintain reactor vessel water level.

Depressurization of the nuclear system allows the low-pressure core cooling systems to supply enough cooling water to adequately cool the fuel.

Section 5.2.5 establishes the limits on nuclear system leakage inside the drywell so that appropriate action can be taken before the integrity of the nuclear system process barrier is impaired.

The reactor vessel and appurtenances are described in Section 5.3. The major safety consideration for the reactor vessel is the ability of the vessel to function as a radioactive material barrier. Various combinations of loading are considered in the vessel design. The vessel meets the requirements of applicable codes and criteria. The possibility of brittle fracture is considered,

RBS USAR Revision 27 5.1-2 and suitable design, material selection, material surveillance activity, and operational limits are established that avoid conditions where brittle fracture is possible.

The reactor recirculation system provides coolant flow through the core. Adjustment of the core coolant flow rate changes reactor power output, thus providing a means of following plant load demand without adjusting control rods. The recirculation system is designed to provide a slow coastdown of flow so that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions. The arrangement of the recirculation system routing is such that a piping failure cannot compromise the integrity of the floodable inner volume of the reactor vessel.

The main steam line flow restrictors of the venturi type are installed in each main steam line inside the primary containment. The restrictors are designed to limit the loss of coolant resulting from a main steam line break outside the primary containment. The coolant loss is limited so that reactor vessel water level remains above the top of the core during the time required for the main steam isolation valves (MSIVs) to close. This action protects the fuel barrier.

Two isolation valves are installed on each main steam line; one is located inside and the other is located outside the primary containment. In the event that a main steam line break occurs inside the containment, closure of the isolation valve outside the primary containment acts to seal the primary containment itself. The MSIVs automatically isolate the RCPB in the event a pipe break occurs downstream of the inboard isolation valves. This action limits the loss of coolant and the release of radioactive materials from the nuclear system.

The reactor core isolation cooling (RCIC) system provides makeup water to the core during a reactor shutdown in which feedwater flow is not available. The system is started automatically upon receipt of a low reactor water level signal or manually by the operator. Water is pumped to the core by a turbine pump driven by reactor steam.

The residual heat removal (RHR) system includes a number of pumps and heat exchangers that can be used to cool the nuclear system under a variety of situations. During normal shutdown and reactor servicing, the RHR system removes residual and decay heat. The RHR system allows decay heat to be removed whenever the main heat sink (main condenser) is not available.

One mode of RHR operation allows the removal of heat from the primary containment following a LOCA. Another operational mode of the RHR system is low pressure coolant injection (LPCI).

LPCI operation is an engineered safety feature for use during a postulated LOCA. This operation is described in Section 6.3.

The reactor water cleanup (RWCU) system recirculates a portion of reactor coolant through a filter-demineralizer to remove particulate and dissolved impurities from the reactor coolant. It also removes excess coolant from the reactor system under controlled conditions.

Design and performance characteristics of the reactor coolant system and its various components are found in Table 5.4-1.

5.1.1 Schematic Flow Diagram Schematic flow diagrams of the reactor coolant system denoting all major components, principal pressures, temperatures, flow rates, and coolant volumes for normal steady-state operating conditions at rated power are presented on Fig. 5.1-1 and 5.1-2.

5.1.2 Piping and Instrumentation Diagram

RBS USAR Revision 27 5.1-3 Piping and instrumentation diagrams covering the systems included within the reactor coolant system and connected systems are presented as follows:

System Figure Nuclear boiler 5.1-3a and 5.1-3b Main steam 10.3-1a through 10.3-1c Feedwater 10.4-7 Recirculation 5.4-2 Reactor core isolation cooling 5.4-8 Residual heat removal 5.4-12 Reactor water cleanup 5.4-15 5.1.3 Elevation Drawing An elevation drawing showing the general arrangement of the reactor and coolant system in relation to the containment is shown on Fig. 1.2-7.


































W

9





)
V

 

A!!

'
'

GÇç

 B

ó%'



-

n
+/-

9













 

 


$3â

56 (66N

3







   


CC

3
*9 39

=°D  °D









  




/,: 9/

&
/
)
*

9 





&)9

%

-t&O&



9 z







0



8

'

y-( 






'

d

'

11h

`) %







/"3 %

²







• / C

9

)C%0





Q 

 /,:

3Q
* 

zz gg



 ,%



{

8

9



    

 






$ 
$

!!
!

!!
!





8

11

O W'*

9 X'

W'

9

'

 

/(C

 (%0

$!$

 V

( 


V

 B

³

%  ²

5$

5

B@$

`)
0 


³ -

8q







1!

 





U

6





+

+++++

++
 

á




/

* 9 

 






'

¹'*

9

M



9

,%

8

69



1h/

11

'

A!!

{

/ R



O

 ,#2


0

 

gn)%'

zg 




{

0





4 aaaa

'



_(%0







'


 



'*M





















+

i<<<<*

$

$





 9!!
1!



Ñ

ZZ/

^) N



c()

(&9 d()9 rjJ9

  

6 &,=



] N

2 %%

9!!
!

H&\\&

ł 9 f

Y9



@

Â(
E

^( Ee

















9




1







 







 



&9



 





 C2

 K###>>>> ý



-1

1. t+

  
#

É(([~~



2



4



+








()9

 5






'

8

&9

9

œ) &0

-89 R2




8

• J

9



• J9 u*J

'6





&&

==











Q/ 9

J9







rjJ9





$







$

1. ))9

& h



$

1. ))9

& '



u' 
 '*9

8'

'



6





(0

1. ))9 ( 0

1. ))9

_( 0

1. ))9 ÷(0

$

1. ))

-



1. )

&+ (39

&+ (39

&+9 (3

&+ (39



 3/4  
 /,

Q 3 Q 
    

        

9 *Jm)9








'*9

'*9

 











9&





+!

$




Q 








 Q


3/4



1. 3+-3




 




B@

1. 3

3

!3

3 8(q

])
V G

*9 X'9

9

 'é 9



'@

B 1/2 


1/2 "




(


p
+/-

^(

'&

^(N

'&













$













8

9

'





M

'



=




"


3+.3

5

p)e

@=

§

É(([



} *3&&&&&3(3'3








*

# 

d a 

8

J9

O





f

 







'

Ã(







yy

 )%



"










]S¥



"


3


j

@

l)%e



"






/(,



1. 1. /x

Ø



"


'M



]¶



l) Ew






&

9

"






Y

5

) E














1

goS N

L




"


'19









l^(



 -



c(

(&



- %

#######





!#

K###??














X()9

(&9

1











+5%



ís K

K sss

• ú§

??????????

/





Y

9

"



• 

L

@ 



L

£(x

£)
0x

%

99





"


'*M

1!

Ü(

A





( 

+9

"
ZZ

"




4



4



4



4



4 R

4 4

2

~TTTK

 Z





@ 



"j





%

9

"






 

 "

#

K###?

 89 ,#2










"






"













"













W

6 l) Ew YG



)
0¸

M

$

n(
N W

9

3 l) e

GÇ



(

l(%0

M

9 S w



f c()9

(&

9

 





 

 

89 2

()9

+%





S








)









¹ 





`(¸

'¬r\\*  

A!!
Z

" h<&F

i 
 

1

2)&&&,3



"


(

l YG





'H&!\\<*&



"


G&

L



7

kkkk

7 777777777



Ž L

l) µ

9

)%0





9!!

A!!

A!!

A!

"


d

&9



)&0 c

9 c

9 d"

9

5



*

V pz

Â



"


"
 




"


"
1


















 













G





'/





¢

5-

-











Ã)¥

]v o
v n(%e o
w o)v

]Sv



t&\\<&F

{

()9

+-&9

  









u q

u q












"





4

 4Å,4 4

$4H+~º###K 





+

5







}





7





9++





9++'

%%9

b&\\&

/ R















'û

(

)

)

Ú

&ü

+



&

(



'

ø

• ÿ+++++++++++

+















i i

A










r/j



),

   /33 



'-f X

(&

9

 %



    

 -<R&F

 

  



+,&







3



"#k

?ºTTTK

 

()9

+&9 L

X

X

}

"

/ R

9

_<%F

_'

-'

89 RH

)9

 !



$
)

/*
2

,
H

, 

3* 2%'

'!


      ,.

$* 'I&!

'

  .

3*  $

-

$:

$* b=-

-




3* 2%




 , P. 
 

$* %-



* .   ,



t&!\\*& 


!


-

&)

 

'*

b  
¨ 
.
¿  © 
 P.

.  ¿  $ : D

-=D

 :  $$
 $   :
2

i i



()

 " $

UUUUU



, $ 





*

 



9

'



`(



'

_(x



2  O D"D :. 
   . P.
 
$
, 

  
 
I $   P.
   < F $    

 


.  
 $, $
H








"






y'6

n)
¶

" <6%



6&Ef

'



-G

B

p) EV












9








9 9



 


'

9

!



S µ



9






 


"





$

( 0

 

99 W




' 











'



( EN














 

<6=F





9



f

' '5m C¬

-5 -m CH









L



 D D






L

 -

<%F }


 '

'*



 




 B Y


'



 


'

¢'

B 

  



A!!



'

89 hm C





 




 

!!!! Å 
















B 

`)
x





I  :
*  
:
$  *
   
, :
*
I

''2    *
  ,2

I  .

 

  


  
,  

$  , . 
 P. ,  *
$  ,  ,I

P= - , ,  P. ,  $  O* $  

O* .I

'b   
   
 

 
*   
  $ 


$ 

, 
.  

*  . < F $  .

 
.I

H  
.   5¨ @ © 


     
 
 
b





 

 


  

 

    


   




 



         

1/41/4





































AND STEAM CONDITIONS AT 0 PSIG IN THE VESSEL AND THE DRYWELL WITH NO JET PUMP FLOW.

ABOVE WATER LEVEL NOZZLE WITH NO JET PUMP FLOW.

C. NARROW RANGE: (SAFEGAURDS & FEEDWATER): THE INSTRUMENTS ARE D. UPSET RANGE: THE INSTRUMENT IS CALIBRATED FOR SATURATED WATER THE DRYWELL.

B. WIDE RANGE: THE INSTRUMENTS ARE CALIBRATED FOR 1055 PSIG IN THE MIDDLE WATER LEVEL NOZZLE AND SATURATED WATER AND STEAM CONDITIONS CALIBRATED FOR SATURATED WATER AND STEAM CONDITIONS AT 1055 PSIG 2

3 4

2 3

4 PS N676B NS NS NS NS NS NS NS NS CORE PLATE POST ACCIDENT MONITORING PIS N675D PIS N675C PIS N675B PIS N675A PIS N676D PIS N676C PIS N676A 2

POST ACCIDENT MONITORING

• PT N062B

• PT N062A

• PT N075D

• PT N075C

• PT N075B

• PT N075A

• PT N076D

• PT N076C

• PT N076B

• PT N076A

• dPT N032 2

4 3

2 4

3 2

dP 4

4 4

4 4

4 4

4 4

2 PRESS PERM PS N697F PS N698F RHR(B) RHR(C)

NS =NUCLEAR STEAM SUPPLY SHUTOFF (CONTAINMENT ISOLATION) FUNCTION JET PUMP DIFFUSER TAP JET PUMP INTRUMENT NOZZLE 149.0" 159.2"

• FUNCTION IS IN FEEDWATER CONTROL SYSTEM FOR LOSS OF ONE FEED PUMP NOTES:

WHERE A DIFFERENT PREFIX IS SHOWN.

A. FUEL ZONE: THE INSTRUMENTS ARE CALIBRATED FOR SATURATED WATER

1. ALL LINE, INSTRUMENT, VALVE, AND EQUIPMENT TO BE PREFIXED WITH "B21-" EXCEPT

2. THE DASH (-) IN THE SYSTEM PREFIX IS REPLACED BY AN ASTERISK (*) WHERE THE INSTRUMENT, VALVE, OR EQUIPMENT IS PART OF A NUCLEAR SAFETY RELATED SYSTEM.

3. WATER LEVEL INSTRUMENTS FOR VARIOUS RANGES ARE CALIBRATED AS STATED BELOW.

ALL WATER LEVEL SWITCH SET POINTS ARE NORMAL: I.E., THE ANALYSES ARE PER-FORMED WITH THE SWITCH TRIP UNCERTAINTY INCLUDED. THE CONTAINMENT BUILDING

• PT N094F

• PT N094B

• PT N094E

• PT N094A

• PT N067R

• PT N067L

• PT N067G

• PT N067C

• PT N058F

• PT N058B

• PT N058E 2

2 3

3 4

4 2

2 3

3 3

3 2

2 RECIRC (B)

RECIRC (B)

RECIRC (A)

HPCS HPCS HPCS HPCS RHR(A)/LPCS/RCIC/ADS(A)

RHR(A)/LPCS/ADS(A)

RHR(B)/RHR(C)/RCIC/ADS(B)

RHR(B)/RHR(C)/ADS(B) 2 2

2 2

2 2

2 2

2 2

PS N669B PS N670B PS N617B PS N618B PS N669E PS N670E PS N616E PS N618E PS N669F PS N670F PS N616F PS N618F PRESS RELIEF PRESS RELIEF PRESS RELIEF REOPEN/RECLOSE (MID)

REOPEN/RECLOSE (HIGH)

PRESS RELIEF PRESS RELIEF PRESS RELIEF REOPEN/RECLOSE (LOW)

REOPEN/RECLOSE (HIGH)

PRESS RELIEF PRESS RELIEF PRESS RELIEF REOPEN/RECLOSE (LOW)

REOPEN/RECLOSE (HIGH)

PRESS RELIEF PRESS RELIEF PRESS RELIEF REOPEN/RECLOSE (LOW)

REOPEN/RECLOSE (HIGH)

PIS N658B PIS N658F PIS N667C PIS N667G PIS N667L PIS N667R PIS N694A PIS N694E PIS N694B PIS N694F PIS N668A PS N669A PS N670A PS N617A PS N618A

• PT N068E 2

• PT N068B

• PT N068A 2

• PT N068F LOW LOW SET LOW LOW SET LOW LOW SET LOW LOW SET PIS N668F PIS N668E PIS N668B

• LT N081B

• LT N091E

• LT N091F

• LT N073C

• LT N073G

• LT N073L

• LT N073R

• LT N081C

• LT N081D

• LT N080A

• LT N080B

• LT N080C

• LT N080D

• LT N099A

• LT N099E

• LT N099B

• LT N099F

• LT N095A

• LT N095B

• LT N081A

• • TRIPS RHR SHUTDOWN ISOLATION VALVES TO CLOSE 1

PS N697A PS N698A PRESS PERM LPCS/ RHR(A) 2 PRESS PERM PRESS PERM PS N697B PS N698B PS N697E PS N698E RHR(B) RHR(C)

LPCS/ RHR(A) 2 2

LIS N681B LS N682B NS (MSIV) 4 2

2 4

4 3

4 3

3 3

3 3

LIS N691E LS N692E LIS N691F LS N692F LIS N673C LS N674C LIS N673G LS N674L NS 3

4 LIS N673L LIS N673R 3

4 LIS N681C LS N682C HPCS NS (MSIV) 4 NS 4 NS (MSIV) 4 NS 4 LIS N681D LS N682D 2

2 LIS N680A LS N683A RPS(A) NS (A)** 4 RPS(A)

RPS(B) NS (B)** 4 RPS(B)

LIS N680B LS N683B RCIC HPCS RCIC ADS(B)/RHR(B)/RHR(C)

HPCS ADS(A)/RHR(A)/LPCS HPCS 3

4 3

HPCS HPCS 4

LIS N680C LS N683C RPS(C) NS (C)** 4 RPS(C)

RPS(D) NS (D)** 4 RPS(D)

LIS N680D LS N683D 2

2 2

8 2

8 2

2 2

2 2

2 3

3 2

2 2

2 3

8 3

8 3

8 3

8 LIS N699A LIS N699E LIS N699B LIS N699F LIS N695A LIS N695B LIS N681A LS N682A 2

2 2

2 INSTRUMENT LINE NOZZLE RECIRC (B)

RECIRC (B)

RECIRC (A)

ADS(A)

ADS(B)

NS (MSIV)

NS RECIRC (A) 586.25" 4

4 BOOSTER PUMPS.

SCRAM.

HIGH LEVEL ALARM NORMAL WATER LEVEL LOW LEVEL ALARM RUN RECIRC FLOW BACK ON FEEDPUMP TRIP.*

SCRAM & CONTRIBUTE TO AUTO DEPRESSUR-IZATION. RUN RECIRC FLOW BACK. CLOSE RHR SHUTDOWN ISOL VALVES.

520.62" INSTRUMENT LINE NOZZLE WATER LEVEL INSTRUMENT ZERO 509.0" INITIATE RCIC & HPCS.

CLOSE PRIMARY SYSTEMS ISOL VALVES EXCEPT MSIV'S & RHR SHUTDOWN ISOL VALVES. TRIP RECIRC PUMPS START DIV 3 STANDBY DIESEL.

INITIATE RHR & LPCS.

CONTRIBUTE TO AUTO DEPRESSURIZATION.

START DIV 1, DIV 2 STANDBY DIESELS.

CLOSE MSIV'S.

TOP OF ACTIVE FUEL 358.56" INSTRUMENT LINE NOZZLE 358.0" TABLE II TABLE II TABLE II 8

51.0" 51.0" 51.0" 38.8" 7

9.7" 9.7" 3

30.8" 4

34.8" 5

0" 0"

0" 0"

0"

-160.0"

-143.0"

-43.0"

-110.0" 2

-310.0"

-162.0" 0"

TRANSMITTER MECH DIV LOC ELEC DIV SYSTEM TRIP UNIT

• PT N058A

• PT N078D

• PT N078C

• PT N078B

• PT N078A RPS (A) 4 4

3 3

2 2

RECIRC (A)

NS (D) (RHR ISOL)

RPS (D)

NS (C) (RHR ISOL)

RPS (C)

NS (B) (RHR ISOL)

RPS (B)

NS (A) (RHR ISOL)

PIS N678A PS N679A PIS N678B PS N679B PIS N678C PS N679C PIS N678D PS N679D PIS N658A PIS N658E 4

4 4

4 TABLE I: PRESSURE INSTRUMENT CONTACT UTILIZATION TRANSMITTER

• LT N091B

• LT N091A

• LT N027

• LT N044C

• LT N044D TABLE II: WATER LEVEL INSTRUMENT CONTACT UTILIZATION

• LT N044E MECH DIV LOC ELEC DIV TRIP UNIT SYSTEM 2

4 LS N693A LS N692A LIS N691A 2

3 2

2 3

LS N693B LS N692B LIS N691B RCIC RCIC ADS(B)/RHR(B)/RHR(C)

RCIC RCIC ADS(A)/RHR(A)/LPCS FUEL ZONE FUEL ZONE SHUTDOWN LEVEL LEVEL TRIP POINT 2

8 2

8 REFERENCE TOP OF HEAD FLANGE (COLD VESSEL)

INCHES ABOVE VESSEL ZERO STEAM LINE NOZZLE 636.5" 842.0" TRIP RCIC TURBINE &

HPCS INJECTION VALVE CLOSURE SIGNAL.

CLOSE MAIN TURBINE STOP VALVES. TRIP FEED PUMPS & CONDENSATE FUEL ZONE DESCRIPTION OF TRIPS INSTRUMENT(S)

PROVIDING TRIP REACTOR VESSEL LEVEL IDENTITY TABLE II FUEL ZONE LR R615 LI R610E,C SAFEGUARDS WIDE RANGE LR/PR R623A,B LI R604 FEEDWATER NARROW RANGE C33/C34 LR R608 C33/C34 LI R606ABC UPSET C33/C34 LR R608 SHUTDOWN LI R605 CONTROL ROOM LEVEL INDICATION AND TRIP LEVELS SEE NOTE 3 180.0" 400.0" 60.0" 60.0" 60.0" TABLE III ELEVATION CORRELATION CHART L

21 20 19 18 17 16 15 14 13 12 11 10 9

8 7

6 5

4 3

2 1

21 20 19 18 17 16 15 14 13 12 11 10 9

8 7

6 5

4 3

2 1

J B

P N

M L

K H

G F

E D

C B

A P

N M

K J

H G

F E

D C

A 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 1

1 TEMPERATURE ASSUMED TO BE 86.5° F.

VESSEL, 130° F IN THE DRYWELL AND 20 BTU/LB SUB-COOLING BELOW THE IN THE VESSEL AND 130° F IN THE DRYWELL.

AND STEAM CONDITIONS AT 1055 PSIG IN THE VESSEL AND 130° F IN SHUTDOWN: THE INSTRUMENT IS CALIBRATED FOR 120° F WATER AT 0 PSIG VESSEL AND 80° F IN THE DRYWELL.

FIGURE SYSTEM P&ID REVISION 22 UPDATED SAFETY ANALYSIS REPORT RIVER BEND STATION 5.1-3b 051 NUCLEAR BOILER INSTRUMENTATION 25-01B P0148 1

ALL LINE, INSTRUMENT, VALVE, AND EQUIPMENT NUMBERS TO BE PREFIXED WITH "RCS-" EXCEPT WHERE A DIFFERENT PREFIX IS SHOWN.

SYSTEM TITLE SYS NO.

REFERENCES:

NOTES:

L 21 20 19 18 17 16 15 14 13 12 11 10 9

8 7

6 5

4 3

2 1

21 20 19 18 17 16 15 14 13 12 11 10 9

8 7

6 5

4 3

2 1

J B

P N

M L

K H

G F

E D

C B

A P

N M

K J

H G

F E

D C

A FIGURE SYSTEM P&ID RIVER BEND STATION UPDATED SAFETY ANALYSIS REPORT REVISION 20 5.1-3c 051 REFERENCE LEG BACKFILL SYSTEM 25-1G F

F 1H22*PNLP027 1H22*PNLP004 051 052 NUCLEAR BOILER INSTRUMENTATION CONTROL ROD DRIVE HYDRAULIC 1H22*PNLP005 1H22*PNLP026 1/2" 1/2" 1/2" ALL MANUAL VALVES ARE INSTRUMENT TUBING NEEDLE VALVES.

3.

V3061 V3060A V3059A FLT5A V3060B FLT5B V3059B V3062 V3058B V3058A V3055D V3056D FI 108D D

V3057D V3054D TEST D

• V3051D TEST D

• V3049D TEST D

• V3052D

• V3050D

• V3048D

• V3048B

• V3050B

• V3049B V3057B 109B RO V3054B D

TEST D

• V3051B D

TEST

• V3052B 108B FI D

TEST V3055B V3056B

• V3050C

• V3048C V3057C V3054C D

TEST D

• V3051C TEST D

• V3052C 108C FI

• V3049C TEST D

V3056C V3055C V3057A V3054A D

D TEST 109A RO 108A FI V3056A V3055A

• V3050A

• V3049A TEST

• V3051A TEST D

• V3052A D

• V3048A 1/4" 1/4" 1/4" 1/4" V3064A V3064B LC LC LC LC 5.1-3a(H-16) 5.1-3a(H-18) 5.1-3a(E-6) 5.1-3a (J-3) 4.6-5a(D-15)

TEST TEST TEST TEST FIGURE NO.

5.1-3a 4.6-5a ALL LINES ARE UNNUMBERED INSTRUMENT TUBING LINES.

4.

2 2

2 2

V3066A V3066D V3066B V3066C 1/4" 109D RO 1/4" 1/4" RO 109C 1/4" 1.

2. THE ASTERISK "*" WAS USED IN A PREVIOUS EQUIPMENT IDENTIFICATION SYSTEM AT RIVER BEND STATION. REFER TO THE EQUIPMENT DATA BASE (EDB) FOR THE PROPER COMPONENT NUMBER AND SAFETY CLASSIFICATION.

5.4-8 (J-18) 5.4-8 (H-18)

(J-4)

N-9 209 REACTOR CORE ISOLATION COOLING 5.4-8 RO302 ICS-FI302 ICS-V3020 V3021 ICS-ICS-V3026 1/4" LC V3022 1/4" ICS-ICS-ICS-ICS-V3024 V3023 V3025 LC ICS-RO301 ICS-V3010 ICS-ICS-V3016 1/4" ICS-ICS-V3015 LC ICS-V3014 V3013 V3011 LC ICS-FI301 ICS-1/4" V3012 ICS-H22-PNLP004 V3028 ICS-V3018 ICS-

RBS USAR Revision 27 5.2-1 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY This section discusses measures employed to provide and maintain the integrity of the reactor coolant pressure boundary (RCPB) for the plant design lifetime.

5.2.1 Compliance with Codes and Code Cases 5.2.1.1 Compliance with 10CFR50, Section 50.55a Table 3.2-1, which shows compliance with the rules of 10CFR50, is included in Section 3.2.

Code editions, applicable addenda, and component dates are in accordance with 10CFR50.55a.

5.2.1.2 Applicable Code Cases The reactor pressure vessel (RPV) and appurtenances, and the RCPB piping, pumps, and valves, are designed, fabricated, and tested in accordance with the applicable edition of the ASME Code, including addenda that were mandatory at the order date for the applicable components. Section 50.55a of 10CFR50 requires code case approval only for Class 1 components. These code cases contain requirements or special rules which may be used for the construction of pressure-retaining components of Safety Class 1 (Quality Group Classification A). The various ASME code cases that were applied to components in the RCPB are listed in Table 5.2-1.

Regulatory Guides 1.84 and 1.85 provide a list of ASME Design and Fabrication code cases that have been generically approved by the Regulatory staff. Code cases on this list may, for design purposes, be used until appropriately annulled. Annulled cases are considered "active" for equipment that has been contractually committed to fabrication prior to the annulment.

GE's procedure for meeting the regulatory requirements is to obtain NRC approval for code cases applicable to Class 1 components only. NRC approval of Class 2 and 3 code cases was not required at the time of the design of River Bend Station and is not required by 10CFR50.55a.

All Class 2 and 3 equipment is designed to ASME code or ASME-approved code cases.

5.2.2 Overpressure Protection This section provides evaluation of the systems that protect the RCPB from over pressurization and is applicable to the initial and reload core except as noted in Appendix 5A.

The MSIV with Flux Scram was re-analyzed at 3100 MWt (2% higher) over the Power Uprate value of 3039 core power at conditions shown in Table 15.0-2A. The analysis was done from the MELLL to the ICF core flow range conditions. The limiting ICF condition is reported here, consistent with Appendix 5A. The Uprate condition analysis also assumes that the event is initiated at a higher reactor dome pressure of 1078 psig, which is higher than the nominal uprated dome pressure. For River Bend Station, seven (7) SRVs out-of-services (OOS) were assumed in the overpressure protection analysis; a total of nine (9) SRVs (five in safety mode and four in relief mode were assumed in Appendix 5A. At uprated conditions, a peak RPV pressure 1346.7 psig is calculated at the bottom of the vessel, but the pressure remains below

RBS USAR Revision 27 5.2-2 the 1375 psig ASME limit. The results of the uprate over protection analysis are given in Table 5.2-9 and Figure 5.2-1.

5.2.2.1 Design Basis Overpressure protection is provided in conformance with 10CFR50, Appendix A, General Design Criterion 15. Preoperational and startup instructions are given in Chapter 14.

The overpressure analysis shown in Chapter 5 of the USAR assumed the plant is initially operating at 105 percent steam flow condition with a maximum vessel dome pressure of 1,045 psig. There is no need to establish a separate technical specification limit on the initial operating pressure.

The maximum operating pressure at 100 percent power is expected to be 1055 psig; therefore, the assumed initial operating pressure of 1078 psig is expected to be conservative relative to expected actual operation. In addition, the nominal high pressure scram set point is expected to be set at 1094.7 psig.

A study was performed for a BWR/3 to investigate the effects of increasing the initial reactor pressure relative to the initial value used in the overpressure protection analysis on the peak system pressure. The conclusion was that increasing the initial operating pressure results in an increase peak system pressure, which is less than half the initial pressure increase as shown on Fig. 5.2-14 for the overpressure design transient (i.e., all MSIV closures with indirect high neutron flux scram). The same general trend is expected to exist for River Bend Station.

Limitations for reactor steam dome pressure are provided in the River Bend Technical Specifications.

5.2.2.1.1 Safety Design Bases The nuclear pressure-relief system has been designed:

1.

To prevent overpressurization of the nuclear system that could lead to the failure of the RCPB.

2.

To provide automatic depressurization for small breaks in the nuclear system occurring with a failure to maintain reactor water level, so that the low-pressure coolant injection (LPCI) and the low-pressure core spray (LPCS) system can operate to protect the fuel barrier.

3.

To permit verification of its operability.

4.

To withstand adverse combinations of loadings and forces resulting from normal, upset, emergency, or faulted conditions.

RBS USAR Revision 27 5.2-3 5.2.2.1.2 Power Generation Design Bases The nuclear pressure relief system safety/relief valves (SRV) have been designed to meet the following power generation bases:

1.

Discharge to the containment suppression pool.

2.

Correctly reclose following operation so that maximum operational continuity can be obtained.

5.2.2.1.3 Discussion The ASME Boiler and Pressure Vessel Code requires that each vessel designed to meet Section III be protected from overpressure under upset conditions. The code allows a peak allowable pressure of 110 percent of vessel design pressure under upset conditions. The code specifications for safety valves require that: 1) the lowest safety valve be set at or below vessel design pressure, and 2) the highest safety valve be set so that total accumulated pressure does not exceed 110 percent of the design pressure for upset conditions. The safety/relief valves are designed to open via either of two modes of operation: automatically using a pneumatic power actuator or by self-actuation in the spring lift mode.

Set points of the 16 SRVs are listed in Table 5.2-2. These set points satisfy the ASME Code specifications for safety valves, because all valves open at less than the nuclear system design pressure of 1,250 psig.

The automatic depressurization capability of the nuclear system pressure relief system is evaluated in Sections 6.3 and 7.3.

The following detailed criteria are used in selection of relief valves:

1.

Must meet requirements of ASME Section III.

2.

Must qualify for 100 percent of nameplate capacity credit for the overpressure protection function.

3.

Must meet other performance requirements such as response time, etc, as necessary to provide relief functions.

The SRV discharge piping is designed, installed, and tested in accordance with ASME Section III.

5.2.2.1.4 Safety/Relief Valve Capacity The SRV capacity is adequate to limit the primary system pressure, including transients, to the requirements of the ASME Boiler and Pressure Vessel Code,Section III, up to and including 1971 Edition with Summer 1973 Addenda. The essential ASME requirements which are all met by this analysis are discussed as follows.

It is recognized that the protection of vessels in a nuclear power plant is dependent upon many protective systems to relieve or terminate pressure transients. Installation of pressure-relieving devices may not independently provide complete protection. The safety valve sizing evaluation

RBS USAR Revision 27 5.2-4 assumes credit for operation of the scram protective system which may be tripped by either one of two sources; i.e., a direct or flux trip signal. The direct scram trip signal is derived from position switches mounted on the main steam isolation valves (MSIVs) or the main turbine stop valves or from pressure switches mounted on the dump valve of the main turbine control valve hydraulic actuation system. The position switches are actuated when the respective valves are closing and following 10 percent travel of full stroke. The pressure switches are actuated when a fast closure of the main turbine control valves is initiated. Credit is taken for 50 percent of the total installed SRV capacity operating via the power operated mode as permitted by ASME Section III. Credit is also taken for the remaining SRV capacity which opens via the spring mode of operation direct from inlet pressure.

The rated capacity of the pressure-relieving devices is sufficient to prevent a rise in pressure within the protected vessel of more than 110 percent of the design pressure (1.10 x 1,250 psig

= 1,375 psig) for events defined in Section 15.2.

Full account is taken of the pressure drop on both the inlet and discharge sides of the valves.

All combination SRVs discharge into the suppression pool through a discharge pipe from each valve which is designed to achieve sonic flow conditions through the valve, thus providing flow independence to discharge piping losses.

Table 5.2-5 lists the systems which could initiate during the design basis overpressure event.

5.2.2.2 Design Evaluation 5.2.2.2.1 Method of Analysis To design the pressure protection for the nuclear boiler system, extensive analytical models representing all essential dynamic characteristics of the system are simulated on a large computing facility. These models include the hydrodynamics of the flow loop, the reactor kinetics, the thermal characteristics of the fuel and its transfer of heat to the coolant, and all the principal controller features, such as feedwater flow, recirculation flow, reactor water level, pressure, and load demand. These are represented with all their principal nonlinear features in models that have evolved through extensive experience and favorable comparison of analysis with actual BWR test data.

A detailed description of this model is documented in References 8, 9, and 10. SRVs are simulated in a nonlinear representation, and the model thereby allows full investigation of the various valve response times, valve capacities, and actuation set points that are available in applicable hardware systems.

Typical valve characteristics as modeled are shown in Fig. 5.2-2A and 5.2-2B for the power-activated relief and spring-action safety modes of the dual-purpose SRVs. The associated bypass, main turbine control valve, and MSIV characteristics are also simulated in the model.

5.2.2.2.2

System Design

A parametric study was conducted to determine the required steam flow capacity of the SRVs based on the following assumptions.

RBS USAR Revision 28 5.2-5 5.2.2.2.2.1 Operating Conditions The operating conditions assumed in the overpressure analysis are:

1.

Operating power = 3100 MWt (100.3 percent of nuclear boiler rated power)

2.

Vessel dome pressure < 1078 psig

3.

Steamflow = 13.506 x 106 lb/hr (100.6 percent of nuclear boiler rated steamflow).

These conditions are the most severe because maximum stored energy exists at these conditions. At lower power conditions, the transients would be less severe. The corresponding nominal values at 100 percent nuclear boiler rated power and steam flow are 3091 MWt, 13.424 x 106 lb/hr and 1055 psig.

5.2.2.2.2.2 Transients The overpressure protection system must accommodate the most severe pressurization transient. There are two major transients, the closure of all MSIVs and a turbine/generator trip with a coincident closure of the turbine steam bypass system valves that represent the most severe abnormal operational transients resulting in a nuclear system pressure rise. The evaluation of transient behavior with final plant configuration has shown that the isolation valve closure is slightly more severe when credit is taken only for indirect derived scrams; therefore, it is used as the overpressure protection basis event and shown in Fig. 5.2-1. Table 5.2-9 lists the sequence of events for the MSIV closure event with flux scram and with the installed SRV capacity for initial core. The current reloads results can be found the cycle specific SRLR.

5.2.2.2.2.3 Scram Control rod drive scram motion is shown in Fig. 5.2-3. Time zero in Fig. 5.2-3 is the time when the real variable exceeds the scram setpoint. The delay time indicated (0.07 sec) includes both sensor delay time (0.02 sec) and scram circuit initiation delay (0.05 sec). The sensor delay time is variable according to the sensor used. The 0.02 sec shown in Fig. 5.2-3 is for load rejection only. Sensor delay times specified for different scrams have been used in the transient analysis.

5.2.2.2.2.4 Safety/Relief Valve Transient Analysis Specification

1.

Simulated valve groups:

a.

Power-actuated relief mode - 4 groups

b.

Spring-action safety mode - 5 groups

2.

Pressure set point (maximum safety limit):

a.

Power-actuated relief mode - 1,163 to 1,183 psig

b.

Spring-action safety mode - 1,231 to 1,246 psig

3.

Reclosure pressure set point (percentage of opening set point) - both modes:

RBS USAR Revision 27 5.2-6

a.

Maximum safety limit (used in analysis) - 98%

b.

Minimum operational limit - (not used in analysis).

The opening and closure set points are assumed at a conservatively high level above the nominal set points. This is to account for initial set point errors and any instrument set point drift that might occur during operation. Typically, the assumed set points in the analysis are at least 1 to 2 percent above the actual nominal set points. Highly conservative SRV response characteristics are also assumed. Therefore, the analysis conservatively bounds all safety/relief operating conditions.

5.2.2.2.2.5 Safety/Relief Valve Capacity Sizing of the SRV capacity is based on establishing an adequate margin from the peak vessel pressure to the vessel code limit (1,375 psig) in response to the reference transients.

The safety relief valve discharge coefficient is established by test(7), and the flow capacity is calculated as follows (Reference 7, page iii):

W = 51.5 x A x P x K W = 51.5 x 4.582 (3/4) (1.03 x 1190 + 14.7)0.869 W = 914508 lb/hr where:

W = Steam flow, lb/hr A = Nozzle area, in2 P = 1.03 x setpress + 14.7 psia K = Average coefficient (including 0.9 constant)

(Reference 7, page 34)

The method used to determine total valve capacity is described as follows:

Whenever system pressure increases to the relief pressure set point of a group of valves having the same set point, half of those valves are assumed to operate in the relief mode, opened by the pneumatic power actuation. When the system pressure increases to the valve spring set pressure of a group of valves, those valves not already considered open are assumed to begin opening and to reach full open at 103 percent of the valve spring set pressure.

RBS USAR Revision 27 5.2-7 5.2.2.2.3 Evaluation of Results 5.2.2.2.3.1 Safety/Relief Valve Capacity The required SRV capacity is determined by analyzing the pressure rise from an MSIV closure with flux scram transient. The plant is assumed to be operating at the turbine-generator design conditions at a maximum vessel dome pressure of 1078 psig. The analysis hypothetically assumes the failure of the direct isolation valve position scram. The reactor is shut down by the backup, indirect, high neutron flux scram. For the analysis, the power-actuated relief set points of the SRV are assumed to be in the range of 1163 to 1183 psig and the spring-action safety set points to be in the range of 1,231 to 1,246 psig. The analysis indicates that the design valve capacity is capable of maintaining adequate margin below the peak ASME code allowable pressure in the nuclear system (1,375 psig). Fig. 5.2-1 shows curves produced by this analysis.

The sequence of events in Table 5.2-9 assumed in this analysis was investigated to meet code requirements and to evaluate the pressure relief system exclusively. Under the General Requirements for Protection Against Overpressure as given in Section III of the ASME Boiler and Pressure Vessel Code, credit can be allowed for a scram from the reactor protection system. In addition, credit is taken for the protective circuits which are indirectly derived when determining the required SRV capacity. The backup reactor high neutron flux scram is conservatively applied as a design basis in determining the required capacity of the pressure relieving dual purpose SRVs. Application of the direct position scrams in the design basis could be used since they qualify as acceptable pressure protection devices when determining the required SRV capacity of nuclear vessels under the provisions of the ASME code. The SRVs are operated in a relief mode (pneumatically) at set points lower than those specified for the safety function. This ensures sufficient margin between anticipated relief mode closing pressures and valve spring forces for proper seating of the valves.

The parametric relationship between peak vessel (bottom) pressure and SRV capacity for the MSIV transient with high flux scram is described in Fig. 5.2-4. Also shown in Fig. 5.2-4 is the parametric relationship between peak vessel (bottom) pressure and safety/relief valve capacity for the generator load rejection with a coincident failure of the turbine bypass valves and direct scram, which is the most severe transient when direct scram is considered. Pressures shown for flux scram result only with multiple failures in the redundant direct scram system. Peak pressure at the bottom of the vessel for the MSIV closure-flux scram case is calculated to be 1,265 psig, well below the code limit of 1,375 psig.

The time response of the vessel pressure to the MSIV transient with flux scram and the generator load rejection with a coincident closure of the turbine bypass valves and direct scram for 16 valves is illustrated in Fig. 5.2-5. This shows that the pressure at the vessel bottom exceeds 1,250 psig for less than 2 sec, which is not long enough to transfer any appreciable amount of heat into the vessel metal which was at a temperature well below 550°F at the start of the transient.

5.2.2.2.3.2 Low-Low Set Relief Function In order to assure that no more than one relief valve reopens following a reactor isolation event, one automatic depressurization system (ADS) SRV and four non-ADS valves are provided with lower opening and closing set points. These set points override the normal set points following the initial opening of the relief valves and act to hold open these valves longer, thus preventing more than a single valve from subsequently reopening. This system logic is referred to as the

RBS USAR Revision 27 5.2-8 low-low set relief logic and functions to ensure that the containment design basis of one SRV operating on subsequent actuations is met.

The low-low set relief function is armed from the same pressure sensors which initiate opening of any of the three relief setpoint groups of SRVs (low, medium or high). Thus, the low-low set valves do not actuate during normal plant operation even though the reopening set points of one of the valves is in the normal operating pressure range. This arming method results in the low-low set SRVs opening initially during an overpressure transient at the normal relief opening set point.

The lowest set point low-low set valve cycles to remove decay heat. Table 5.2-2 shows the opening and closing set points for the low-low set SRVs. These set points are based on maintaining certain differences between the normal relief function set points. The SRVs are balanced type, spring loaded safety valves provided with an auxiliary power actuated device which allows opening of the valve even when pressure is less than the safety-set pressure of the valve. Previous undesirable performance on operating BWRs was associated principally with multiple stage pilot operated SRVs. These newer, power-operated safety valves employ significantly fewer moving parts wetted by the steam and are therefore considered an improvement of the previously used valves.

5.2.2.2.3.3 Pressure Drop in Inlet and Discharge Pressure drop on the piping from the reactor vessel to the valves is taken into account in calculating the maximum vessel pressures. Pressure drop in the discharge piping to the suppression pool is limited by proper discharge line sizing to prevent backpressure on each SRV from reducing valve capacity below nameplate rating due to the discharge piping. Each SRV has its own separate discharge line.

5.2.2.3 Piping and Instrument Diagrams Fig. 10.3-1 and 5.2-7 show the schematic location of pressure-relieving devices for:

1.

Reactor coolant system

2.

Primary side of the auxiliary or emergency systems interconnected with the primary system

3.

Any blowdown or heat dissipation system connected to the discharge side of the pressure-relieving devices.

The schematic arrangements of the SRVs are shown in Fig. 5.2-7 and 5.2-8. A P&ID for the main steam safety and relief valve system is provided in Fig. 10.3-1.

5.2.2.4 Equipment and Component Description 5.2.2.4.1 Description The nuclear pressure relief system consists of SRVs located on the main steam lines between the reactor vessel and the first isolation valve within the drywell. These valves protect against overpressure of the nuclear system.

RBS USAR Revision 27 5.2-9 The SRVs provide three main protection functions:

1.

Overpressure relief operation The valves open automatically to limit a pressure rise.

2.

Overpressure safety operation The valves function as safety valves and open (self-actuated operation if not already automatically opened for relief operation) to prevent nuclear system overpressurization.

3.

Depressurization operation The ADS valves open automatically as part of the emergency core cooling system (ECCS) for events involving small breaks in the nuclear system process barrier.

Chapter 15 discusses the events which are expected to activate the primary system SRVs. The section also summarizes the number of valves expected to operate during the initial blowdown of the valves and the expected duration of this first blowdown. For several of the events it is expected that the lowest set SRV reopens and recloses as generated heat drops into the decay heat characteristics. The pressure increase and relief cycle continues with lower frequency and shorter relief discharges as the decay heat drops off and until such time as the RHR system can dissipate this heat. Remote manual actuation of the valves from the main control room is recommended to minimize the total number of these discharges, with the intent of achieving extended valve seat life.

A schematic of the dual function type SRV is shown in Fig. 5.2-9. It is opened by either of two modes of operation:

1.

The safety (pressure) mode of operation is initiated when the direct and increasing static inlet steam pressure overcomes the restraining spring and frictional forces acting against the inlet steam pressure and the disc moves in the opening direction at a faster rate than corresponding disc movements at higher or lower inlet steam pressures. The pressure at which this action is initiated is termed the "popping" pressure and corresponds to the "set pressure" value stamped on the nameplate of the SRV.

2.

The relief (power) mode of operation is initiated when an electrical signal is received at any one of the solenoid valves located on the pneumatic actuator assembly. The solenoid valve(s) opens allowing pressurized air to enter into the lower side of the pneumatic cylinder's piston, pushing the piston and rod upwards.

This action pulls the lifting nut upward via the lever arm mechanism and thereby opens the valve to allow inlet steam to discharge through the SRV even if the inlet pressure is equal to zero.

The pneumatic operator is so arranged that if it malfunctions it does not prevent the valve disk from lifting if steam inlet pressure reaches the spring lift set pressure.

For overpressure SRV operation (self-actuated or spring lift mode), the spring load establishes the safety valve opening set point pressure and is set to open at set points designated in Table 5.2-2. In accordance with the ASME code, the full lift of this mode of operation is attained at a pressure no greater than 3 percent above the set point.

RBS USAR Revision 27 5.2-10 The safety function of the SRV is a backup to the relief function described in the following paragraph. The spring-loaded valves are designed and constructed in accordance with ASME Section III, Subarticle NB-7640, as safety valves with auxiliary actuating devices.

For overpressure relief valve operation (power actuated mode), each valve is provided with a pressure-sensing device which operates at the set points designated in Table 5.2-2. When the set pressure is reached, it operates a solenoid air valve which in turn actuates the pneumatic piston/cylinder and linkage assembly to open the valve.

When the piston is actuated, the delay time, maximum elapsed time between receiving the overpressure signal at the valve actuator and the actual start of valve motion does not exceed 0.1 sec. The maximum elapsed time between signal to actuator and full open position of valve does not exceed 0.2 sec with the inlet system pressure equal to or greater than 1000 psig.

The SRVs can be operated in the power actuated mode by remote-manual controls from the main control room.

Actuation of either solenoid A or solenoid B on the SRV causes the SRV to open; hence, there is no single failure of a logic component or SRV solenoid valve which would result in failure of the main valve to open. The trip units for each SRV within each division are in series, and failure of one of the transmitters shown on Fig. 5.1-3 does not cause the SRVs to open. Each SRV is provided with its own pneumatic accumulator and inlet check valve. The accumulator capacity is sufficient to provide one SRV actuation, which is all that is required for overpressure protection. Subsequent actuations for an overpressure event can be spring actuations to limit reactor pressure to acceptable levels.

The SRVs are designed to operate to the extent required for overpressure protection in the following accident environments:

1.

340°F for 3 hr, at drywell pressure § 45 psig

2.

320°F for an additional 3-hr period, at drywell pressure d 45 psig

3.

250°F for an additional 18-hr period, at 25 psig

4.

Duration of operability is 2 days at 200°F and 20 psig, following which the valves remain fully open or closed for 97 days, provided air and power supply is available.

No power/air supply is required to keep the valve closed.

The ADS utilizes selected SRVs for depressurization of the reactor as described in Section 6.3.

Each of the SRVs is equipped with an air accumulator and check valve arrangement. The accumulators on the SRVs utilized for automatic depressurization assure that the valves can be held open following failure of the air supply to the accumulators. The accumulator capacity is sufficient for each ADS valve to provide two actuations against 70 percent of the maximum drywell design pressure when pressurized to a minimum of 131 psig prior to the start of an accident.

The accumulators are designed to provide two ADS actuations at 70 percent of drywell design pressure, which is equivalent to 4 to 5 actuations at atmospheric pressure. The ADS valves are designed to operate at 70 percent of drywell design pressure because that is the maximum pressure for which rapid reactor depressurization through the ADS valves is required. The

RBS USAR Revision 27 5.2-11 greater drywell design pressures are associated only with the short duration primary system blowdown in the drywell immediately following a large pipe rupture for which ADS operation is not required. For large breaks which result in higher drywell pressure, sufficient reactor depressurization occurs due to the break to preclude the need for ADS. One ADS actuation at 70 percent of drywell design pressure is sufficient to depressurize the reactor and allow inventory makeup by the low pressure ECC systems. However, for conservatism, the accumulators are sized to allow 2 actuations at 70 percent of drywell design pressure. The system is qualified to perform its function for a minimum of 100 days following an accident.

The River Bend Station design utilizes 60-gal accumulators and an air charging system. The air supply system includes two ASME III Division I, Class 2 air compressors and two non-nuclear safety (NNS) compressors which feed two separate charging systems for the accumulators. Both ASME III compressors are powered from the preferred ac power supply systems and can be powered by on-site power. Each charging system consists of an air dryer and associated piping and valves necessary to provide air to each of the two divisional sets of accumulators. Each charging system has physical separation in order to protect them from postulated pipe breaks.

Only two of the ADS valves need to function to meet short-term demands and the functional operability of only one ADS valve can fulfill longer term needs.

The air supply to the ADS valves has been designed such that the failure of any one component does not result in the loss of air supply to more than one nuclear safety-related division of ADS valves. The loss of air supply to one division of ADS valves does not prevent the safe shutdown of the unit.

During normal plant operation, SRV and ADS accumulators are supplied with air from the non-nuclear safety (NNS) main steam system air compressors, SVV-C4A and SVV-C4B, as shown in Fig. 10.3-1d. In order to satisfy the requirement of 2 ADS actuations at 70% of drywell design pressure or 4 to 5 actuations at normal drywell pressure, without any makeup air, the ADS accumulators must be charged to a minimum of 131 psig. The SVV compressors are assumed to become unavailable at the start of the accident and makeup air is not available until the penetration valve leakage control system (PVLCS) compressors are started. Post-LOCA air requirements are supplied by the PVLCS compressors, C3A and C3B. Intermediate and long-term operability of the ADS valves is assured with PVLCS delivering air at a minimum pressure of 101 psig. Refer to Section 9.3.6 for a description of PVLCS.

Air dryers downstream of the NNS compressors are designed to dry the air to a dewpoint of

-40°F at 140 psig and filter to a maximum particle size of 1 micron. The required dewpoint is

-24°F at 0 psig (reference GE BWR Requirements Plant Air Specification 22A6489). A Safety Class 2 pressure transmitter which activates an annunciator in the main control room is provided downstream of the dryers to alert the operator to a malfunction and allow him to remote manually isolate and bypass the dryer/filter. Pressure transmitters are also provided on the PVLCS air accumulators as described in Section 9.3.6.

Each SRV discharges steam through a discharge line to a point below the minimum water level in the suppression pool. The SRV discharge lines are classified as Safety Class 3 and Seismic Category I. SRV discharge line piping from the SRV to the suppression pool consists of two parts. The first is attached at one end to the SRV and attached at its other end to a pipe anchor. The main steam piping, including the SRV discharge piping up to and including the first

RBS USAR Revision 27 5.2-12 anchor, is analyzed as a complete system. Diameter, length, and routing of the SRV piping are given in Appendix 6A, Table A.6A.4-1 and Fig. A.6A.10-1 and A.6A.10-2.

The second part of the SRV discharge piping extends from the anchor to the suppression pool.

Because of the upstream anchor on this part of the line, it is physically decoupled from the main steam header and is therefore analyzed as a separate piping system.

The effect of the alternate shutdown cooling mode on SRV discharge piping has been considered. The resultant load distribution is within the design capacity of the spring hangers and other support structures.

As a part of the preoperational and startup testing of the main steam lines, movement of the SRV discharge lines will be monitored.

The SRV discharge piping is designed to limit valve outlet pressure to 40 percent of maximum valve inlet pressure with the valve wide open. Water in the line more than a few feet above suppression pool water level would cause excessive pressure at the valve discharge when the valve is again opened. For this reason, two vacuum relief valves are provided on each SRV discharge line to prevent drawing an excessive amount of water up into the line as a result of steam condensation following termination of relief operation. The SRVs are located on the main steam line piping, rather than on the reactor vessel top head, primarily to simplify the discharge piping to the pool and to avoid the necessity of having to remove sections of this piping when the reactor head is removed for refueling. In addition, valves located on the steam lines are more accessible during a shutdown for valve maintenance.

The nuclear pressure relief system automatically depressurizes the nuclear system sufficiently to permit the LPCI and the LPCS system to operate as a backup for the HPCS system. Further descriptions of the operation of the automatic depressurization feature are found in Sections 6.3 and 7.3.1.1.1.

5.2.2.4.2 Design Parameters The specified operating transients for components within the RCPB are given in Section 3.9.1.

Refer to Section 3.7 for discussion of the input criteria for design of Seismic Category I structures, systems, and components.

The design requirements established to protect the principal components of the reactor coolant system against environmental effects are discussed in Section 3.11.

5.2.2.4.3 Safety/Relief Valve The ASME capacity rated nozzle bore discharge area of the valve is 16.469 sq in and the coefficient of discharge K(D) is equal to 0.966 (K = 0.9 K(D)).

The design pressure and temperature of the valve inlet and outlet are 1,375 psig at 585°F and 625 psig at 500°F, respectively.

The valves have been designed to achieve the maximum practical number of actuations consistent with state-of-the-art for valve technology.

RBS USAR Revision 27 5.2-13 Cyclic testing has demonstrated an expected service life of at least 60 actuation cycles between required maintenance. For a schematic cross section of the valve, see Fig. 5.2-9.

5.2.2.5 Mounting of Pressure Relief Devices The pressure relief devices are located on the main steam piping. The mounting consists of a special, contoured nozzle and an over-sized flange connection. This provides a high integrity connection that withstands the thrust, bending, and torsional loadings which the main steam pipe and relief valve discharge pipe are subjected to, including:

1.

Thermal expansion effects of the connecting piping

2.

Dynamic effects of the piping due to SSE

3.

Reactions due to transient unbalanced wave forces exerted on the SRVs during the first few seconds after the valve is opened and prior to the time steady-state flow has been established. (With steady-state flow, the dynamic flow reaction forces are self-equilibrated by the valve discharge piping.)

4.

Dynamic effects of the piping and branch connection due to the main turbine stop valve closure

5.

Dynamic effects on the piping due to hydrodynamic loads.

In no case are allowable valve flange loads exceeded nor does the stress at any point in the piping exceed code allowables for any specified combination of loads. The design criteria and analysis methods for considering loads due to SRV discharge are contained in Section 3.9.3.3.

5.2.2.6 Applicable Codes and Classification The vessel overpressure protection system is designed to satisfy the requirements of ASME Section III. The general requirements for protection against overpressure of ASME Section III recognize that reactor vessel overpressure protection is one function of the reactor protective systems and allows the integration of pressure relief devices with the protective systems of the nuclear reactor. Hence, credit is taken for the scram protective system as a complementary pressure protection device. The NRC has also adopted the ASME Codes as part of their requirements in 10CFR50.55a.

5.2.2.7 Material Specification The safety-relief valves for RBS are manufactured by Crosby Valve and Gauge Company, Wrentham, MA.

Material specifications of pressure retaining components of SRVs valves are reported in Table 5.2-3. Viton-E rubber U-cup and O-ring are used in the pneumatic actuator. Material selections for this type of safety-relief valve (Crosby dual-function) are in accordance with ASME Section III and are suitable for the intended environment and functional application.

Successful qualification test results confirmed the adequacy of material selections. There is no air accumulator integral to the design of the Crosby safety-relief valve. The pneumatic actuator, when pressurized from an external air source, provides the relief mode of operation. Based upon qualification test results, the pneumatic actuator assembly, including solenoid valves, was

RBS USAR Revision 27 5.2-14 demonstrated to be operable for a minimum of 300 cycles without refurbishment. Each safety-relief valve and actuator assembly is subjected to relief operations to verify proper operability and leak tightness prior to delivery.

5.2.2.8 Process Instrumentation Overpressure protection process instrumentation is listed in Table I of Fig. 5.1-3b and shown on Fig. 5.1-3a.

5.2.2.9 System Reliability The system is designed to satisfy the requirements of ASME Section III. Therefore, it has high reliability. The consequences of failure are discussed in Sections 15.1.4 and 15.6.1.

5.2.2.10 Inspection and Testing The Crosby dual-function safety-relief valve design has been subjected to the following engineering qualification tests with results in compliance with the valve design specifications.

1.

Life Cycle - 300 relief modes of operation under normally installed (steam) conditions with leakage not greater than 100 lb/hr after 50 cyclic operations.

2.

Solenoid Qualification - Operable after being subjected to a continuous steam environment for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and qualified for 100 days post accident in a harsh environment such as discussed in USAR Section 5.2.2.4.1.

3.

Seismic and Moment Transfer Qualification - Structural and functional acceptability under OBE and SSE conditions with and without moments applied at 4.5g horizontal and 3g vertical.

4.

Normal vs. Elevated Ambient Setpoint Correlation Verification Test - Verification of proper spring set-pressure at factory as compared to an installed elevated design ambient environment of 135°F.

5.

Valve Capacity - Certified by the National Board of Boiler and Pressure Vessel Inspectors.

6.

Blowdown - Qualified by use of full-flow steam test loop.

Each SRV is production tested at the vendor's shop in accordance with quality control procedures to detect anomalies and to demonstrate operability prior to delivery for installation.

The following tests are conducted:

1.

Hydrostatic inlet and outlet tests at specified test conditions.

2.

Each valve is steam seat leak tested at 90 percent of the nameplate set pressure value with a maximum permitted leakage acceptance criterion of 1 lb/hr.

3.

Set pressure and blowdown test: Each valve is pressure popped with saturated steam. The valve must operate within +0 percent to -2 percent of the nameplate set pressure value for acceptance. The nameplate set pressure value defines the

RBS USAR Revision 27 5.2-15 set pressure of the valve when the valve is in a thermally stabilized condition and with an environmental ambient condition of 135°F. Blowdown testing is in a range of 11 percent to 2 percent blowdown with a backpressure of 20 percent to 45 percent of inlet pressure.

4.

Response time test: Each SRV is tested to demonstrate acceptable opening, closing, and response time characteristics.

5.

Relief actuator test: The electro-pneumatic actuator is nitrogen leak checked and the valve is power actuated with electrical, pneumatic, and inlet steam systems activated.

The valves are installed as received from the factory. The GE equipment specification requires certification from the valve manufacturer that design and performance requirements have been met. This includes capacity and blowdown requirements. The set points are adjusted, verified, and indicated on the valves by the vendor. Specified manual and automatic actuation relief mode of each SRV is verified during the preoperational test program as discussed in Chapter 14.

It is not feasible to test the SRV set points while the valves are in place. The valves are mounted on 1,500-lb primary service rating flanges. They can be removed for maintenance or bench checks and reinstalled during normal plant shutdowns. All River Bend Station safety-relief valves are inspected and tested a maximum of every 5 years to meet the requirements of ASME OM Code.

The inspection covers accessible internal and external surfaces and parts. Additional detailed inspection is provided for internal parts indicating severe wear and for all gaskets and seals during valve maintenance. Testing is accomplished by simulating operating conditions where possible and verifying: 1) the set pressure of a sample of the installed valves, and 2) the stroke capability using the pneumatic power actuator. Leak testing is conducted on the pneumatic actuator and the valve main seat.

All SRVs are refurbished as necessary to meet ASME OM Code requirements. This consists of disassembly and inspection of all internals for wear, damage or erosion, and replacement, as necessary, of any gaskets, seals, or parts. The valves are relapped and lubricated.

Reassembled valves are retested, and appropriate adjustments are made prior to use.

5.2.2.11 Safety Relief Valve (SRV) Surveillance River Bend Station is meeting the intent of NUREG-0152 through participation in the Institute of Nuclear Power Operations (INPO) Operating Experience program, the 10CFR50.65 Maintenance Rule process, and the site corrective action program.

5.2.2.12 SRV Position Indication Two methods are provided on River Bend Station for reliable position indication of the main steam SRVs.

1.

SRV Discharge Pipe Temperature

RBS USAR Revision 27 5.2-16 One thermocouple is provided on each SRV discharge pipe. A high temperature reading will be caused by steam flow in the pipe, and is indicative of the opening of an SRV. The thermocouple outputs are recorded in the main control room. The recorder and thermocouples are powered from a nonessential bus.

2.

Acoustic Monitoring of SRV Discharge Pipe Positive indication of SRV position is provided by acoustic sensors strapped to the SRV discharge pipe. An accelerometer-type sensor is mounted on each SRV discharge pipe to detect the vibration generated by flow through an open SRV.

By using the relationship between valve flow rate and the corresponding vibration level produced by the flow, the valve status is assessed.

The acoustic signals are conditioned and preamplified before being fed to the acoustic monitoring panel in the control building. This panel provides individual contact outputs for main control room indicating lights for SRV Open indication, and a common output relay for annunciation in the main control room, when any one of the 16 SRVs is not fully closed.

Additional features of the acoustic monitoring system are:

a.

The system is seismically and environmentally qualified in accordance with IEEE 344-1975 and IEEE 323-1974, respectively.

b.

The monitoring system and associated main control room indicating lights are powered from a Class 1E power supply.

c.

The system has provisions for periodic testing while in operation.

The SRV acoustic monitoring system provides a highly reliable indication of SRV position, while the SRV discharge pipe temperature recorder provides confirmation.

Two systems can be used by the operator in conjunction with the SRV pilot-actuation indicating lights (which show that SRV actuation signal is present) to access proper SRV operation.

5.2.3 Reactor Coolant Pressure Boundary Materials 5.2.3.1 Material Specifications Table 5.2-3 lists the principal pressure-retaining materials and the appropriate material specifications for the RCPB components.

5.2.3.2 Compatibility with Reactor Coolant 5.2.3.2.1 PWR Chemistry of Reactor Coolant Not applicable to BWRs.

RBS USAR Revision 27 5.2-17 5.2.3.2.2 BWR Chemistry of Reactor Coolant Materials in the reactor coolant system are primarily austenitic stainless steel and Zircaloy cladding. The reactor water chemistry limits are established to provide an environment favorable to these materials. Limits are placed on conductivity and chloride concentrations.

Conductivity is limited because it can be continuously and reliably measured and gives an indication of abnormal conditions and the presence of unusual materials in the coolant.

Chloride limits are specified to prevent stress corrosion cracking of stainless steel(2).

Several investigations have shown that in neutral solutions some oxygen is required to cause stress corrosion cracking of stainless steel, while in the absence of oxygen no cracking occurs.

One of these is the chloride-oxygen relationship of Williams where it is shown that at high chloride concentration little oxygen is required to cause stress corrosion cracking of stainless steel, and at high oxygen concentration little chloride is required to cause cracking(3). These measurements were determined in a wetting and drying situation using alkaline-phosphate-treated boiler water and, therefore, are of limited significance to BWR conditions. They are, however, a qualitative indication of trends.

The water quality requirements are further supported by GE stress corrosion test data summarized as follows:

1.

Type 304 stainless steel specimens were exposed in a flowing loop operating at 537°F. The water contained 1.5 ppm chloride and 1.2 ppm oxygen at a pH of 7.

Test specimens were bent beam strips stressed over their yield strength. After 2,100 hr exposure, no cracking or failures occurred.

2.

Welded Type 304 stainless steel specimens were exposed in a refreshed autoclave operating at 550°F. The water contained 0.5 ppm chloride and 1.5 ppm oxygen at a pH of 7. Uniaxial tensile test specimens were stressed at 125 percent of their 550°F yield strength. No cracking or failures occurred at 15,000 hr exposure.

When conductivity is in its normal range, pH, chloride, and other impurities affecting conductivity are also within their normal range. When conductivity becomes abnormal, chloride measurements are made to determine whether or not they are also out of their normal operating values. This is not necessarily the case. Conductivity may be high due to the presence of a neutral salt which does not have an effect on pH or chloride. In such a case, high conductivity alone is not a cause for shutdown. In some types of water-cooled reactors, conductivities are high because of the purposeful use of additives. In BWRs, however, where no additives are used and where near neutral pH is maintained, conductivity provides a good and prompt measure of the quality of the reactor water. Significant changes in conductivity provide the operator with a warning mechanism so he can investigate and remedy the condition before reactor water limits are reached. Methods available to the operator for correcting the off-standard condition include operation of the reactor water cleanup system (RWCU), reducing the input of impurities, and placing the reactor in the cold shutdown condition. The major benefit of cold shutdown is to reduce the temperature-dependent corrosion rates and provide time for the cleanup system to re-establish the purity of the reactor coolant.

RBS USAR Revision 27 5.2-18 Following is a summary and description of BWR water chemistry for various plant conditions.

1.

Normal Plant Operation The BWR system water chemistry is conveniently described by following the system cycle as shown on Fig. 5.2-10. Reference to Table 5.2-4 has been made as numbered on the diagram and correspondingly in the table.

For normal operation starting with the condenser-hotwell, condensate water is processed through a condensate demineralizer system resulting in effluent water quality represented in Table 5.2-4.

The effluent from the condensate treatment system is pumped through the feedwater heater train, and enters the reactor vessel at an elevated temperature and with a chemical composition typically as shown in Table 5.2-4.

During normal plant operation, boiling occurs in the reactor, decomposition of water takes place due to radiolysis, and oxygen and hydrogen gas are formed. Due to steam generation, stripping of these gases from the water phase takes place, and the gases are carried with the steam through the turbine to the condenser. The oxygen level in the steam, resulting from this stripping process, is typically observed to be about 20 ppm (Table 5.2-4). At the condenser, deaeration takes place and the gases are removed from the process by means of steam jet air ejectors (SJAEs). The deaeration is completed to a level of approximately 20 ppb (0.02 ppm) oxygen in the condensate.

The dynamic equilibrium in the reactor vessel water phase established by the steam-gas stripping and the radiolytic formation (principally) rates, corresponds to a nominal value of approximately 200 ppb (0.2 ppm) of oxygen at rated operating conditions. Slight variations around this value have been observed as a result of differences in neutron flux density, core-flow, and recirculation flow rate.

A RWCU system is provided for removal of impurities resulting from fission products formed in the primary system. The cleanup process consists of filtration and ion exchange, and serves to maintain a high level of water purity in the reactor coolant.

Typical chemical parametric values for the reactor water are listed in Table 5.2-4 for various plant conditions.

Additional water input to the reactor vessel originates from the control rod drive (CRD) cooling water. The CRD water is approximately feedwater quality. Separate filtration for purification and removal of insoluble corrosion products takes place within the CRD system prior to entering the drive mechanisms and reactor vessel.

No other inputs of water or sources of oxygen are present during normal plant operation.

During plant conditions other than normal operation additional inputs and mechanisms are present as outlined in the following section.

2.

Plant Conditions Outside Normal Operation During periods of plant conditions other than normal power production, transients take place, particularly with regard to the oxygen levels in the primary coolant. Oxygen levels in the

RBS USAR Revision 27 5.2-19 primary coolant vary from the normal during plant startup, plant shutdown, hot standby, and when the reactor is vented and depressurized. The hotwell condensate absorbs oxygen from the air when vacuum is broken on the condenser. Prior to startup and input of feedwater to the reactor, vacuum is established in the condenser and deaeration of the condensate takes place by means of mechanical vacuum pump and SJAE operation and condensate recirculation.

During these plant conditions, continuous input of CRD cooling water takes place as described previously.

a.

Plant Depressurized and Reactor Vented During certain periods such as during refueling and maintenance outages, the reactor is vented to the condenser or atmosphere. Under these circumstances the reactor cools and the oxygen concentration increases to a maximum value of 8 ppm. Equilibrium between the atmosphere above the reactor water surface, the CRD cooling water input, any residual radiolytic effects, and the bulk reactor water is established after some time. No other changes in water chemistry of significance take place during this plant condition because no appreciable inputs take place.

b.

Plant Transient Conditions - Plant Startup/Shutdown During these conditions, no significant changes in water chemistry other than oxygen concentration take place.

1.

Plant Startup Depending on the duration of the plant shutdown prior to startup and whether the reactor has been vented, the oxygen concentration could be that of air saturated water, i.e., approximately 8 ppm oxygen.

Following nuclear heatup initiation, the oxygen level in the reactor water decreases rapidly as a function of water temperature increase and correspondingly reduced oxygen solubility in water. The oxygen level reaches a minimum of about 20 ppb (0.02 ppm) at a coolant temperature of about 380°F, at which point an increase takes place due to significant radiolytic oxygen generation. For the elapsed process up to this point the oxygen is degassed from the water and is displaced to the steam dome above the water surface.

Further increase in power increases the oxygen generation as well as the temperature. The solubility of oxygen in the reactor water at the prevailing temperature controls the oxygen level in the coolant until rated temperature (540°F) is reached. Thus, a gradual increase from the minimum level of 20 ppb to a maximum value of about 200 ppb oxygen takes place. At, and after this point (540°F) steaming and the radiolytic process control the coolant oxygen concentration to a level of around 200 ppb.

2.

Plant Shutdown Upon plant shutdown following power operation, the radiolytic oxygen generation essentially ceases as the fission process is terminated. Because oxygen is no longer generated, while some steaming still takes place due to residual energy, the oxygen concentration in the coolant decreases to a minimum value determined by steaming rate temperature. If venting is performed, a gradual increase to

RBS USAR Revision 27 5.2-20 essentially oxygen saturation at the coolant temperature takes place, but does not exceed a maximum value of 8 ppm oxygen.

3.

Oxygen in Piping and Parts Other Than the Reactor Vessel Proper As can be concluded from the preceding descriptions, the maximum possible oxygen concentration in the reactor coolant and any other directly related or associated parts is that of air saturation at ambient temperature. At no time or location, in the water phase, do oxygen levels exceed the nominal value of 8 ppm.

As temperature is increased and hence, oxygen solubility decreased accordingly, the oxygen concentration is maintained at this maximum value, or reduced below it depending on available removal mechanisms, i.e., diffusion, steam stripping, flow transfer, or degassing.

Depending on the location, configuration, etc, such as dead legs or stagnant water, inventories may contain 8 ppm dissolved oxygen or some other value below this maximum limitation.

Conductivity of the reactor coolant is continuously monitored by instruments connected to redundant sources: the reactor water recirculation loop and the RWCU system inlet. Effluent from the RWCU system is also monitored for conductivity on a continuous basis. These measurements provide reasonable assurance for adequate surveillance of the reactor coolant.

Grab samples are provided, for the locations shown in Table 5.2-6, for special and noncontinuous measurements such as pH, oxygen, chloride, and radiochemical measurements.

During normal plant operation, hydrogen is injected into the feedwater system to suppress the free oxygen in the reactor vessel in order to alleviate the potential for IGSCC in certain key areas of the reactor and recirculation piping. Hydrogen injection does not impact the ionic concentrations or other chemistry parameters as discussed in this SAR section or Table 5.2-4 except for suppression of feedwater and reactor oxygen as discussed below and per Table 5.2-

4.

The system cycle is the same as for normal water chemistry operation as discussed above, with the exception of dissolved oxygen concentrations. Injection of excess free hydrogen into reactor feedwater shifts the stoichiometric oxygen concentration in the reactor vessel. With NobleChemTM injection to the plant, the amount of hydrogen required for IGSCC mitigation is reduced. The Noble Metal applied attaches to the metal surfaces and acts as a catalyst for hydrogen-oxygen recombination. As a result the oxygen levels adjacent to the metal surface are reduced to near zero concentrations and the bulk fluid still contains oxygen though at reduced levels from normal water chemistry (NWC). The oxygen transported down the steam lines is reduced from NWC, though not reduced to near zero. Offgas and condensate oxygen levels are reduced from those of NWC, but not as low as for Moderate HWC. The hydrogen water chemistry system as discussed in section 9.5.10 provides oxygen injection into both of these systems to restore the desired oxygen levels to normal water chemistry concentrations.

Section 12.1.3 provides a discussion of ALARA IMPCATS due to hydrogen water chemistry.

The relationship of chloride concentration to specific conductance measured at 25°C for chloride compounds such as sodium chloride and hydrochloric acid can be calculated, as shown on Fig. 5.2-11. Values for these compounds essentially bracket values of other common chloride salts or mixtures at the same chloride concentration. Surveillance requirements are based on these relationships.

RBS USAR Revision 27 5.2-21 In addition to this program, limits, monitoring, and sampling requirements are imposed on the condensate, condensate treatment system and feedwater by warranty requirements and specifications. Thus, a total plant water quality surveillance program is established providing assurance that off specification conditions are quickly detected and corrected.

The sampling frequency when reactor water has a low specific conductance is adequate for calibration and routine audit purposes. When specific conductance increases, and higher chloride concentrations are possible, or when continuous conductivity monitoring is unavailable, increased sampling is provided (see plant technical requirements).

For the higher than normal limits of <1 Pmho/cm, more frequent sampling and analyses are invoked by the coolant chemistry surveillance program.

The primary coolant conductivity monitoring instrumentation ranges and accuracy, and sensor, indicator, and recorder locations are shown in Table 5.2-6. The sampling is coordinated in a reactor sample station especially designed with constant temperature control and sample conditioning and flow control equipment.

c.

Water Purity During Condenser Leakage The condensate cleanup system is designed to maintain the reactor water chloride concentration during a condenser tube leak as described in Section 10.4.6.2.

Regulatory Guide 1.56 describes an acceptable method of implementing GDC 13, 14, 15, and 31 of 10CFR50, Appendix A, with regard to minimizing the probability of corrosion-induced failure of the RCPB in BWRs by maintaining accept-able purity levels in the reactor coolant, and acceptable instrumentation to determine the condition of the reactor coolant.

As discussed previously, the materials in the primary system are primarily austenitic stainless steel and Zircaloy cladding. The reactor water chemistry limits have been established to provide an environment favorable to these materials. Design engineering and Technical Requirement limits are placed on conductivity and chloride concentrations. Operationally, the conductivity is limited because it can be continuously and reliably measured and gives an indication of abnormal conditions and the presence of unusual materials in the coolant.

Chloride limits are specified to prevent stress corrosion cracking of stainless steel.

The water quality requirements are further supported by General Electric Topical Report NEDO-10899(2).

5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant The materials of construction exposed to the reactor coolant consist of the following:

1.

Solution annealed austenitic stainless steels (both wrought and cast); Types 304, 304L, 316, 316K, and 316L

2.

Nickel base alloys - Inconel 600 and Inconel 750X

3.

Carbon steel and low alloy steel

RBS USAR Revision 27 5.2-22

4.

Some 400 series martensitic stainless steel (all tempered at a minimum of 1,100°F)

5.

Colmonoy and Stellite hardfacing material.

All of these materials of construction are resistant to stress corrosion for their application in the BWR coolant. General corrosion on all materials, except carbon and low alloy steel, is negligible. Conservative corrosion allowances are provided for all exposed surfaces of carbon and low alloy steels.

Contaminants in the reactor coolant are controlled to very low limits by the reactor water quality specifications. No detrimental effects will occur on any of the materials from allowable contaminant levels in the high purity reactor coolant. Expected radiolytic products in the BWR coolant have no adverse effects on the construction materials.

5.2.3.2.4 Compatibility of Construction Materials with External Insulation Nonmetallic insulation materials used on all stainless-steel components at RBS comply with Regulatory Guide 1.36 and have the proper ratio of leachable sodium plus silicate ions to leachable chloride plus fluoride ions.

5.2.3.3 Fabrication and Processing of Ferritic Materials 5.2.3.3.1 Fracture Toughness 5.2.3.3.1.1 Compliance with Code Requirements

1.

Ferritic materials used for piping, pumps, and valves of the RCPB are 2 1/2 in or less in thickness. Impact testing in accordance with NB-2332 for thicknesses of 2 1/2 in or less.

2.

Materials for bolting with nominal diameters exceeding 1 in meet both the 25 mils lateral expansion specified in NB-2333 and the 45 ft-lb Charpy V value specified in Appendix G of 10CFR50.

3.

The reactor vessel complies with the requirements of NB-2331 and Appendix G of 10CFR50. The reference temperature, RTNDT, was established for all required pressure retaining materials used in the construction of Class I vessels. This includes plates, forgings, and weld material. The RTNDT differs from the nil-ductility temperature, NDT, in that in addition to passing the drop weight test, three Charpy V-notch specimens (transverse) must exhibit 50 ft-lb absorbed energy and 35 mil lateral expansion at 60°F above the RTNDT. The core beltline material meets 70 ft-lb absorbed upper shelf energy.

4.

Fracture toughness data are provided in Table 5.3-1. The calibration of instruments and equipment such as temperature instruments and Charpy V-notch impact test machines used in impact testing is performed in accordance with ASME Code Section III, 1971

Edition, Summer 1973

Addenda, subsection NB-2360, "Calibration of Instruments and Equipment."

RBS USAR Revision 27 5.2-23 5.2.3.3.2 Control of Welding 5.2.3.3.2.1 Control of Preheat Temperature Employed for Welding of Low Alloy Steel (Regulatory Guide 1.50)

Regulatory Guide 1.50 delineates preheat temperature control requirements and welding procedure qualifications supplementing those in ASME Sections III and IX.

Welding of low alloy steel is restricted to the reactor pressure vessel. Other ferritic components in the RCPB to be welded are fabricated from carbon steel materials. New welding procedure qualifications were qualified with the test assembly preheat temperature maintained within 50 degrees above the minimum preheat temperature.

Preheat temperatures employed for welding of low alloy steel meet or exceed the recommendations of ASME Section III, Subsection NB. Components were either held for an extended time at preheat temperature to assure removal of hydrogen or preheat was maintained until post weld heat treatment. The minimum preheat and maximum weld interpass temperatures were specified and monitored.

NOTE:

The above restrictions only apply when using electrodes utilizing hygroscopic welding fluxes. They are not applicable when the GTAW process is used and the preheat temperature is maintained sufficient to drive and keep off any moisture from the base metal prior to welding. To avoid the effect of cold cracking, the preheat is maintained for one hour additional after completion of the weld and then allowed to cool slowly to ambient.

5.2.3.3.2.2 Control of Electroslag Weld Properties (Regulatory Guide 1.34)

No electroslag welding was performed on BWR components.

5.2.3.3.2.3 Welder Qualification for Areas of Limited Accessibility (Regulatory Guide 1.71)

Qualification for areas of limited accessibility is discussed in Section 5.2.3.4.2.3.

5.2.3.3.2.4 Control of Stainless-Steel Weld Cladding of Low-Alloy Steel Components (Regulatory Guide 1.43)

Reactor pressure vessel specifications require that all low alloy steel be produced to fine grain practice. The requirements of this regulatory guide are not applicable to the River Bend Station RCPB.

5.2.3.3.2.5 Nondestructive Examination (NDE)

Extruded seamless pipe was examined in accordance with ASME Code,Section III, NB-2550, and this required 100 percent ultrasonic examination as specified by NB-2552.1(b) and (c). The plate for seam-welded pipe and fittings was examined ultrasonically according to the requirements of NB-2560 and its reference NB-2531, which specifies 100 percent angle beam ultrasonic examination over the entire volume. Subsequent to rolling and welding, 100 percent of the welded seams were radiographed as required by NB-2561 of the ASME Code,Section III.

RBS USAR Revision 27 5.2-24 5.2.3.3.3 Moisture Control for Low Hydrogen, Covered Arc-Welding Electrodes All low hydrogen covered welding electrodes are stored in controlled storage areas, and only authorized persons are permitted to release and distribute electrodes. Electrodes are received in hermetically sealed canisters. After removal from the sealed containers, electrodes which are not immediately used are placed in storage ovens which are maintained at about 250°F (generally 200°F minimum).

Electrodes are distributed from sealed containers or ovens as required. At the end of each work shift, unused electrodes are returned to the storage ovens. Electrodes which are damaged, wet, or contaminated are discarded. If any electrodes are inadvertently left out of the ovens for more than one shift, they are discarded or reconditioned in accordance with the manufacturer's instructions.

5.2.3.4 Fabrication and Processing of Austenitic Stainless Steels 5.2.3.4.1 Avoidance of Stress Corrosion Cracking 5.2.3.4.1.1 Avoidance of Significant Sensitization Regulatory Guide 1.44's purpose is to address 10CFR50 Appendix A, GDCs 1 and 4, and Appendix B requirements to control "the application and processing of stainless steel to avoid severe sensitization that could lead to stress corrosion cracking." The guide proposes that this should be done by limiting sensitization due to welding as measured by ASTM A262 Practice A or E, or another method that can be demonstrated to show nonsensitization in austenitic stainless steel.

All austenitic stainless steel was purchased in the solution heat treated condition in accordance with applicable ASME and ASTM specifications. Carbon content of wrought austenitic stainless steel was limited to 0.08 percent maximum, and cooling rates from solution heat treating temperatures were required to be rapid enough to prevent sensitization. Welding heat input was restricted to 110,000 joules per inch maximum, and weld interpass temperature to 350°F.

High heat welding processes such as block welding and electroslag welding were not permitted.

All weld filler metal and castings were required by specification to have a minimum of 5 percent ferrite.

Whenever any wrought austenitic stainless steel was heated to temperatures over 800°F, by means other than welding or thermal cutting, the material was subsequently solution annealed.

These controls were used to avoid severe sensitization and to comply with the intent of Regulatory Guide 1.44.

5.2.3.4.1.2 Process Controls to Minimize Exposure to Contaminants Exposure to contaminants capable of causing stress corrosion cracking of austenitic stainless-steel components was avoided by carefully controlling all cleaning and processing materials which contact the stainless-steel during manufacture and construction.

Special care was exercised to ensure removal of surface contaminants prior to any heating operations. Water quality for cleaning, rinsing, flushing, and testing was controlled and

RBS USAR Revision 27 5.2-25 monitored. Suitable packaging and protection was provided for components to maintain cleanliness during shipping and storage.

The degree of surface cleanliness obtained by these procedures meets the requirements of Regulatory Guide 1.44.

5.2.3.4.1.3 Cold Worked Austenitic Stainless Steels Austenitic stainless steels with a yield strength greater than 90,000 psi are not used.

5.2.3.4.1.4 Hydrogen Water Chemistry Injection of excess free hydrogen into reactor feedwater along with Noble metal chemical injection, shifts the stoichiometric oxygen concentration in the reactor vessel to near zero concentrations adjacent to the metal surfaces, which results in a lower vessel electrochemical corrosion potential (ECP) value. Laboratory and in-situ tests have shown that reduction of the reactor water ECP below -230 mV standard hydrogen electrode results in reduced susceptibility of lower core internal components to initiate stress corrosion cracking (SCC) or propagate existing cracks.

5.2.3.4.2 Control of Welding 5.2.3.4.2.1 Avoidance of Hot Cracking Regulatory Guide 1.31 describes an acceptable method of implementing requirements with regard to the control of welding when fabricating and joining austenitic stainless-steel components and systems.

Written welding procedures which are approved by GE are required for all primary pressure boundary welds. These procedures comply with the requirements of ASME Sections III and IX and applicable Regulatory Guides. All austenitic stainless-steel weld filler materials are required by specification to have a minimum of 5 percent ferrite. Prediction of ferrite content was made by using the chemical composition in conjunction with the Schaeffler diagram. The use of the 5 percent minimum limit for ferrite content determined by the Schaeffler diagram has been shown to be adequate to prevent hot cracking in austenitic stainless-steel welds. An extensive test program performed by GE, with the concurrence of the Nuclear Regulatory Commission staff, demonstrated that controlling weld filler metal ferrite at 5 percent minimum (by Schaeffler diagram) resulted in production welds which meet the requirements of Regulatory Guide 1.31.

A total of approximately 400 production welds in five BWR plants were measured and all welds met the requirements of Branch Technical Position MTEB No. 5-1 "Interim Regulatory Position of Regulatory Guide 1.31, Control of Stainless Steel Welding."

5.2.3.4.2.2 Electroslag Welds (Regulatory Guide 1.34)

Electroslag welding was not employed for RCPB components.

5.2.3.4.2.3 Welder Qualification for Areas of Limited Accessibility (Regulatory Guide 1.71)

RBS USAR Revision 27 5.2-26 Regulatory Guide 1.71 requires that weld fabrication and repair for wrought low-alloy and high-alloy steels or other materials such as static and centrifugal castings and bimetallic joints should comply with fabrication requirements of ASME Sections III and IX. It also requires additional performance qualifications for welding in areas of limited access.

All construction phase ASME Section III welds were volumetrically inspected in accordance with the requirements of ASME Section III Class 1, in lieu of qualifying welders. There are few restrictive welds involved in the fabrication of BWR components.

Welder qualification for operation phase welds with restrictive access is accomplished by simulated welding. Mock-ups are examined by bend tests or by radiograph.

5.2.3.4.2.4 Nondestructive Examination (NDE)

Extruded seamless pipe was examined in accordance with ASME Section III NB-2550, and this required 100 percent ultrasonic examination as specified by NB-2552.1(b) and (c).

The plate for seam-welded pipe and fittings was examined ultrasonically according to the requirements of NB-2560 and its reference, NB-2531, which specified 100 percent angle beam ultrasonic examination over the entire volume. Subsequent to rolling and welding, 100 percent of the welded seams were radiographed as required by NB-2561 of the ASME Code,Section III.

5.2.4 Inservice Inspection and Testing of Reactor Coolant Pressure Boundary (RCPB)

Inservice inspection (ISI) of ASME Class 1 pressure retaining components, such as vessels, piping, pumps, valves, welds, bolting and supports within the RCPB, will comply with ASME Section XI as required by the Code of Federal Regulations (10CFR50.55a (g)). Exceptions have been documented in requests for relief pursuant to 10CFR50.55 (g) (6) (i).

The initial preservice inspection (PSI) of ASME Class 1 components has been performed in accordance with ASME Section XI. The 1974 Edition, up to and including Winter 1975 Addenda was used for Emergency Core Cooling systems (ECCS) and Residual Heat Removal system (RHS) and the 1977 Edition, up to and including Winter 1978 Addenda was used for the remaining systems. Augmented examinations are established in accordance with regulatory and industry documents, such as Regulatory Guides, Bulletins, Generic Letters and vendor recommendations. Requests for Relief from ASME Section XI requirements that were identified during PSI were submitted to the USNRC and were approved in NUREG-0989, Supplement 3.

The ISI program will be in accordance with an approved ASME Section XI code. Exceptions to this will be identified in the ISI Program plan. IST is addressed in Section 3.9.6A of the USAR.

Details of ISI are contained in the River Bend Station ISI Program Plan. This plan defines ASME Class 1, 2 and 3 components subject to inspection, extent and frequency of examinations, exemptions and requests for relief. The initial plan was submitted to the USNRC for review and acceptance.

RBS USAR Revision 27 5.2-27 5.2.4.1 System Boundary In addition to the reactor pressure vessel (RPV) and support skirt, components and supports within ASME Section III, Class 1 boundaries are subject to the requirements of ASME Code,Section XI, Subarticles IWA, IWB and IWF.

The following systems contain components and supports within the RCPB and are shown on system piping and instrument diagrams (P&ID).

High pressure core spray (CSH), low pressure core spray (CSL), RCPB drains (DTM),

feedwater (FWS), reactor core isolation cooling (ICS), main steam isolation valve leakage control (MSI), main steam (MSS), nuclear boiler instrumentation (RCS), reactor recirculation (RCS), control rod drive (RDS), residual heat removal (RHS), standby liquid control (SLS) and reactor water cleanup (WCS).

5.2.4.2 Arrangement and Accessibility 5.2.4.2.1 General Access During system and component arrangement and design, careful attention was given to physical clearances for allowing personnel and equipment to perform examinations. Access requirements of ASME Section XI have been considered in the design of components, weld joint configuration and system arrangement. In addition, these access requirements are considered during repair, replacements and modifications to systems and components. An ISI program design review was undertaken to identify any exceptions to the access requirements of ASME Section XI with subsequent design modifications or inspection technique development to ensure Code compliance, as required, to the extent practical at this stage of plant design and construction. Additional exceptions may be identified and reported to the USNRC after plant operations as specified in 10CFR50.55a (g) (5) (iv). Space has been provided to handle and store insulation, structural members, radiological shielding and similar material related to the inspection. Suitable hoists, handling equipment, lighting and sources of power are installed at appropriate locations for ISI activities.

5.2.4.2.2 Access to Reactor Pressure Vessel (RPV)

Access to the RPV can only be obtained during planned or unplanned outages.

Access to the exterior surface of the RPV for ISI is provided by shield wall penetration doors, platforms, removable insulation and movable radiation shield wall plugs. An annular space is provided between the vessel exterior and the insulation interior surface to permit insertion of examination devices and personnel. The biological shield wall penetrations are designed with movable radiation plugs and removable insulation to allow sufficient clearance for examinations.

Access to the closure head and head spray vent are provided by removal of the drywell head and insulation hood cover. With the closure head in dry storage, direct examinations can be performed. The RPV flange area, studs, nuts, and washers can be examined with the closure head removed. Access is afforded to the upper interior clad surface of the RPV by removal of the steam dryer and separator assembly. Removal of these components enables the examination of remaining internal components by remote visual techniques. A volumetric examination of the vessel-to-flange weld and closure head-to-flange weld can be performed by applying the search units to the RPV top head areas from one side of the weld only.

RBS USAR Revision 27 5.2-28 Openings in the RPV skirt are provided to permit access to the RPV bottom head for purposes of ISI examinations. The examinations being performed may use manual or automated equipment to obtain the more meaningful examination of circumferential welds, meridional welds and bottom head penetration welds, except where exempted by ASME Section XI.

5.2.4.2.3 Access other than RPV Removable insulation and radiological shielding have been provided on those piping systems requiring volumetric and surface examinations. The placement of pipe supports with respect to the welds requiring inspections has been reviewed and modified, where necessary, to reduce the amount of plant support required in those areas during the time of inspection. Platforms, permanent and temporary, are provided to facilitate ISI requirements. Welds requiring ultrasonic examination have been located to permit examination from at least one side. The surface of welds requiring volumetric and surface examinations has been prepared to permit effective examinations.

5.2.4.3 Examination Techniques and Procedures The visual, surface and volumetric examination techniques, including special techniques and procedures are written in accordance with the requirements of ASME Section XI, Subarticle IWA-2200.

5.2.4.4 Inspection Intervals As defined in ASME Section XI, Subarticle IWA-2400, the inspection interval is ten years, unless otherwise approved by the USNRC. The interval may be extended by as much as one year to permit inspections to be concurrent with planned outages.

The inspection schedule is in accordance with IWB-2400. ISI examinations are performed during planned or unplanned outages occurring during the inspection interval. Examinations will not be performed which require drainage of the reactor vessel or removal of the core solely for the purpose of accomplishing the examination(s).

5.2.4.5 Examination Categories and Requirements The extent of the examinations performed, and the methods used, such as volumetric, surface or visual comply with the requirements of ASME Section XI, Subsection IWB, Table IWB-2500-

1. In addition, PSI complies with IWB-2200.

5.2.4.6 Evaluation of Examination Results Examination results are evaluated to ASME Section XI, IWB-3000 with repairs based on the requirements of IWB-4000.

In addition, as directed by the USNRC (Generic Letter 88-01), evaluation procedures and acceptance criteria for flaws in austenitic piping are in accordance with ASME Section XI, Paragraph IWB-3640. This paragraph was added in the Winter 1983 Addenda of the 1983 Edition of the ASME Code.

RBS USAR Revision 27 5.2-29 5.2.4.7 System Leakage and Hydrostatic Pressure Tests System leakage and hydrostatic tests are conducted in accordance with ASME Section XI, Subarticle IWB-5000 and ASME Code Cases, approved for use at RBS.

5.2.4.8 Augmented Inservice Inspection to Protect Against Postulated Class 1 Piping Failures High energy ASME Class 1 pipe welds located between the first moment limiting restraints, outboard of the isolation valves, are subject to the following additional inspection requirements.

Nonexempt circumferential welds greater than four inches nominal pipe size (NPS) are volumetrically examined each inspection interval as defined in Section 5.2.4.4 in accordance with Section 3.6.2.1.5.2.1A.2.g.

5.2.5 Reactor Coolant Pressure Boundary and ECCS Leakage Detection System 5.2.5.1 Leakage Detection Methods The nuclear boiler leak detection system consists of temperature, pressure, sump level, flow, airborne gaseous and particulate fission product sensors, and process radiation sensors with associated instrumentation used to indicate and alarm leakage from the RCPB and, in certain cases, to initiate signals used for automatic closure of isolation valves to shut off leakage external to the containment. The system is designed to be in conformance with Regulatory Guide 1.45 and Reference Section IEEE 279.

Abnormal leakage from the following systems within the containment is detected, indicated, alarmed and in certain cases isolated:

1.

Main steam lines

2.

RWCU system

3.

RHR system

4.

RCIC system

5.

Feedwater system

6.

HPCS

7.

Coolant systems within the containment

8.

LPCS

9.

RPV

10.

Miscellaneous systems

RBS USAR Revision 28 5.2-30 Leak detection methods used to obtain conformance with Regulatory Guide 1.45 for plant areas inside the drywell differ from those for the areas located outside the drywell. LEAKAGE is defined as follows, to be consistent with TSTF-554, Revision 1, "Revise Reactor Coolant Leakage Requirements":

a.

Identified LEAKAGE

1.

LEAKAGE into the drywell such as that from pump seals or valve packing, that is captured and conducted to a sump or collecting tank; or

2.

LEAKAGE into the drywell atmosphere from sources that are both specifically located and known to not interfere with the operation of leakage detection systems.

b.

Unidentified LEAKAGE - All LEAKAGE into the drywell that is not identified LEAKAGE.

c.

Total LEAKAGE-Sum of the identified and unidentified LEAKAGE.

d.

Pressure Boundary LEAKAGE - LEAKAGE through a fault in a Reactor Coolant System (RCS) component body, pipe wall, or vessel wall. LEAKAGE past seals, packing, and gaskets is not pressure boundary LEAKAGE.

Leakage inside containment and outside the drywell is considered separately and is not included as part of drywell LEAKAGE.

These areas are considered separately as follows:

5.2.5.1.1 Detection of Leakage within the Drywell The primary detection methods for small unidentified leaks within the drywell include monitoring of drywell and pedestal floor drain sump fillup rates, drywell cooler condensate flow rate increases, and airborne gaseous and particulate radioactivity increases. The sensitivity of the primary detection method of monitoring a floor drain sump for unidentified leakage within the drywell is 1 gpm within 1 hr. The sensitivity of the other primary method of detection is listed in Table 11.5-1. These variables are continuously indicated and/or recorded in the main control room. If the unidentified leakage increases to a total of 5 gpm, the detecting instrumentation channel(s), except the drywell cooler condensate high flow rate detection system, trips and activates an alarm in the main control room. No isolation trip occurs. The drywell floor drain sump fill rate and pump turn-on and off times are monitored by a programmable controller (PC) to activate an alarm in the main control room when the leak rate reaches a preset value.

The secondary detection methods, i.e., the monitoring of pressure and temperature of the drywell atmosphere, are used to detect gross unidentified leakage. High drywell pressure alarms and trips the isolation logic which results in closure of the containment isolation valves.

The detection of small identified leakage within the drywell is accomplished by drywell equipment drain sump fillup rate and pump turn on and off times monitoring by the PC used for unidentified leakage. These measurements have a sensitivity for detection of leakage increases of 1 gpm in 1 hr. The PC activates an alarm in the main control room when total leak rate (identified plus unidentified) reaches 25 gpm.

RBS USAR Revision 27 5.2-31 Leakage from thermally hot sources such as the reactor vessel head flange vent drain and valve packings (except for live-loaded valves) are piped to a common header and routed to the drywell equipment drain sump through the drywell equipment drain cooler which condenses the steam before it reaches the sump. The drywell equipment drain cooler is part of the reactor building equipment drain system (refer to Section 9.3.3 and Fig. 9.3-7).

The determination of the source of identified leakage within the drywell is accomplished by monitoring the drain lines to the drywell equipment drain sumps from various potential leakage sources. These include reactor recirculation pump seal drain flow, valve stem leakoff drain line temperatures and reactor vessel head seal drain line pressure. Additionally, temperature is monitored in the SRV discharge lines to the suppression pool to detect leakage through each of the SRVs. All of these monitors, except the reactor recirculation seal drain flow monitor, continuously indicate and/or record in the main control room. All of these monitors trip and activate an alarm in the main control room on detection of leakage from monitored components.

Excessive leakage inside the drywell (e.g., process line break or LOCA within drywell) is detected by high drywell pressure, low reactor water level or steam line flow (for breaks downstream of the flow elements). The instrumentation channels for these variables trip when the monitored variable exceeds a predetermined limit to activate an alarm and trip the isolation logic which closes appropriate isolation valves (Table 5.2-8).

The alarms, indication and isolation trip functions initiated by the leak detection systems are summarized in Tables 5.2-7 and 5.2-8.

5.2.5.1.2 Detection of Leakage External to the Drywell (within Containment)

The detection of leakage within the containment (outside the drywell) is accomplished by detection of level increases in containment floor drain sump and containment equipment drain sump and also monitoring of pump turn on and off times. The containment floor drain sump monitors detect leakage increases with a sensitivity of 1 gpm/hr. The containment equipment drain sump monitors detect leakage increases with a sensitivity of 1 gpm/hr.

In addition, the containment is provided with radiation monitors which could provide an indication of reactor coolant leakage.

These monitors are further described in Sections 11.5.2.1.3.4 and 12.3.4.

5.2.5.1.3 Detection of Leakage External to Containment The areas outside the containment which are monitored for primary coolant leakage are:

equipment areas in the auxiliary building, the main steam tunnel, and the turbine building. The process piping for each system to be monitored for leakage is located in compartments or rooms separate from other systems where feasible so that leakage may be detected by area temperature indications. Each temperature and pressure leakage detection system detects leak rates that are less than the established leakage limits. The sumps outside the containment are equipped with a high-high alarm set point.

1.

Dual element thermocouples are used to sense high ambient temperatures in the monitored areas. The temperature elements are located or shielded so that they are sensitive to air temperatures only and not radiated heat from hot piping or equipment. Increases in ambient temperature indicate leakage of reactor coolant into the area. These monitors have temperature setpoints which are predicated on

RBS USAR Revision 27 5.2-32 an area temperature rise equivalent to reactor coolant leakage into the monitored areas of 25 gpm. The temperature trip set points are a function of room size and the type of ventilation provided. These monitors, except for the turbine building monitors, provide alarm, indication and recording in the main control room, and trip the isolation logic to close selected isolation valves (e.g., the main steam tunnel monitors close the MSIV and MSL drain isolation valves, RWCU system isolation valves, and the RCIC isolation valves, as shown in Table 5.2-8). In addition, the auxiliary building drain sumps have a high-high alarm set point.

2.

The turbine building monitors only provide alarm and indication in the main control room. The turbine building sumps collect leakage and are alarmed for high sump level.

3.

Excess leakage external to the primary containment (e.g., process line break outside containment) is detected by low reactor water level, high process line flow, high ambient temperature in the piping or equipment areas, and high differential flow. These monitors provide alarm and indication in the main control room and trip the isolation logic to cause closure of appropriate system isolation valves on indication of excess leakage (Table 5.2-8).

4.

Each area outside the containment is monitored by the radiation monitoring system and alarms on detection of high radiation level.

5.2.5.1.4 Intersystem Leakage Monitoring Radiation monitors are used to detect reactor coolant leakage into the cooling water systems supplying the RHR heat exchangers, RWCU system nonregenerative heat exchangers, seal coolers for the RHR pumps, and seal coolers for the reactor recirculation pumps. These radiation monitors are part of the process and effluent radiological and sampling systems (Section 11.5).

A radiation monitor is provided to monitor the radiation levels of the service water effluent on each of the two RHR heat exchanger trains (Fig. 9.2-1). Each channel alarms on high radiation conditions indicating reactor coolant leakage into the service water.

Leakage into the RWCU system nonregenerative heat exchangers and the seal coolers for the RHR and the reactor recirculation pumps is detected by a radiation monitor located in the RPCCW system (Fig. 9.2-2). This radiation monitor alarms on high radiation levels, but no isolation functions are provided.

Leakage from the HPCS, LPCS, RCIC, and RHR systems outside containment is detected by a combination of methods including high area temperature, high area radiation, high sump level, and reactor pressure vessel condition (Section 5.2.5.1.3).

Safety systems connected to the reactor coolant pressure boundary (HPCS, LPCS, RHR, and RCIC) are isolated from the reactor coolant system by two or more isolation valves placed in series. Periodic leak testing of each of these pressure isolation valves is performed to ensure the integrity of the valve, demonstrate the adequacy of the redundant pressure isolation function, and give an indication of valve degradation over a period of time. In addition, the pressure in each of these systems is monitored. A high-pressure alarm, located in the main

RBS USAR Revision 27 5.2-33 control room, provides an indication of possible reactor coolant leakage into the system across the pressure isolation valves.

5.2.5.2 Leak Detection Instrumentation and Monitoring 5.2.5.2.1 Leak Detection Instrumentation and Monitoring Inside Drywell

1.

Floor Drain Sump Measurement The normal design leakage collected in the drywell and pedestal floor drain sumps includes unidentified leakage from the CRDs, valve flange leakage, component cooling water, service water, air cooler drains, and any leakage not connected to the equipment drain sump.

Equipment drain sump instrumentation is identical to that of the floor drain sump. Both floor drain sumps have level transmitters that send 4-20 ma signals to the control room where the signal is monitored by a programmable controller and also sent to a recorder. The programmable controller checks the increase in level every 15 min and calculates the leakage rate into each sump it monitors. It totalizes unidentified leakage and actuates an alarm if that total exceeds 5 gpm. The programmable controller totalizes unidentified and identified leakage and actuates an alarm if the total exceeds 25 gpm. It calculates the average total leakage for the last 24 hr giving the leakage rate into each sump it monitors, showing the last four calculations to indicate a trend and displaying the total unidentified, total identified, their sum, and the 24-hr average. The programmable controller displays system status and abnormal system conditions at its display monitor. The display monitor permits download of reports for printing.

A recorder located in the main control room provides independent indication of the identified and unidentified leakage levels. The recorder is a backup for the leak rate detector because it records the change in leakage inventory over time and thereby provides the leakage rate over a specified time period. Abnormal leakage rates are alarmed in the main control room.

2.

Equipment Drain Sump The equipment drain sump collects only identified leakage. This sump receives piped drainage from pump seal leakoff, reactor vessel head flange vent drain, valve stem packing leakoff and upper containment pool bellows seal.

3.

Cooler Condensate Drain Condensate from the drywell coolers is routed to the drywell floor drain sump and is monitored by use of a flow transmitter which measures flow in the condensate drain line and sends signals for indication instrumentation in the main control room. The condensate is measured twice, once as condensate flow rate and then as a portion of the drywell leakage floor drain sump flow rate.

4.

Temperature Measurement The ambient temperature within the drywell is monitored by four dual element thermocouples located equally spaced in the vertical direction within the drywell. An abnormal increase in drywell temperature could indicate a leak within the drywell; therefore, the drywell exit end of the containment penetration guard pipe for the main steam line is also monitored for abnormal temperature rise caused by leakage from the main steam line. Ambient temperatures within the

RBS USAR Revision 27 5.2-34 containment are recorded and alarmed on the leakage detection and isolation system (LD&IS) panel in the main control room.

5.

Fission Product Monitoring The drywell air sampling system is used along with the temperature, pressure, and flow variation method described above to detect leaks of the RCPB. The system continuously monitors the drywell atmosphere for airborne radioactivity (iodine, noble gases, and particulates). The sample is drawn from the drywell. A sudden increase of activity, which may be attributed to steam or reactor water leakage, is annunciated in the main control room (Section 7.6). The radiation detectors associated with fission product monitoring in the drywell air sampling system are powered from a Class 1E source.

6.

Drywell Pressure Measurement The drywell is at a slightly positive pressure during reactor operation and is monitored by pressure sensors. The pressure fluctuates slightly as result of barometric pressure changes and outleakage. A pressure rise above the normally indicated values indicates a possible leak within the drywell. Pressure exceeding the preset values is annunciated in the main control room and safety action is automatically initiated.

7.

Reactor Vessel Head Seal The reactor vessel head closure is provided with double seals with a leakoff connection between seals that is piped through a normally closed manual valve to the equipment drain sump. Leakage through the first seal is annunciated in the main control room. When pressure between the seals increases, the second seal then operates to contain the vessel pressure.

8.

Reactor Water Recirculation Pump Seal Reactor water recirculation pump seal leaks are detected by monitoring flow in the seal drain line. Leakage, indicated by high flow rate, alarms in the main control room. The leakage is piped to the equipment drain sump.

9.

Safety/Relief Valves Temperature sensors connected to a multipoint recorder are provided to detect SRV leakage during reactor operation. SRV temperature elements are mounted, using a thermowell, in the SRV discharge piping several feet downstream from the valve body. Temperature rise above the alarm set point is annunciated in the main control room. See Fig. 10.3-1.

10.

Valve Stem Packing Leakage Valve stem packing leaks of power-operated valves in the recirculation system are detected by monitoring packing leakoff flow rate. High temperature is recorded and annunciated by an alarm in the main control room.

11.

High Flow in Main Steam Lines (for Leaks Downstream of Flow Elements)

High flow in each main steam line is monitored by differential pressure sensors that sense the pressure difference across a flow element in the line. Steam flow exceeding preset values for

RBS USAR Revision 27 5.2-35 any of the four main steam lines results in annunciation and isolation closure of all the main steam and steam drain lines.

12.

Reactor Water Low Level The loss of water in the reactor vessel (in excess of makeup) as the result of a major leak from the RCPB is detected by using the same nuclear boiler system low reactor water level signals that alarm and isolate selected primary system isolation valves.

13.

RCIC Steam Line Flow (for Leaks Downstream of Flow Elements)

The steam supply line for motive power for operation of the RCIC turbine is monitored for abnormal flow. Steam flow exceeding preset values initiates annunciation and isolation of the RCIC steam line.

14.

High Differential Pressure Between ECCS Injection Lines (for Leakage Internal to Reactor Vessel Only)

A break between ECCS injection nozzles and vessel shroud is detected by monitoring the differential pressure between RHR "A" and LPCS, RHR "B" and "C", and HPCS and reactor vessel plenum. Indicator and alarm are located in the main control room.

15.

Bellows Seal Leakage The bellows seal is monitored for leakage by means of a flow transmitter locally mounted on the upper pool drain line. Indicator and alarm are located in the main control room.

16.

Upper Containment Pool Liner Leakage Upper containment pool liner leakage is administratively monitored by manually opening individual drain line valves and visually checking for leakage.

5.2.5.2.2 Leak Detection Instrumentation and Monitoring External to Drywell

1.

Containment Sump Flow Measurement Instrumentation monitors and indicates the amount of leakage into the containment floor drainage system outside the drywell. Equipment leakage within the containment outside the drywell is piped to the containment equipment drain sump. The containment floor and equipment drain sump instrumentation is identical to the drywell equipment drain sump.

2.

Visual and Audible Inspection Accessible areas are inspected periodically, and the temperature and flow indicators previously discussed are monitored regularly. Any instrument indication of abnormal leakage is investigated.

3.

Differential Flow Measurement (RWCU System Only)

Because of its arrangement, the RWCU uses the differential flow measurement method to detect leakage. The flow into the cleanup system is compared with the flow from the system.

RBS USAR Revision 27 5.2-36 An alarm in the main control room and an isolation signal are initiated when high differential flow exists between flow into the system and flow back to the reactor vessel, and/or the main condenser indicates that a leak equal to the established leak rate limit may exist.

4.

Main Steam Line Area Temperature Monitors High temperature in the main steam line tunnel area is detected by dual element thermocouples. The dual element thermocouples are used for measuring main steam tunnel ambient temperatures and are located in the area of the main steam and RCIC steam lines. All temperature elements are located or shielded so as to be sensitive to air temperatures and not to the radiated heat from hot equipment. High ambient temperature alarms in the main control room provide a signal to close the main steam and drain line isolation valves, RCIC steam isolation valves, and the RWCU system isolation valves. A high temperature alarm may also indicate leakage in the reactor feedwater line which passes through the main steam tunnel.

Leak detection in the main steam line area in the turbine building is similar to the main steam line tunnel area, except that no valve isolation signals are provided (only alarm and indication).

5.

Temperature Monitors in Equipment Areas Dual element thermocouples are installed in the equipment areas of the RCIC, RHR, and RWCU system equipment rooms for sensing high ambient temperature. These elements are located or shielded so that they are sensitive to air temperature only and not radiated heat from hot equipment. Eight temperature monitoring channels are provided in each equipment area.

Three channels respond to ambient temperature in the equipment area. Five channels are spared and not used. High ambient temperatures are alarmed in the main control room and provide trip signals for closure of isolation valves of the respective system in the monitored area.

6.

Intersystem Leakage Monitoring The intersystem leakage monitoring is included in the process radiation monitoring system to satisfy the requirements of that system.

7.

Large Leaks External to the Drywell The main steam high flow, RCIC/RHR steam high flow and reactor vessel low water level monitoring discussed in Section 5.2.5.2.1, Paragraphs 11, 12, and 13, can also indicate large leaks from the reactor coolant piping external to the drywell.

5.2.5.2.3 Summary Tables 5.2-7 and 5.2-8 summarize the actions taken by each leakage detection function. The table shows that those systems which detect gross leakage initiate immediate automatic isolation. The systems which are capable of detecting small leaks initiate an alarm in the main control room. In addition, the tables show that two or more leakage detection systems are provided for each system or area that is a potential source of leakage. Plant operating procedures dictate the action an operator is to take upon receipt of an alarm from any of these systems. The operator can manually isolate the violated system or take other appropriate action. A time delay is provided for the RWCU system differential flow to prevent normal system surges from isolating the system.

RBS USAR Revision 27 5.2-37 The leak detection system is a multi-dimensional system which is redundantly designed so that failure of any single element does not interfere with a required detection of leakage or isolation.

Any single channel or divisional component malfunction does not cause a false indication of leakage or false isolation trip because it only trips one of four channels, and two channels are required to trip for closure of the MSIVs. It thus combines a very high probability of operating when needed with a very low probability of operating falsely. The system is testable during plant operation.

5.2.5.3 Indication in Main Control Room Leak detection methods are discussed in Section 5.2.5.1. Details of the leakage detection system indications are included in Section 7.6.1.2.

5.2.5.4 Limits for Reactor Coolant Leakage 5.2.5.4.1 Total Leakage Rate The total leakage rate consists of all leakage, identified and unidentified, that flows to the drywell floor drain, drywell pedestal floor drain, and drywell equipment drain sumps. The total leakage rate limit is well within the makeup capability of the RCIC system. The total leakage rate limit is established at 30 gpm. The unidentified leakage rate limit is established at 5 gpm.

The total leakage rate limit is established low enough to prevent overflows of the sumps. The equipment sumps and the floor drain sumps, which collect all leakage, are each pumped out by two nominal 50-gpm pumps used separately or combined at high sump level.

5.2.5.4.2 Identified Leakage Inside Drywell The pump packing glands, valve stems, and other seals in systems that are part of the RCPB and from which normal design identified source leakage is expected are provided with leakoff drains. Selected nuclear system valves inside the drywell are equipped with double seals.

Leakage from the primary recirculation pump seals is monitored for flow in the drain line and piped to the equipment drain sump as described in Section 5.4.1.3. Leakage from the main steam SRVs discharging to the suppression pool is monitored by temperature sensors that transmit to the main control room. Any temperature increase above the ambient temperature detected by these sensors indicates valve leakage.

Thus, the leakage from pumps, valve stem packings, the reactor vessel head seal, and the upper containment pool liner and bellows seal, which discharge to the equipment drain sump, is measured during plant operation.

5.2.5.5 Unidentified Leakage Inside the Drywell 5.2.5.5.1 Unidentified Leakage Rate The unidentified leakage rate is the portion of the total leakage rate received in the drywell and pedestal floor drain sumps that is not identified as previously described. A threat of significant compromise to the nuclear system process barrier exists if the barrier contains a crack that is large enough to propagate rapidly (critical crack length). The unidentified leakage rate limit

RBS USAR Revision 27 5.2-38 must be low because of the possibility that most of the unidentified leakage rate might be emitted from a single crack in the nuclear system process barrier.

An allowance for leakage that does not compromise barrier integrity and is not identifiable is made for normal plant operation.

The total unidentified leakage rate limit is established at 5 gpm rate to allow time for corrective action before the process barrier could be significantly compromised. This 5 gpm unidentified leakage rate is a small fraction of the calculated flow from a critical crack in a primary system pipe (Fig. 5.2-12).

5.2.5.5.2 Sensitivity and Response Times Sensitivity, including sensitivity tests and response time of the leak detection system, is discussed in Section 7.6.1.2.

5.2.5.5.3 Length of Through-Wall Flaw Experiments conducted by GE and Battelle Memorial Institute (BMI) permit an analysis of critical crack size and crack opening displacement(4). This analysis relates to axially oriented through-wall cracks.

1.

Critical Crack Length Satisfactory empirical expressions to predict critical crack length have been developed to fit test results. A simple equation which fits the data in the range of normal design stresses (for carbon steel pipe) is:

Lc = 15,000 D (see data correlation on Fig. 5.2-13)

Vh LLs E

where:

Lc = Critical crack length (in)

D = Mean pipe diameter (in)

Vh = Nominal hoop stress (psi)

2.

Crack Opening Displacement The theory of elasticity predicts a crack opening displacement of:

Z = 2LV E

where:

L = Crack Length V = Applied nominal stress

RBS USAR Revision 27 5.2-39 E = Young's modulus Measurements of crack opening displacement made by BMI show that local yielding greatly increases the crack opening displacement as the applied stress V approaches the failure stress Vf. A suitable correction factor for plasticity effects is:

C = sec (

S 2

V V f)

(5.2-2)

The crack opening area is given by A = C S 4

ZL = S V

L E

2 2

sec (

S 2

V V f)

(5.2-3)

For a given crack length L, Vf = 15,000 D/L.

3.

Leakage Flow Rate The maximum flow rate for blowdown of saturated water at 1,000 psi is 55 lb/sec-in, and for saturated steam the rate is 14.6 lb/sec-in(5). Friction in the flow passage reduces this rate, but for cracks leaking at 5 gpm (0.7 lb/sec) the effect of friction is small. The required leak size for 5 gpm flow is:

A = 0.0126 sq in (saturated water)

A = 0.0475 sq in (saturated steam)

From this mathematical model, the critical crack length and the 5 gpm crack length have been calculated for representative BWR pipe size (Schedule 80) and pressure (1,050 psi).

The lengths of through-wall cracks that would leak at the rate of 5 gpm given as a function of wall thickness and nominal pipe size are:

Nominal Pipe Size Average Wall Crack Length L (in)

(Sch 80) (in)

Thickness (in) Steam Line Water Line 4

0.337 7.2 4.9 12 0.687 8.5 4.8 24 1.218 8.6 4.6 The ratios of crack length, L, to the critical crack length, Lc as a function of nominal pipe size are:

Nominal Pipe Size L/Lc (Sch 80) (in)

Steam Line Water Line 4

0.745 0.510

RBS USAR Revision 27 5.2-40 12 0.432 0.243 24 0.247 0.132 It is important to recognize that the failure of ductile piping with a long, through-wall crack is characterized by large crack opening displacements which precede unstable rupture. Judging from observed crack behavior in the GE and BMI experimental programs, involving both circumferential and axial cracks, it is estimated that leak rates of hundreds of gpm precede crack instability. Measured crack opening displacements for the BMI experiments were in the range of 0.1 to 0.2 in at the time of incipient rupture, corresponding to leaks of the order of 1 sq inch in size for plain carbon steel piping. For austenitic stainless-steel piping, even larger leaks are expected to precede crack instability, although there are insufficient data to permit quantitative prediction.

The results given are for a longitudinally oriented flaw at normal operating hoop stress. A circumferentially oriented flaw could be subjected to stress as high as the 550°F yield stress, assuming high thermal expansion stresses exist. It is assumed that the longitudinal crack, subject to a stress as high as 30,000 psi, constitutes a worst case with regard to leak rate versus critical size relationships. Given the same stress level, differences between the circumferential and longitudinal orientations are not expected to be significant in this comparison.

Fig. 5.2-12 shows general relationships between crack length, leak rate, stress, and line size, using the mathematical model described previously. The asterisks denote conditions for which the crack opening displacement is 0.1 in, at which time instability is imminent as noted previously under "Leakage Flow Rate." This provides a realistic estimate of the leak rate to be expected crack of critical size. In every case, the leak rate from a crack of critical size is significantly greater than the 5-gpm criterion.

If either the total or unidentified leak rate limits are exceeded, an orderly shutdown can be initiated, and the reactor can be placed in a cold shutdown condition within 24 hr.

5.2.5.5.4 Margins of Safety The margins of safety for a detectable flaw to reach critical size are presented in Section 5.2.5.5.3. Fig. 5.2-12 shows general relationships between crack length, leak rate, stress, and line size using the mathematical model.

5.2.5.5.5 Criteria to Evaluate the Adequacy and Margin of the Leak Detection System For process lines that are normally open, there are at least two different methods of detecting abnormal leakage from each system within the nuclear system process barrier located in the drywell, containment, and auxiliary building as shown in Tables 5.2-7 and 5.2-8. The instrumentation is designed so it can be set to provide alarms at established leakage rate limits and isolate the affected system, if necessary. The alarm points are determined analytically or are based on measurements of appropriate parameters made during the startup and preoperational phases of plant operation.

The unidentified leakage rate limit is based, with an adequate margin for contingencies, on the crack size large enough to propagate rapidly. The established limit is sufficiently low that, even if the entire unidentified leakage rate were coming from a single crack in the nuclear system

RBS USAR Revision 27 5.2-41 process barrier, corrective action could be taken before the integrity of the barrier would be threatened.

The leak detection system can satisfactorily detect unidentified leakage of 5 gpm.

5.2.5.6 Differentiation Between Identified and Unidentified Leaks Section 5.2.5.1 describes the systems that are monitored by the leak detection system. The ability of the leak detection system to differentiate between identified and unidentified leakage is discussed in Sections 5.2.5.4, 5.2.5.5, and 7.6.1.2.

5.2.5.7 Sensitivity and Operability Tests Sensitivity, including sensitivity testing and response time of the leak detection system, and the criteria for shutdown if leakage limits are exceeded, are covered in Section 7.6.1.2.

Testability of the leakage detection system is also contained in Section 7.6.1.2.

5.2.5.8 Safety Interfaces The balance of plant-GE nuclear steam supply system safety interfaces for the leak detection system are the signals from the monitored balance of plant equipment and systems which are part of the RCPB and associated wiring and cable lying outside the nuclear steam supply system equipment.

5.2.5.9 Testing and Calibration Provisions for testing and calibration of the leak detection system are covered in Chapter 14.

Surveillance of the floor drain system, which is used to detect liquid leakage, includes periodic testing for blocked lines.

5.2.5.10 Regulatory Guide Compliance Regulatory Guide 1.45 prescribes guidelines to assure that leakage detection and collection systems provide maximum practical identification of leaks from the RCPB.

Leakage is separated into identified and unidentified categories, thus meeting Position C.1 of Regulatory Guide 1.45.

Small unidentified leaks (5 gpm and less) inside the drywell are detected by sump fill-up rates, drain pump activities, fission product monitoring, and drywell cooler condensate flow monitoring.

Large leaks are also detected by changes in reactor water level, changes in flow rates in process lines, and drywell temperature and pressure increases.

The 5 gpm leakage rate is a proposed limit on unidentified leakage inside the drywell. The leak detection system is fully capable of monitoring the sump fillup rates and flow rates of 1 gpm and is thus in compliance with Paragraph C.2 of Regulatory Guide 1.45.

RBS USAR Revision 27 5.2-42 By monitoring drywell and pedestal floor drain sump fill-up rates, drywell cooler condensate flow rate and radioactivity increases, Position C.3 is satisfied.

Isolation and/or alarm of affected systems and the detection methods used are summarized in Tables 5.2-7 and 5.2-8.

Monitoring of coolant abnormal flow radiation in the RHR and RWCU system heat exchanger satisfies Position C.4 of the Regulatory Guide. (For system details, see Section 7.6.)

The three methods described are designed to detect 1 gpm in less than 1 hr, thus Position C.5 is satisfied. The floor drain leak detection system has a combined loop accuracy of r1/4 in of sump level. This is equivalent to r2.5 gal. Since two readings are required for each calculation, the error in volume detected would be r3.5 gal, using square root of the sum of squares method. The accuracy (percentage) of the system is dependent on the rate of leakage, with higher leakage rate producing lower percentage of error. Considering a leakage rate of 1 gpm, the sump volume will change by 60 gal in 1 hr and the error of 3.5 gal is equivalent to r5 to 8 percent. Thus the system is sensitive enough to measure a leakage rate of 1 gpm in 1 hr with acceptable limits of accuracy. The drywell and pedestal floor drain sumps, drywell cooler condensate monitors, and fission product monitor systems are qualified for seismic events.

This satisfies Position C.6.

Leakage detection indicators and alarms are provided in the main control room. This satisfies Position C.7. Procedures and graphs are provided to plant operators for converting various indicators to a common leakage equivalent, thus meeting Position C.7.

The leakage detection systems are equipped with provisions to permit testing for operability and calibration during operation by the following methods:

1.

Continuous monitoring of sump levels compared to flow rates into sump

2.

Operability checked by comparing one method to another (i.e., condensate flow versus sump fill-up)

3.

Simulation of signals into trip monitors

4.

Comparing Channel A against Channel B of the same leak detection method.

Thus, Position C.8 is satisfied.

Limiting conditions for identified and unidentified leakage are established as 25 gpm and 5 gpm, respectively, thus satisfying Position C.9.

References - 5.2

1.

Deleted

2.

Skarpelos, J.M. and Bagg, J.W. Chloride Control in BWR Coolants. NEDO-10899, June 1973.

3.

Williams, W.L. Corrosion. Vol 13, 1957, p 539t.

RBS USAR Revision 27 5.2-43

4.

Reynolds, M.B. GEAP-5620, Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws. April 1968.

5.

Investigation and Evaluation of Cracking in Austenitic Stainless-Steel Piping of Boiling Water Reactor Plants. NUREG-76/067, NRC/PCSG, October 1975.

6.

ANS Standard Decay Energy Release Rate Following Shutdown of Uranium Fueled Thermal Reactors, Revised October 1973.

7.

Pressure Relieving Device Certifications, Certified by the National Board of Boiler and Pressure Vessel Inspectors, 1979 Edition.

8.

NEDO-024154-A, Volumes 1 and 2, Qualification of the One-Dimensional Core Transient Model, August 1986.

9.

NEDO-024154P-A, Volume 3, Qualification of the One-Dimensional Core Transient Model, August 1986.

10.

NEDO-024154-A, Supplement 1 - Volume 4, Qualification of the One-Dimensional Core Transient Model, February 2000.

RBS USAR Revision 27 Page 1 of 1 TABLE 5.2-1 REACTOR COOLANT PRESSURE BOUNDARY COMPONENTS APPLICABLE CODE CASES Code Case Number Applicable Equipment Title 1141-1 RPV Foreign Produced Steel 1332-6 RPV Requirements for Steel Forgings 1361-2 CRD Socket Welds 1557 RPV Steel Product Refined by Secondary Remelting 1567 Recirc Pump, SRV Testing Logs of Carbon or Low Alloy Steel Covered Electrodes,Section III 1572 RPV Fracture Toughness,Section III, Class 1 Components 1578 CRD SB-167 Nickel-Chromium Iron (Alloy 600) Pipe or Tube,Section III 1620 RPV Stress Category for Partial Penetration Welded Penetrations,Section III, Class 1 Construction 1711 SRV Pressure Relief Valve Design Rules,Section III, Division 1, Class 1, 2, and 3 1820 (N177)

RPV and Recirc Pump Alternate Ultrasonic Examination Technique,Section III, Division I N207 CRD Use of Modified SA-479 Type XM-19 for Section III, Division 1, Class 1, 2, or 3 Construction 1637 Recirc Valves Effective Date of Compliance with NA-3700,Section III N-483 RPV Alternate Rules to the Provisions of NCA-3800

RBS USAR Revision 27 1 of 1 TABLE 5.2-2 NUCLEAR SYSTEM SAFETY/RELIEF SET POINTS No. of Valves Spring Set Pressure (psig)

ASME Rated Capacity

@ 103% Spring Set Pressure (lb/hr each)

Relief Pressure Set Pressure (psig)

Low-Low Set Relief No. of Valves Set Point Open/Close 7

1,195 918,000 5

1,205 926,000 4

1,120 929,000 1

1,133*

1 1,063/956 8

1,143*

1 1,103/966 3

1,143/976 7

1,153*

NOTE:

Seven of the safety/relief valves serve in the automatic depressurization function.

• Closing set point is 100 psi below opening set point.

RBS USAR TABLE 5.2-3 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS Revision 27 1 of 5 Component Form Material Specification (ASTM/ASME)

Main Steam Isolation Valve Valve body Cast Carbon steel SA216, Gr. WCB Cover Forged Carbon steel SA105 Poppet Forged Carbon steel SA105 Stem Barstock Precipitation hardened steel SA564, Type 630, Condition 1150 Body bots Barstock Carbon steel SA540, Gr. B23, Cl. 5 Hex nuts Barstock Carbon steel SA540, Gr. B23, C1. 5 Main Steam Safety/Relief Valve Body Forged Carbon steel SA105 Bonnet (yoke)

Forged Carbon steel SA105 Nozzle Forged Stainless steel SA182, Gr. F316 Body-to-bonnet stud Bar/rod Low alloy steel SA193, Gr. B7 Body-to-bonnet nut Bar/rod Carbon steel SA194, Gr. 2H Disc (disc insert)

Forged Alloy steel SA637, Gr. 718 Spring washer Forged Carbon steel SA105 Spindle (stem)

Bar Precipitation hardened steel A564, Type 630, Condition 1150 Adjusting screw Alloy steel SA193, Gr. B6 Spring Wire Carbon steel A304, Gr. 4161 Main Steam Flow Element Upstream casting Cast Stainless steel SA351, Gr. CF8 Downstream casting Cast Carbon steel SA216, Gr. WCB Nozzle Forged Carbon steel SA105 Instrument tube Seamless Stainless steel SA213, Gr. TP 304 Main Steam Piping Pipe Seamless Carbon steel SA106, Gr. B Pipe (penetration)

Seamless Carbon steel SA106, Gr. B Contour nozzle Forged Carbon steel SA105 8 x 10 1,500 lb groove flange Forged Carbon steel SA105 Elbow Welded fitting Carbon steel SA234, Gr. WPB, SA516, Gr. 70 1 x 6,000 lb socket weld half coupling Forced Carbon steel SA105 Head fitting Forced Carbon steel SA105

RBS USAR TABLE 5.2-3 (Cont)

Revision 27 2 of 5 Component Form Material Specification (ASTM/ASME)

Guide lug Plate Carbon steel SA516, Gr.70 Recirculation Pump Pump case casting Cast plate Stainless steel SA351, Gr. CF8M Lifting lug Cast plate Stainless steel SA240, Type 304/316 Shock suppressor lug Cast plate Stainless steel SA240, Type 316 Shock suppressor lug Cast plate Stainless steel SA240, Type 316 Shock suppressor lug Cast plate Stainless steel SA240, Type 316 Stud-case to stuff box (3 1/4 - 8N)

Bar Alloy steel SA540, Gr. B23 C1 5 Stud nut (3 1/4 - 8N)

Bar Alloy steel SA194, Gr. 7 Stuffing box casting Cast forging Stainless steel SA351, Gr. CF8M Nozzle - 1 Cast forging Stainless steel SA182, Gr. F304/F316 Nozzle - 1 Cast forging Stainless steel SA182, Gr. F304/F316 Nozzle - 3/4 Cast forging Stainless steel SA182, Gr. F304/F316 Flange nozzle - 1 Cast forging Stainless steel SA182, Gr. F304/F316 Flange 1 - 150# ASA soc weld Forging Stainless steel A182, Gr. F304/F316 Lifting lugs Plate Stainless steel SA240, Type 304/316 Flange nozzle - 3/4 Forging Stainless steel SA182, F304/F316 Flange 3/4 - 1,500# soc weld Forging Stainless steel SA182, Gr. F304/F316 Thrust ring Forging Stainless steel SA182, Gr. F316 Pump flange Forging plate Carbon steel SA350, Gr. LF2 Motor stand barrel Forging plate Carbon steel SA516, Gr. 70 Brace Forging plate Carbon steel SA516, Gr. 70 Brace Forging plate Carbon steel SA516, Gr. 70 Strut lug Plate Carbon steel SA36 Strut lug Forging plate Carbon steel SA36 Seal Flange Assembly Forging Stainless steel SA182, Gr. F316 Upper seal gland Forging Stainless steel SA182, Gr. F304/F316 Clamp - 1 pipe size Cast Stainless steel SA351, Gr. CF8/CF8M Stud complete w/nuts Bar Alloy steel SA193, Gr. B8 Pipe - 1 sch 80 (0.179 wall)

Pipe Stainless steel SA312, Gr. TP 304/316 Hub soc weld Forging Stainless steel SA182, Gr. F304/F316 Tee - 1 Pipe 3000# soc weld Forging Stainless steel SA182, Gr. F304/F316 Thermowell for 1 Tee Forging Stainless steel SA182, Gr. F304/F316 Pipe - 1 sch 80 (0.179 wall)

Pipe Stainless steel SA312, Gr. TP 304/316

RBS USAR TABLE 5.2-3 (Cont)

Revision 27 3 of 5 Component Form Material Specification (ASTM/ASME)

Flange 1500# soc weld lg grv Forging Stainles steel SA182, Gr. F304/F316 Hub - 1" soc weld Forging Stainless steel SA182, Gr. F304/F316 Tee - 1" pipe 3000# soc weld Forging Stainless steel SA182, Gr. F304/F316 Thermowell for 1" tee Forging Stainless steel SA182, Gr. F304/F316 Pipe plug - 3/4" NPT Forging Stainless steel SA182, Gr. F304/F316 Pipe 3/4 sch 80 (0.154 wall)

Pipe Stainless steel SA312, Gr. TP 304/316 Tee 3/4" pipe 3000# soc weld Forging Stainless steel SA182, Gr. F304/F316 Thermowell for 3/4" tee Forging Stainless steel SA182, Gr. F304/F316 Flange 3/4-1500# soc weld lg grv Forging Stainless steel SA182, Gr. F304/F316 Hub - 3/4" soc weld Forging Stainless steel SA182, Gr. F304/F316 Valve body Plate Stainless steel SA240, Type 304/316 Valve bonnet Plate Stainless steel SA240, Type 304/316 Coil inner 1 1/4 tube x 0.065 wall Pipe Stainless steel SA213, Gr. TP316 Tee 1 1/4 tube x 1" pipe run-3000#

Forging Stainless steel SA182, Gr. F304/F316 Pipe Cap 1" soc weld - 3000#

Forging Stainless steel SA182, Gr. F304/F316 Flange 1"-1500# soc weld lg groove Forging Stainless steel SA182, Gr. F304/F316 Hub - 1" soc weld Forging Stainless steel SA182, Gr. F304/F316 Pipe 1"-sch 80 (0.179 wall)

Pipe Stainless steel SA312, Gr. TP 304 Recirculation Gate Valve Body Cast Stainless steel SA351, Gr. CF8M Bonnet Cast Stainless steel SA351, Gr. CF8M Stem Bar Precipitation hardened steel SA564, Type 630, Condition 1150 Disc Cast Stainless steel SA351, Gr. CF3A Nuts Barstock Carbon steel SA194, Gr. 7 Bolts Barstock Low alloy steel SA193, Gr. B7 Recirculation Flow Control Valve Body Cast Stainless steel SA351, Gr. CF8M Bonnet Cast Stainless steel SA351, Gr. CF8M Housing Cast Stainless steel SA351, Gr. CF8M Covers Cast Stainless steel SA351, Gr. CF8M

RBS USAR TABLE 5.2-3 (Cont)

Revision 27 4 of 5 Component Form Material Specification (ASTM/ASME)

Recirculation Piping Pipe Rolled & welded Stainless steel SA358, Gr. 316*

Cross, tee, concentric reducer, cap, contour nozzle, and elbow Fittings Stainless steel SA403, WP 316*

CRD CRD flanges, plugs Forged Stainless steel SA182, Gr. F304 CRD indicator tube Pipe Stainless steel SA312, Gr. TP316 CRD nut, base Bar Stainless steel SA479, Type XM-19 Drive housing Forged Stainless steel SA182, Gr. F304 or 316L Tube Stainless steel SA312 or SA213 Tube Alloy steel SB167 Welds Alloy steel SFA 5.1, Type ERNiCr3 In-core housings Forged Stainless steel SA182, Gr. F304 or F316L Tube Alloy steel SB167 Welds Alloy steel SFA 5.14, Type ERNiCr3 Pressure Vessel Vessel shells, heads Rolled plate or forgings Low alloy steel SA533, Gr. B, Class 1 SA508, Class 2 Closure flange Forged ring Welds Low alloy steel Low alloy steel SA508, Class 2 SFA5.5, SFA5.23 Nozzles Forged shapes Welds Low alloy steel Low alloy steel SA508, Class 2 SFA5.5, SFA5.23 Nozzle safe ends Forgings or plate Stainless steel

SA336, SA240, Type 304 or 316 SA182, Gr. F304 or F316 Welds Stainless steel SFA5.9, Type 308L or 316

RBS USAR TABLE 5.2-3 (Cont)

Revision 27 5 of 5 Component Form Material Specification (ASTM/ASME)

Nozzle safe ends Forgings Welds Carbon steel Carbon steel SA508, Class 1 SFA5.1, SFA5.18GPA SFA5.17F70, SFA5.28 Nozzle safe ends Forgings Welds Carbon steel Ni-Cr-Fe SA508, Class 1 SFA5.14, Type ERNiCr3 SFA5.11, Type ENiCrFe-3 Nozzle safe ends Forgings Welds Stainless steel Ni-Cr-Fe SA336 Inconel 182 SA182, Gr. F316L SFA5.14, Type ERNiCr3 SFA5.11, Type ENiCrFe-3

• Carbon content limited to 0.02 weight percent maximum.

RBS USAR TABLE 5.2-4 BWR WATER CHEMISTRY Revision 27 1 of 1 Concentrations - Parts per Billion (ppb)

Conductivity pH

@ 25qC Iron Copper Chloride Oxygen P mho/cm

@ 25qC Condensate (1)*

15-30 3-5

< 20 20-50 a0.1 a7 Condensate treatment effluent (2)*

0.5-15

< 1 a0.2 20-50

< 0.1 a7 Feedwater (3)*

0.5-15

< 1 a0.2 20-50

< 0.1 a7 Reactor water (4)*

a. Normal Operation

b. Shutdown

c. Hot Standby

d. Depressurized 10-50

< 20

< 20

< 20

< 20

< 20 100-300 a0#

See outline 8,000 0.2-0.5

< 1

< 1

< 2 a7 a7 a7 6-6.5 Steam (5)*

0 0

0 10,000 - 30,000 a5,000 a0.1 Control rod drive cooling water (6)*

50-500

< 20

< 150

< 0.1 a7 Suppression pool make-up+

< 500

< 10 5.3 - 8.6 Condensate storage tank make-up+, ##

< 50

< 3 5.3 - 7.5 Numerals in parentheses refer to locations delineated on Fig. 5.2-10.

a Represents the word approximately.

+

NSSS Vendor requirements.

1. Applies to hydrogen water chemistry environment with low H2 injection rates and NobleChem.

1. 1. The CST water quality during normal operation is maintained by design and proper operation of systems that provide input to the condensate storage facilities discussed in Section 9.2.6.

RBS USAR TABLE 5.2-5 SYSTEMS WHICH MAY INITIATE DURING OVERPRESSURE EVENT Revision 27 1 of 1 System Initiating/Trip Signal(s)(1)

Reactor Protection System Reactor trips "OFF" with High Flux RCIC "ON" with Reactor Water Level at L2 "OFF" with Reactor Water Level at L8 HPCS "ON" with Reactor Water Level at L2 "ON" with High Drywell Pressure "OFF" with Reactor Water Level at L8(2)

Recirculation System Pumps trip "OFF" with Reactor Water Level at L2 Pumps trip to Low Frequency M/G set at L3 "OFF" with Reactor Pressure at 1125 psig RWCU system "OFF" with Reactor Water Level at L2 (1)Vessel level trip settings are shown on Fig. 5.3-2.

(2)HPCS system continues to inject into the reactor if level L8 and a high drywell pressure signal exist.

RBS USAR TABLE 5.2-6 WATER SAMPLE LOCATIONS Revision 27 1 of 1 Sample Origin Sensor Location Indicator Location Recorder Location Conductivity (P mho/cm)

Range Alarm Set Point Minimum(1)

Accuracy (Percent)

High High-High Reactor Water Recirculation Loop Sample Line Sample Station Main Control Room 0-10(2) 0.7 3.5 r 1 Reactor Water Cleanup System Inlet Sample Line Sample Station Main Control Room 0-10(2) 0.7 3.5 r 1 Reactor Water Cleanup System Outlets Sample Line Sample Station Main Control Room 0-1(3) 0.1 0.2 r 1 Condensate Control Rod Drive System Sample Line Sample Station Main Control Room 0-1(3) 0.2 r 1 (1)The accuracy is expressed as percent of full-scale range. The instruments are sensitive to within, or less than, the accuracy and are periodically (1/week) calibrated against laboratory calibration instruments.

(2)The instrument is nonlinear with 1 mho/cm at midscale to facilitate readings at the normally low levels (i.e., <<1 mho/cm).

(3)The instrument is nonlinear with 0.1 mho/cm at midscale.

RBS USAR TABLE 5.2-7

SUMMARY

OF SYSTEM ALARMS AND THE LEAK DETECTION METHODS USED Revision 27 1 of 1 AFFECTED VARIABLE MONITORED LOCATED, INSIDE DRYWELL LOCATED, OUTSIDE DRYWELL DRYWELL PRESSURE, HIGH REACTOR WATER LEVEL, LOW FLOOR DRAIN HIGH FILL-UP RATE (CONTAINMENT)

EQUIPMENT DRAIN SUMP FLOW RATE, HIGH (CONTAINMENT)

FISSION PRODUCT RADIATION, HIGH DRYWELL TEMPERATURE, HIGH SAFETY/RELIEF VALVE DISCHARGE PIPE TEMP, HIGH MSL GUARD PIPE TEMP, HIGH VALVE STEM LEAKOFF TEMP, HIGH RECIRC PUMP SEAL FLOW, HIGH VESSEL HEAD SEAL PRESSURE, HIGH AIR COOLER CONDENSATE FLOW, HIGH FLOW RATE, HIGH (STEAM FLOW)

SUMP OR DRAIN FLOW, HIGH (EQUIP AREAS)

MSL TUNNEL AMBIENT TEMP, HIGH EQUIPMENT AREA AMBIENT TEMP, HIGH RWCU DIFFERENTIAL FLOW, HIGH BELLOWS SEAL DRAIN FLOW, HIGH INTERSYSTEM LEAKAGE (RADIATION) HIGH ECCS INJECTION LINE LEAKAGE (INTERNAL TO REACTOR VESSEL) DIFFERENTIAL PRESSURE MSL AREA TEMP HIGH (TURB BLDG)

SOURCE OF LEAKAGE MAIN STEAM LINE X

A A

A A

A A

A A

A A

X A

A A

A A

RCIC/RHR STEAM LINE X

A A

A A

A A

A A

X A

A A

A A

RCIC STEM LINE X

X A

A A

A A

RWCU WATER X

A A

A A

A A

A A

X A

A A

A A

A HPCS WATER X

A A

A X

LPCS WATER X

A A

A X

RECIRC PUMP SEAL X

A A

A A

X FEEDWATER X

A A

A A

A A

X A

A A

RHR WATER X

A A

A A

A A

A A

X A

A A

A REACTOR VESSEL HEAD SEAL X

A A

A A

X UPPER CONTAINMENT POOL BELLOWS SEAL X

A A

X A

MICELLANEOUS LEAKS X

A X

A A

VALVE STEM PACKING X

A A

X RCIC WATER X

A X

LEGEND A = ALARM AND INDICATE OR RECORD ONLY.

X = LOCATION OF LEAKAGE SOURCE.

RBS USAR Revision 27 1 of 1 TABLE 5.2-8

SUMMARY

OF SYSTEM ISOLATION/ALARMS AND THE LEAK DETECTION METHODS USED REACTOR VESSEL WATER LEVEL MAIN STEAM LINE PRESSURE LOW MS TUNNEL AMBIENT TEMP, HIGH MS FLOW RATE, HIGH DRYWELL PRESSURE, HIGH RHR EQUIPMENT AREA AMBIENT TEMP, HIGH RCIC EQUIPMENT AREA AMBIENT TEMP, HIGH RCIC EXHAUST DIAPHRAGM PRESSURE, HIGH RHR/RCIC STEAM SUPPLY DIFFERENTIAL PRESSURE (HIGH FLOW)

RHR/RCIC STEAM SUPPLY DIFFERENTIAL PRESSURE (INSTR LINE BREAK)

RWCU PROCESS PIPING DIFFERENTIAL FLOW, HIGH RWCU EQUIPMENT AREA AMBIENT TEMP, HIGH MAIN STEAM 1

I I

I RECIRC (SAMPLE LINE) 2 RHR 3

I I

RCIC I

• I I

I I

I I

RWCU 2

I I

I CONTAINMENT ISOLATION 2

I I = ISOLATE ALARMS AND INDICATE OR RECORD.

• RCIC TURBINE EXHAUST VACUUM BREAKER LINE VALVES ONLY.

• • SYSTEMS OR SELECTED VALVES WITHIN THE SYSTEM THAT ISOLATE.

VARIABLE MONITORED SYSTEM ISOLATED **

RBS USAR TABLE 5.2-9 SEQUENCE OF EVENTS FOR FIG. 5.2-1 Time (sec)

Events Revision 27 1 of 1 0

Initiate closure of all main steam isolation valves (MSIVs).

0.3 MSIVs reached 90 percent open and initiated reactor scram. However, hypothetical failure of this position scram was assumed in this analysis.

1.7 Neutron flux reached the APRM flux scram set point and initiated reactor scram.

2.4 Reactor water level dropped to the set point of recirculation pump trip (L3).

2.4 Recirculation pump motor tripped to low frequency M/G set.

2.6 Reactor dome pressure reached the pressure set point (power actuated mode). Only one half of the valves in this group were assumed to function.

2.6 Steam line pressure reached the safety/relief valve pressure set point (spring action mode). Valves which were not opened in the power actuated mode were opened.

2.4 Sensed dome pressure reached ATWS high pressure recirculation pump trip setpoint. (However, pumps were already tripped just before 2.4 sec due to low water level.)

3.0 All safety/relief valves opened in either power actuated mode or spring action mode due to high pressure.

3.0 MSIVs completely closed.

4.24 Vessel bottom pressure reached its peak value.

FIGURE 5.2-1 MSIV CLOSURE WITH FLUX SCRAM AND INSTALLED SAFETY/RELIEF VALVE CAPACITY RIVER BEND STATION UPDATED SAFETY ANALYSIS REPORT Revision 17

RBS USAR Revision 27 5.3-1 5.3 REACTOR VESSEL 5.3.1 Reactor Vessel Materials 5.3.1.1 Materials Specifications The materials used in the RPV and appurtenances are listed in Table 5.2-3 together with the applicable specifications.

5.3.1.2 Special Processes Used for Manufacturing and Fabrication The RPV is primarily constructed from low alloy, high strength steel plate and forgings. Plates are ordered to ASME SA533 Grade B, Class 1, and forgings to ASME SA508, Class 2. These materials are melted to fine grain practice and are supplied in the quenched and tempered condition. Further restrictions include a requirement for vacuum degassing to lower the hydrogen level and improve the cleanliness of the low alloy steels. Materials used in the core beltline region also specify limits of 0.12-percent maximum copper and 0.015-percent maximum phosphorus content in the base materials, and a 0.10-percent maximum copper and 0.025-percent maximum phosphorus content in weld materials.

Studs, nuts, and washers for the main closure flange are ordered to ASME SA540, Grade B23 or Grade B24. Welding electrodes are low hydrogen type ordered to ASME SFA5.5.

All plate, forgings, and bolting are 100-percent ultrasonically tested and surface examined by magnetic particle methods or liquid penetrant methods in accordance with ASME Section III, Subsection NB standards. Fracture toughness properties are also measured and controlled in accordance with Subsection NB requirements.

All fabrication of the RPV is performed in accordance with GE-approved drawings, fabrication procedures, and test procedures. The shells and vessel heads are made from formed plates and the flanges and nozzles from forgings. Welding performed to join these vessel components is in accordance with procedures qualified in accordance with ASME Sections III and IX requirements. Weld test samples are required for each procedure for major vessel full penetration welds. Tensile and impact tests are performed to determine the properties of the base metal, heat-affected zone, and weld metal.

Submerged arc and manual stick electrode welding processes are employed. Electroslag welding is not permitted. Preheat and interpass temperatures employed for welding of low alloy steel meet or exceed the requirements of ASME Section III, Subsection NA. Post weld heat treatment at 1100°F minimum is applied to all low alloy steel welds.

Radiographic examination is performed on all pressure containing welds in accordance with requirements of ASME Section III, Subsection NB-5320. In addition, all welds are given a supplemental ultrasonic examination.

The materials, fabrication procedures, and testing methods used in the construction of BWR reactor pressure vessels meet or exceed requirements of ASME Section III, Class 1 vessels.

RBS USAR Revision 27 5.3-2 5.3.1.3 Special Methods for Nondestructive Examination The materials and welds on the RPV were examined in accordance with methods prescribed and meet the acceptance requirements specified by ASME Section III. In addition, the pressure retaining welds were ultrasonically examined using manual techniques. The ultrasonic examination method, including calibration, instrumentation, scanning sensitivity, and coverage, was based on the requirements imposed by ASME Section XI in Appendix I. Acceptance standards were equivalent or more restrictive than required by ASME Section XI.

5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels 5.3.1.4.1 Compliance With Regulatory Guides 5.3.1.4.1.1 Regulatory Guide 1.31 Controls on stainless steel welding are discussed in Section 5.2.3.4.2.1.

5.3.1.4.1.2 Regulatory Guide 1.34 Electroslag welding was not employed for the RPV fabrication.

5.3.1.4.1.3 Regulatory Guide 1.43 RPV specifications require that all low alloy steel be produced to fine grain practice. The requirements of this regulatory guide are not applicable to BWR vessels.

5.3.1.4.1.4 Regulatory Guide 1.44 Controls to avoid severe sensitization are discussed in Section 5.2.3.4.1.1.

5.3.1.4.1.5 Regulatory Guide 1.50 Preheat controls are discussed in Section 5.2.3.3.2.1.

5.3.1.4.1.6 Regulatory Guide 1.71 Qualification for areas of limited accessibility is discussed in Section 5.2.3.4.2.3.

5.3.1.4.1.7 Regulatory Guide 1.99 Predictions for changes in transition temperature and upper shelf energy were made in accordance with the requirements of Regulatory Guide 1.99, Revision 2.

5.3.1.5 Fracture Toughness 5.3.1.5.1 Compliance with 10CFR50, Appendix G The interpretation of and compliance to Appendix G of 10CFR50 for Class I RCPB components of the BWR 6 reactor design are as discussed in Section 5.3.2 with the following exceptions:

RBS USAR Revision 27 5.3-3

1.

The specific temperature limits for operation when the core is critical are based on 10CFR50, Appendix G, December 1995.

2.

A minimum boltup and pressurization temperature of 70°F is called for, which is at least 60°F above the flange region RTNDT. This exceeds the minimum RTNDT temperature required by ASME Section III, Appendix G, Paragraph G2222(c),

Summer 1976 and later editions. A flange region flaw size less than 10 percent of the wall thickness can be detected at the outside surface of the flange-to-shell and head junctions, where the presence of stresses due to boltup is most limiting.

The following items 1 through 7 are the interpretations and methods used to comply with Appendix G of 10CFR50. Item 8 reports the fracture toughness test results and the background information used as the basis to show compliance with 10CFR50, Appendix G.

1.

Records and Procedures for Impact Testing Personnel conducting fracture toughness tests were qualified to written impact testing procedures that demonstrated competency to perform required tests. For River Bend Station Unit 1, RPV records were not sufficient to document full compliance to current code requirements; however, there are sufficient records to document that the technical requirements are met.

2.

Specimen Orientation for Original Qualification Versus Surveillance The special longitudinally oriented Charpy specimens required by general ref erence NB-2300 and, specifically, NB-2322.2(a) (6) for beltline material qualification, are not included for the surveillance program base metal because, with regard to toughness as the limiting factor, the Charpy V-notch energy value is lower for transverse specimens than for longitudinal specimens.

3.

Charpy V-Curves for the RPV Beltline The orientations of impact test specimens comply with the requirements of NB-2322(a)4 (transverse specimen) for plate material as opposed to NB-2322(a)(6) (longitudinal specimen).

Meaningful and conservative beltline curves of unirradiated materials are used for comparison with the results of surveillance program testing of irradiated transverse base metal specimens which complied with ASTM E185-73.

The procedures of ASTM E185-73 were used for selection of surveillance specimen base material and weld material to provide a conservative adjusted reference temperature for the beltline material. The weld test plate for the surveillance program specimens had the principal working direction normal to the weld seam to assure that heat-affected zone specimens are oriented such that they simulate actual production weld conditions.

4.

Upper Shelf Energy for Beltline The River Bend Station RPV beltline materials comply with the requirement of an initial 75 f t-lb minimum upper shelf Charpy V-notch energy. In addition, these materials are predicted (Regulatory Guide 1.99) to maintain a minimum upper shelf energy level of 50 ft-lbs at end-of-life.

RBS USAR Revision 27 5.3-4

5.

Bolting Materials Bolting meets the 45 ft-lb and 25 mils lateral expansion requirements at 10°F for River Bend Station.

6.

Alternative Procedures for the Calculation of Stress Intensity Factor Stress intensity factors were calculated by the methods of ASME Section III, Appendix G.

Discontinuity regions were evaluated, as well as shell and head areas, as part of the detailed thermal and stress analysis in the vessel stress report. Equivalent margins of safety to those required for shells and heads were demonstrated using a 1/4 T defect at all locations, with the exception of the main closure flange-to-head and shell discontinuity locations.

It has been determined that an additional restriction of operating limits is required for outside surface flaw size greater than 0.24 in at the outside surface of the flange-to-shell joint (based on additional analyses made for BWR 6 reactor vessels). It has been demonstrated, using a test mockup of these areas, that smaller defects can be affected by the ultrasonic inservice examination procedures required at the adjacent weld joint. Since the stress intensity f actor is greatest at the outside surface of the flange-to-shell and head joints, a flaw also can be detected by outside surface examination techniques.

7.

Fracture Toughness Margins in the Control of Reactivity Appendix G of ASME Section III (1995 Edition with Addenda through 1996), Protection Against Non-ductile Failure, was used in determining pressure/temperature limitations for all phases of plant operation.

8.

Results of Chemical Analysis and RTNDT Evaluations are in Table 5.3-1 and Table 5.3-2 Table 5.3-1 contains the original information used to calculate the current P-T Limit Curves.

Table 5.3-2 contains the updated fluence analysis. The information in Table 5.3-2 with the additional information and clarification provided in 5.3.1.6.1 is used to evaluate the current P-T Limit curves. The current P-T Limit Curves are based on information in Table 5.3-1 and bound the updated information contained in Table 5.3-2.

5.3.1.6 Material Surveillance 5.3.1.6.1 Compliance with Reactor Vessel Material Surveillance Program Requirements The materials surveillance program monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from their exposure to neutron irradiation and thermal environment. Reactor vessel materials surveillance specimens are provided in accordance with requirements of ASTM E185-73 and 10CFR50, Appendix H.

Materials for the program are selected to represent materials used in the reactor beltline region.

Specimens are manufactured from a plate actually used in the beltline region and a weld typical of those in the beltline region and thus represent base metal, weld material, and the weld heat affected zone material. The plate and weld are heat treated in a manner which simulates the actual heat treatment performed on the core region shell plates of the completed vessel. The plate and heat affected zone (HAZ) heat numbers and chemical compositions are provided in Table 5.3-1. Those heat numbers labeled with an asterisk on Table 5.3-1 are the materials selected for use as RBS reactor vessel test specimens. The preheat treatment procedure

RBS USAR Revision 27 5.3-4

5.

Bolting Materials Bolting meets the 45 ft-lb and 25 mils lateral expansion requirements at 10°F for River Bend Station.

6.

Alternative Procedures for the Calculation of Stress Intensity Factor Stress intensity factors were calculated by the methods of ASME Section III, Appendix G.

Discontinuity regions were evaluated, as well as shell and head areas, as part of the detailed thermal and stress analysis in the vessel stress report. Equivalent margins of safety to those required for shells and heads were demonstrated using a 1/4 T defect at all locations, with the exception of the main closure flange-to-head and shell discontinuity locations.

It has been determined that an additional restriction of operating limits is required for outside surface flaw size greater than 0.24 in at the outside surface of the flange-to-shell joint (based on additional analyses made for BWR 6 reactor vessels). It has been demonstrated, using a test mockup of these areas, that smaller defects can be affected by the ultrasonic inservice examination procedures required at the adjacent weld joint. Since the stress intensity factor is greatest at the outside surface of the flange-to-shell and head joints, a flaw also can be detected by outside surface examination techniques.

7.

Fracture Toughness Margins in the Control of Reactivity Appendix G of ASME Section III (1995 Edition with Addenda through 1996), Protection Against Non-ductile Failure, was used in determining pressure/temperature limitations for all phases of plant operation.

8.

Results of Chemical Analysis and RTNDT Evaluations are in Table 5.3-1 and Table 5.3-2 Table 5.3-1 contains the original information used to calculate the current P-T Limit Curves.

Table 5.3-2 contains the updated fluence analysis. The information in Table 5.3-2 with the additional information and clarification provided in 5.3.1.6.1 is used to evaluate the current P-T Limit curves. The current P-T Limit Curves are based on information in Table 5.3-1 and bound the updated information contained in Table 5.3-2.

5.3.1.6 Material Surveillance 5.3.1.6.1 Compliance with Reactor Vessel Material Surveillance Program Requirements The materials surveillance program monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from their exposure to neutron irradiation and thermal environment. Reactor vessel materials surveillance specimens are provided in accordance with requirements of ASTM E185-73 and 10CFR50, Appendix H.

Materials for the program are selected to represent materials used in the reactor beltline region.

Specimens are manufactured from a plate actually used in the beltline region and a weld typical of those in the beltline region and thus represent base metal, weld material, and the weld heat affected zone material. The plate and weld are heat treated in a manner which simulates the actual heat treatment performed on the core region shell plates of the completed vessel. The plate and heat affected zone (HAZ) heat numbers and chemical compositions are provided in Table 5.3-1. Those heat numbers labeled with an asterisk on Table 5.3-1 are the materials selected for use as RBS reactor vessel test specimens. The preheat treatment procedure

RBS USAR Revision 27 5.3-6 Second capsule - Per the ISP schedule, this capsule is to be withdrawn for testing in the year 2025.

Third capsule - The ISP schedule reflects permanent deferral.

Fracture toughness testing of irradiated capsule specimens is to be in accordance with requirements of 10CFR50, Appendix H.

5.3.1.6.2 Neutron Flux and Fluence Calculations A description of the methods of analysis is contained in Sections 4.1.4.5 and 4.3.2.8.

The peak fluence at the inside surface of the vessel beltline shell is calculated to be 8.34e18 n/cm2 at 54 EFPY. All predictions of radiation damage to the reactor vessel beltline material were made using peak fluence values.

Future neutron fluence calculations will be performed in accordance with Regulatory Guide 1.190.

As described in Section 4.3.2.8, fluence calculations have been performed in accordance with Regulatory Guide 1.190. The evaluation of this revised fluence is described in Section 5.3.1.6.1.

5.3.1.6.3 Predicted Irradiation Effects on Vessel Beltline Materials Estimated maximum changes in vessel beltline RTNDT (initial reference temperature) values as a function of the 54 effective full power year (EFPY) fluence are listed in Table 5.3-2. The predicted peak 54 EFPY fluence at the inside surface of the vessel beltline is 8.34e18 n/cm2 at 54 EFPY. Transition temperature changes and changes in upper shelf energy were calculated in accordance with the rules of Regulatory Guide 1.99, Revision 2. Reference temperatures were established in accordance with 10CFR50, Appendix G, and NB-2330 of the ASME Code.5.3.1.6.4 Positioning of Surveillance Capsules and Methods of Attachment (Reference H-II C(2))

The remaining surveillance specimen capsules are located at two azimuths (3° and 177°) at a common elevation in the core beltline region. The location of each weld and base metal in the reactor vessel beltline region is provided on Fig. 5.3-6. A schematic of the RPV plates and welds is shown in Figure 5.3-7. The sealed capsules are not attached to the vessel but are in welded capsule holders. The capsule holders are mechanically retained by capsule holder brackets welded to the vessel cladding as shown on Fig. 5.3-3. The capsule holder brackets allow the removal and reinsertion of capsule holders. Although not a code part, these brackets are designed, fabricated, and analyzed to the general requirements of ASME Section III.

In areas where brackets, such as the surveillance specimen holder brackets, are located, additional nondestructive examinations are performed on the vessel base metal and stainless-steel weld deposited cladding or weld buildup pads during vessel manufacture. The area examined is the area of the subsequent attachment weld plus a band around this area of width equal to at least half the thickness of the part joined. The required stainless-steel weld deposited cladding is similarly examined. The full penetration welds are liquid penetrant examined. Cladding thickness is required to be at least 1/8 in.

RBS USAR Revision 27 5.3-7 The above requirements have been successfully applied to a variety of bracket designs which are attached to weld deposited stainless steel cladding or weld buildups in many operating BWR RPVs.

Inservice inspection examinations of core beltline pressure retaining welds may be perf ormed from the outside surface of the RPV. If a bracket for mechanically retaining surveillance specimen capsule holders were located at or adjacent to a vessel shell weld, it would not interfere with the straight beam or half node angle beam inservice inspection ultrasonic examinations performed from the outside surface of the vessel.

5.3.1.6.5 Time and Number of Dosimetry Measurements GE provided a separate neutron dosimeter so that fluence measurements could be made at the vessel ID after the first fuel cycle to verify the predicted fluence at an early date in plant operation. This measurement was made in 1988, with a measured flux that was about 25%

lower than design predictions, which is consistent with dosimeter test results at other BWRs.

Updated fluence calculations, performed in accordance with Regulatory Guide 1.190, confirmed the current P-T curves are conservative up to 54 EFPY. Dosimeter flux wires are also included in the surveillance capsules, so that additional fluence measurements may be taken as required by the BWRVIP ISP program (Reference 6 and 7). Thus, there is no need for additional separate dosimetry. It is possible, however, to install a new dosimeter, if required, during succeeding fuel cycles.

5.3.1.7 Reactor Vessel Fasteners The reactor vessel closure head (flange) is fastened to the reactor vessel shell flange by multiple sets of threaded studs and nuts. The lower end of each stud is installed in a threaded hole in the vessel shell flange. A nut and washer are installed on the upper end of each stud.

The proper amount of preload can be applied to the studs by a sequential tensioning using hydraulic tensioners. The design and analysis of this area of the vessel are in full compliance with all ASME Section III, Class 1, code requirements. The material for studs, nuts, and washers is SA540 Grade B23 or B24 at the 130,000 psi specified minimum yield strengths level.

Hardness tests are performed on all main closure bolting to demonstrate that heat treatment has been properly performed. A minimum of 45 ft-lb Charpy V-notch (Cv) energy and 25-mils lateral expansion is required at 70°F. The maximum reported ultimate tensile strength is below the 170,000 psi maximum specified in Regulatory Guide 1.65. Also, the Charpy impact test requirements of G-IV A.4 are satisfied, as the lowest reported C energy is 49 ft-lb at +10°F, compared to the requirement of 45 ft-lb at 70°F, and the lowest reported C expansion was 25 mils, as required. Studs, nuts, and washers are ultrasonically examined in accordance with ASME Section III, NB-2585, and the following additional requirements:

1.

Examination was performed after heat treatment and prior to machining threads.

2.

Straight beam examination was performed on 100 percent of each stud. Reference standard for the radial scan is a 1/2-in diameter flat bottom hole having a depth equal to 10 percent of the material thickness. For the end scan the standard of NB-2585 is used.

3.

Nuts and washers were examined by angle beam from the outside circumference in accordance with ASME SA388 in both the axial and circumferential directions.

RBS USAR Revision 27 5.3-8 The surface examinations of NB-2583 are applied after heat treatment and threading.

There are no metal platings applied to closure studs, nuts, or washers. A phosphate coating is applied to threaded areas of studs and nuts and bearing areas of nuts and washers to assist in retaining lubricant on these surfaces.

Regulatory Guide 1.65 defines acceptable materials and testing procedures with regard to reactor vessel closure stud bolting for light-water-cooled reactors.

The RPV closure studs are SA540 Grade B23 or 24 (AISI4340) and have a maximum ultimate tensile strength of 170 ksi. Additionally, the bolting material has Charpy V-notch impact properties of 45 ft-lb minimum with 25 mils lateral expansion. Nondestructive examination before and after threading is specified to be in accordance with ASME Section III, Subsubarticle NB-2580, which complies with Regulatory Position C.2. Subsequent to fabrication, the studs are manganese phosphate-coated and are lubricated with a graphite/alcohol or a nickel powder base lubricant.

In relationship to Regulatory Position C.2.b, the bolting materials were ultrasonically examined after final heat treatment and prior to threading, as specified. As required for compliance, the examination was done in accordance with SA388. The procedures approved for use in practice were judged to insure comparable material quality and, moreover, were considered adequate on the basis of compliance with the applicable requirements of ASME Section III, Paragraph NB-2583. Additionally, straight beam examination was performed on 100 percent of cylindrical surfaces and from both ends of each stud using a 3/4-in maximum diameter transducer. In addition to the code required notch, the reference standard for the radial scan contained a 1/2-in diameter flat bottom hole with a depth of 10 percent of the thickness, and the end scan standard contained a 1/4-in diameter flat bottom hole 1/2-in deep. Also, angle beam examination was performed on the outer cylindrical surface in both a flat and circumferential direction. Surface examinations were performed on the studs and nuts after final heat treatment and threading, as specified in the guide, in accordance with NB-2583 of the applicable ASME Code.

Radial scan calibration is based on a 1/2-in (12.7 mm) diameter flat bottom hole of a depth equal to 10 percent of the material thickness. End scan calibration is in accordance with NB-2585. Angle beam examination is performed on the outer cylindrical surface of nuts and washer in accordance with ASME SA388 in both axial and circumferential directions. Any indication greater than the indication from the applicable calibration feature is unacceptable. A distance-amplitude correction curve in accordance with NB-2585 is used for the longitudinal wave examination.

In relationship to Regulatory Position C.3, GE practice allows exposure to stud bolting surfaces to high purity fill water; nuts and washers are dry stored during refueling.

5.3.2 Pressure-Temperature Limits 5.3.2.1 Limit Curves The limit curves presented in Technical Specifications (T.S.) Figure 3.4.11-1 are based on the requirements of 10CFR50, Appendix G. All the vessel shell and head areas remote from discontinuities plus the feedwater nozzles were evaluated, and the operating limit curves are based on the limiting location. The boltup limits for the flange and adjacent shell region are

RBS USAR Revision 27 5.3-9 based on a minimum metal temperature of RTNDT+60°F. The maximum through-wall temperature gradient from continuous heating or cooling at 100°F per hr was considered. The safety factors applied were as specified in ASME Code Appendix G.

In accordance with 10CRF50 Appendix H and ASTM E185, the first surveillance capsule of irradiated specimens was pulled and tested at ~10.4 EFPY. River Bend is committed to participate in the BWR ISP which determines the schedule of the subsequent capsule pulls and testing as outlined in Section 5.3.1.6.1. The procedure used to update the actual fracture toughness limits is in accordance with 10CFR50, Appendix G, and ASME Code Section III, Appendix G. Fracture toughness properties of ferritic materials are determined by performing Charpy V-notch tests and, when required, dropweight tests, as specified in ASME Code Section III subsections NB-2321.2 and NB-2321.1, respectively. After testing, the RTNDT level will be compared to the acceptable value as specified in 10CFR50, Appendix G. If the results are within the allowable limit, the limit curves in the T.S. will not change. Any shifts occurring in the core beltline transition temperature due to neutron irradiation, will be plotted on Curves A, B, and C. The operation of RBS would be restricted if Curve C were to exceed the saturation limits.

5.3.2.1.1 Temperature Limits for Boltup A minimum temperature of 68°F is required for the closure studs for River Bend Station. A sufficient number of studs (up to 10 percent) may be fully tensioned at this minimum closure stud temperature to seal the closure flange O-rings for the purpose of raising the reactor water level above the closure flanges in order to assist in warming them. The flanges and adjacent shell are required to be warmed to a minimum temperature of 68°F before they are stressed by the full intended bolt preload (all bolts fully tightened). The fully preloaded boltup limits are shown on Fig. 5.3-4.

5.3.2.1.2 Temperature Limits for ISI Hydrostatic or Leak Pressure Tests The fracture toughness analysis for system pressure tests resulted in the curves labeled A shown in T.S. Figure 3.4.11-1. The curves labeled "core beltline" are based on an initial RTNDT of -50°F for the weld material for River Bend Station.

The T.S. Figure shows the beltline curve with an addition of 152°F for up to 54 EFPY of operation at River Bend Station.

5.3.2.1.3 Operating Limits During Heatup, Cooldown, and Core Operation The fracture toughness analysis was done for the normal heatup or cooldown rate of 100°F/hr.

The temperature gradients and thermal stress effects corresponding to this rate were included.

The results of the analyses are a set of operating limits for nonnuclear heatup or cooldown shown as curves labeled B in the T.S. Figure. Curves labeled C on this figure apply whenever the core is critical.

RBS USAR Revision 27 5.3-10 5.3.2.1.4 Reactor Vessel Annealing Inplace annealing of the reactor vessel because of radiation embrittlement is unnecessary because the predicted value of the adjusted reference temperature does not exceed 200°F (10CFR50, Appendix G).

5.3.2.1.5 Predicted Shift in RTNDT For design purposes, the adjusted reference temperature for BWR vessels is predicted using the procedures in Regulatory Guide 1.99, Revision 2.

5.3.2.2 Operating Procedures By comparison of the pressure vs temperature limit in Section 5.3.2.1 with intended normal operating procedures for the most severe upset transient, it is shown that these limits are not exceeded during any foreseeable upset condition. Reactor operating procedures have been established in such a manner that actual transients are not more severe than those for which the vessel design adequacy has been demonstrated. Of the design transients, the upset condition producing the most adverse temperature and pressure condition anywhere in the vessel head and/or shell areas occurs in the bottom head, yielding a minimum fluid temperature of 250°F and a maximum pressure peak of 1,180 psig. Scram automatically occurs as a result of this event, prior to the reduction in bottom head fluid temperature, so the applicable operating limits are given by the nonnuclear heating limits for vessel discontinuities such as the bottom head (curve B on T.S. Figure 3.4.11-1). For a temperature of 250°F, the maximum allowable pressure exceeds 1,600 psig for the intended margin against nonductile failure. The maximum transient pressure of 1,180 psig is therefore within the specified allowable limits.

5.3.3 Reactor Vessel Integrity The reactor vessel was fabricated for GE's Nuclear Energy Division by CBI Nuclear Company and was subject to the requirements of GE's quality assurance program.

The CBI Nuclear Company has had extensive experience with GE reactor vessels and has been the primary supplier of GE domestic reactor vessels and some foreign vessels since the company was formed in 1972 from a merger agreement between Chicago Bridge and Iron Company and GE. Prior experience by the Chicago Bridge and Iron Company with GE reactor vessels dates back to 1966.

Assurance was made that measures were established requiring that purchased material, equipment, and services associated with the reactor vessels and appurtenances conform to the requirements of the subject purchase documents. These measures included provisions, as appropriate, for source evaluation and selection, objective evidence of quality furnished, inspection at the vendor source, and examination of the completed reactor vessels.

GE provided inspection surveillance of the reactor vessel fabricator's inprocess manufacturing, fabrication, and testing operations in accordance with GE's quality assurance program and approved inspection procedures. The reactor vessel fabricator is responsible for the f irst level inspection of his manufacturing, fabrication, and testing activities, and GE is responsible for the first level of audit and surveillance inspection.

RBS USAR Revision 27 5.3-11 Adequate documentary evidence that the reactor vessel material, manufacture, testing, and inspection conforms to the specified quality assurance requirements contained in the procurement specification is available at the fabricator's plant site.

Regulatory Guide 1.2 states that a suitable program be followed to assure the reactor pressure vessel behaves in a nonbrittle manner under loss-of-coolant accident (LOCA) conditions.

Should it be considered that the margin of safety against reactor pressure vessel brittle fracture due to emergency core cooling system operation at any time during vessel life is unacceptable, the Regulatory Guide states that an engineering solution, such as annealing, could be applied to assure adequate recovery of the fracture toughness properties of the vessel material.

An analysis of the structural integrity of boiling water reactor pressure vessels during a design basis accident (DBA) has been performed.

The analysis included:

1.

Description of the LOCA event.

2.

Thermal analysis of the vessel wall to determine the temperature distribution at different times during the LOCA.

3.

Determination of the stresses in the vessel wall including thermal, pressure, and residual stresses.

4.

Consideration of radiation effect on material toughness (NDTT shift and changes in toughness).

5.

Fracture mechanics evaluation of vessel wall for differed postulated flaw sizes.

This analysis incorporated conservative assumptions in all areas (particularly in the areas of heat transfer, stress analysis, effects of radiation on material toughness, and crack tip stress intensity factor evaluation). The analysis concluded that even in the presence of large flaws the vessel would have considerable margin against brittle fracture following a LOCA.

5.3.3.1 Design 5.3.3.1.1 Description 5.3.3.1.1.1 Reactor Vessel The reactor vessel shown on Fig.5.3-1 is a vertical, cylindrical pressure vessel of welded construction. The vessel is designed, fabricated, tested, inspected, and stamped in accordance with the ASME Section III, Class I, 1971 requirements to and including the Summer 1973 Addenda. Design of the reactor vessel and its support system meets Seismic Category I equipment requirements. The materials used in the RPV are listed in Table 5.2-3.

The cylindrical shell and top and bottom heads of the reactor vessel are fabricated of low alloy steel, the interior of which is clad with stainless steel weld overlay, except for the top head and nozzle and nozzle weld zones.

RBS USAR Revision 27 5.3-12 Inplace annealing of the reactor vessel is unnecessary because shifts in transition temperature caused by irradiation during the 40-yr life can be accommodated by raising the minimum pressurization temperature and the predicted value of adjusted reference temperature does not exceed 200°F. Radiation embrittlement is not a problem outside the vessel beltline region because of the low fluence in those areas.

Quality control methods used during the fabrication and assembly of the reactor vessel and appurtenances assure that design specifications are met.

The vessel top head is secured to the reactor vessel by studs and nuts. These nuts are tightened with a stud tensioner. The vessel flanges are sealed with two concentric metal seal-rings designed to permit no detectable leakage through the inner or outer seal at any operating condition, including heating to operating pressure and temperature at a maximum rate of 100°F/hr in any 1-hr period. To detect seal failure, a vent tap is located between the two seal-rings. A monitor line is attached to the tap to provide an indication of leakage from the inner seal-ring seal.

5.3.3.1.1.2 Shroud Support The shroud support is a circular plate welded to the vessel wall and to a cylinder supported by vertical stilt legs from the bottom head. This support is designed to carry the weight of peripheral fuel elements, neutron sources, core plate, top guide, the steam separators, and the jet pump diffusers, and to laterally support the fuel assemblies. Design of the shroud support also accounts for pressure differentials across the shroud support plate, for the restraining effect of components attached to the support, and for earthquake loadings. The shroud support design is specified to meet appropriate ASME Code stress limits.

5.3.3.1.1.3 Protection of Closure Studs The BWR does not use borated water for reactivity control during normal operation.

5.3.3.1.2 Safety Design Basis The design of the reactor vessel and appurtenances meets the following safety design bases:

1.

The reactor vessel and appurtenances can withstand adverse combinations of loading and forces resulting from operation under abnormal and accident conditions.

2.

To minimize the possibility of brittle fracture of the nuclear system process barrier, the following are required:

a.

Impact properties at temperatures related to vessel operation have been specified for materials used in the reactor vessel.

b.

Expected shifts in transition temperature during design life as a result of environmental conditions, such as neutron flux, are considered in the design.

Operational limitations assure that NDT temperature shifts are accounted for in reactor operation.

RBS USAR Revision 27 5.3-13

c.

Operational margins to be observed with regard to the transition temperature are specified for each mode of operation.

5.3.3.1.3 Power Generation Design Basis The design of the reactor vessel and appurtenances meets the following power generation design bases:

1.

The reactor vessel has been designed for a useful life of at least 40 yr.

2.

External and internal supports that are integral parts of the reactor vessel are located and designed so that stresses in the vessel and supports that result from reactions at these supports are within ASME Code limits.

3.

Design of the reactor vessel and appurtenances allows for a suitable program of inspection and surveillance.

5.3.3.1.4 Reactor Vessel Design Data The reactor vessel design pressure is 1,250 psig, and the design temperature is 575°F. The maximum installed test pressure is 1,563 psig.

5.3.3.1.4.1 Vessel Support The concrete and steel vessel support pedestal is constructed as an integral part of the building foundation. Steel anchor bolts set in the concrete extend through the bearing plate and secure the flange of the reactor vessel support skirt to the bearing plate and thus to the support pedestal (Section 3.8.3).

5.3.3.1.4.2 Control Rod Drive Housings The CRD housings are inserted through the CRD penetrations in the reactor vessel bottom head and are welded to the reactor vessel. Each housing transmits loads to the bottom head of the reactor. These loads include the weights of a control rod, a CRD, a control rod guide tube, a four-lobed fuel support piece, and the four fuel assemblies that rest on the fuel support piece.

The housings are fabricated of Type 304 austenitic stainless steel and Inconel 600.

5.3.3.1.4.3 In-Core Neutron Flux Monitor Housings Each in-core neutron flux monitor housing is inserted through the in-core penetrations in the bottom head and is welded to the inner surface of the bottom head.

An in-core flux monitor guide tube is welded to the top of each housing and either a source range monitor/intermediate range monitor (SRM/IRM) drive unit or a local power range monitor (LPRM) is bolted to the seal-ring flange at the bottom of the housing (Section 7.6).

5.3.3.1.4.4 Reactor Vessel Insulation The insulation on the bottom head of the reactor vessel is of the reflective metallic type and has an average maximum heat transfer coefficient of approximately 0.2 Btu/hr/sq ft-°F at the operating conditions of 550°F for the vessel and 135°F for the drywell air. The insulation for the

RBS USAR Revision 27 5.3-14 remainder of the reactor vessel is comprised of fiberglass panels totally encapsulated in fiberglass cloth and has an average maximum heat transfer coefficient of approximately 0.4 Btu/in/hr/sq ft-°F with the reactor at rated operating conditions. The fiberglass panels for the cylindrical portion of the reactor are secured to a stainless-steel support structure that is attached to the primary shield wall. The fiberglass panels for the top head are secured to a removable insulation support structure. The insulation is designed to be removable over those portions of the vessel where inspection is required by ASME Section XI. The insulation assemblies are designed to remain in place and resist permanent damage during an SSE.

5.3.3.1.4.5 Reactor Vessel Nozzles All piping connected to the reactor vessel nozzles has been designed so as not to exceed the allowable loads on any nozzle. The vessel top head nozzle is provided with a flange with large groove facing. The drain nozzle is of the full penetration weld design. The recirculation inlet nozzles (located as shown on Fig.5.3-1), core spray inlet nozzles, and the LPCI nozzles all have thermal sleeves. The feedwater inlet nozzles have triple thermal sleeves to minimize the potential for cracking in the feedwater nozzle bend radius behind the thermal sleeves caused by leakage past the thermal sleeves. As an alternate to the triple thermal sleeve for the feed water inlet nozzles, the double sleeve tuning fork design may be used to obtain nozzle protection.

Nozzles connecting to stainless steel piping have safe ends or extensions made of stainless steel. These safe ends or extensions were welded to the nozzles after the pressure vessel was heat treated to avoid furnace sensitization of the stainless steel. The material used is compatible with the material of the mating pipe.

The following weldments have been treated with the Mechanical Stress Improvement Process (MSIP) to reduce the susceptibility of Inconel 182 weld buttering pursuant to the guidelines of NUREG-0313 Revision 2:

Nozzle Description Nozzle I.D.

Weld Location Quant. Nozzle Description Nozzle I.D.

Weld Location Quant.

Recirculation Outlet N-1 Nozzle-Safe End 2

Residual Ht.

Removal N-6 Nozzle-Safe End 3

Recirculation Inlet N-2 Nozzle-Safe End 10 Residual Ht.

Removal N-6 Safe End-Extension 3

Feedwater Inlet N-4 Nozzle-Safe End 3*

Jet Pump Instr.

N-9 Nozzle-Safe End 2

Core Spray N-5 Nozzle-Safe End 2

CRD Hyd.

Return N-10 Safe End-Cap 1

Core Spray N-5 Safe End-Extension 2

The N4A safe end was replaced due to a crack in the nozzle to safe end end weld. N4B, C

& D were treated with MSIP.

The nozzle for the standby liquid control pipe is designed to minimize thermal shock ef f ects on the reactor vessel in the event that use of the standby liquid control system is required.

The three LPCI inlets are each designed with a flow deflector to prevent horizontal flow impingement upon the core and instrument tubes. The flow deflectors are designed with a

RBS USAR Revision 27 5.3-15 conical flow splitter which redirects the LPCI flow upward, downward, and in the two horizontal directions tangential to the core. The flow deflectors are fabricated of 316C stainless steel plate material attached to the shroud wall by full penetration welds at the four corners of the deflector plate.

The design, analysis, and testing of the deflectors and its effects on the LPCI system parameters were considered in Reference 4.

In addition to the use of flow deflectors, the intermediate range monitor (IRM) instrument tube nearest each LPCI inlet is reinforced.

5.3.3.1.4.6 Materials and Inspections The reactor vessel was designed and fabricated in accordance with the appropriate ASME Boiler and Pressure Vessel Code as defined in Section 5.2.1. Table 5.2-3 defines the materials and specifications. Section 5.3.1.6 defines the compliance with reactor vessel material surveillance program requirements.

5.3.3.1.4.7 Reactor Vessel Schematic (BWR)

The reactor vessel schematic is contained on Fig.5.3-1. Trip system water levels are indicated as shown on Fig. 5.3-2.

5.3.3.2 Materials of Construction All materials used in the construction of the RPV conform to the requirements of ASME Section II materials. The vessel heads, shells, flanges, and nozzles are fabricated from low alloy steel plate and forgings purchased in accordance with ASME specifications SA533 Grade B, Class 1 and SA508, Class 2. Special requirements for the low alloy steel plate and f orgings are discussed in Section 5.3.1.2. Cladding employed on the interior surfaces of the vessel consists of austenitic stainless-steel weld overlay.

These materials of construction were selected because they provide adequate strength, fracture toughness, fabricability, and compatibility with the BWR environment. Their suitability has been demonstrated by long-term successful operating experience in reactor service.

5.3.3.3 Fabrication Methods The RPV is a vertical cylindrical pressure vessel of welded construction fabricated in accordance with ASME Section III Class I requirements. All fabrication of the RPV was performed in accordance with GE-approved drawings, fabrication procedures, and test procedures. The shell and vessel head were made from formed low alloy steel plates and the flanges and nozzles from low alloy steel forgings. Welding performed to join these vessel components was in accordance with procedures qualified in accordance with ASME Section III and IX requirements. Weld test samples were required for each procedure for major vessel f ull penetration welds.

Submerged arc and manual stick electrode welding processes were employed. Electroslag welding was not permitted. Preheat and interpass temperatures employed for welding of low alloy steel met or exceeded the requirements of ASME Section III, Subsection NA. Post weld heat treatment of 1100°F minimum was applied to all low alloy steel welds.

RBS USAR Revision 27 5.3-16 All previous BWR pressure vessels have employed similar fabrication methods. These vessels have operated for an extensive number of years, and their service history is excellent.

The vessel fabricator, CBI Nuclear Company, has had extensive experience with GE reactor vessels and has been the primary supplier for GE domestic reactor vessels and some foreign vessels since the company was formed in 1972 from a merger agreement between Chicago Bridge and Iron Company and GE. Prior experience by the Chicago Bridge and Iron Company with GE reactor vessels dates back to 1966.

5.3.3.4 Inspection Requirements All plate, forgings, and bolting were 100-percent ultrasonically tested and surface examined by magnetic particle methods or liquid penetrant methods in accordance with ASME Section III requirements. Welds on the RPV were examined in accordance with methods prescribed and meet the acceptance requirements specified by ASME Section III. In addition, the pressure retaining welds were ultrasonically examined using acceptance standards which are required by ASME Section XI.

5.3.3.5 Shipment and Installation The completed reactor vessel is given a thorough cleaning and examination prior to shipment.

The vessel is tightly sealed for shipment to prevent entry of dirt or moisture. Preparations for shipment are in accordance with detailed written procedures. On arrival at the reactor site the reactor vessel is carefully examined for evidence of any contamination as a result of damage to shipping covers. Suitable measures are taken during installation to assure that vessel integrity is maintained; for example, access controls are applied to personnel entering the vessel, weather protection is provided, and periodic cleanings are performed.

5.3.3.6 Operating Conditions Procedural controls on plant operation are implemented to hold thermal stresses within acceptable ranges. These restrictions on coolant temperature are:

1.

The average rate of change of reactor coolant temperature during normal heatup and cooldown does not exceed 100°F during any 1-hr period.

2.

If the coolant temperature difference between the dome (inferred f rom P(sat)) and the bottom head drain exceeds 100°F, neither reactor power level nor recirculation pump flow are increased.

3.

The pump in an idle reactor recirculation loop is not started unless the coolant temperature in that loop is within 50°F of average reactor coolant temperature.

The limit regarding the normal rate of heatup and cooldown (Item 1) assures that the vessel closure, closure studs, vessel support skirt, and CRD housing and stub tube stresses and usage remain within acceptable limits. The limit regarding a vessel temperature limit on recirculating pump operation and power level increase restriction (Item 2) augments the Item 1 limit in further detail by assuring that the vessel bottom head region is not warmed at an excessive rate caused by rapid sweep out of cold coolant in the vessel lower head region by recirculating pump operation or natural circulation (cold coolant can accumulate as a result of control drive

RBS USAR Revision 27 5.3-17 inleakage and/or low recirculation flow rate during startup or hot standby). The Item 3 limit further restricts operation of the recirculating pumps to avoid high thermal stress ef fects in the pumps and piping, while also minimizing thermal stresses on the vessel nozzles.

The above operational limits, when maintained, insure that the stress limits within the reactor vessel and its components are within the thermal limits to which the vessel was designed for normal operating conditions. To maintain the integrity of the vessel in the event that these operational limits are exceeded, the reactor vessel has also been designed to withstand a limited number of transients caused by operator error. Also, for abnormal operating conditions where safety systems or controls provide an automatic temperature and pressure response in the reactor vessel, the reactor vessel integrity is maintained since the severest anticipated transients have been included in the design conditions. Therefore, it is concluded that vessel integrity is maintained during the most severe postulated transients, since all such transients are evaluated in the design of the reactor vessel. The postulated transient for which the vessel has been designed is shown on Fig. 5.2-5 and discussed in Section 5.2.2.

5.3.3.7 Inservice Surveillance Inservice inspection of the reactor pressure vessel is in accordance with the requirements of the 1971 Edition of ASME Section XI, including the Summer 1973 Addenda. The vessel is to be examined once prior to startup to satisfy the preoperational requirements of IS-232 of ASME Section XI. Subsequent inservice inspection is scheduled and performed in accordance with the requirements of 10CFR50.55a, subparagraph (g).

The materials surveillance program monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from their exposure to neutron irradiation and thermal environment. Specimens of actual reactor beltline material are exposed in the reactor vessel and periodically withdrawn for impact testing. Operating procedures will be modified as necessary in accordance with test results to assure adequate brittle fracture control.

Material surveillance programs and inservice inspection programs are in accordance with applicable ASME Code requirements and provide assurance that brittle fracture control and pressure vessel integrity are maintained throughout the service lifetime of the RPV.

References - 5.3

1.

An Analytical Study on Brittle Fracture of GE-BWR Vessel Subject to the Design Basis Accident. NEDO-10029.

2.

Watanabe, H. Boiling Water Reactor Feedwater Nozzle/Sparger Final Report.

NEDO-21821-2, Proprietary Version, and NEDO-21821-2, Nonproprietary Version, August 1979.

3.

Cooke, F. Transient Pressure Rises Affecting Fracture Toughness Requirements for Boiling Water Reactors. NEDO-21778-A, December 1978.

4.

Artigas, Dr. R. Flow Deflector Effects on LPCI Parameters and Plant Safety, to R. L. Tedesco (NRC), May 18, 1982.

5.

GE-NE-B13-02094-00-01, Revision 0, Class III, January 2001, Pressure-Temperature Curves for Entergy Operations Inc. (EOI), Using the Klc Methodology River Bend.

RBS USAR Revision 27 5.3-18

6.

Letter from W. H. Bateman (NRC) to C. Terry (BWRVIP Chairman) entitled, Safety Evaluation Regarding EPRI Proprietary Report BWR Vessel and Internals Project, BWR Integrated Surveillance Program Plan (BWRVIP-78) and BWRVIP-86: BWR Vessel and Internals Project, BWR Integrated Surveillance Program Implementation Plan, dated February 1, 2002.

7.

Electric Power Research Institute (EPRI) Technical Report 1003346, entitled "BWRVIP-86, Revision 1-A: BWR Vessel and Internals Project Updated BWR Integrated Surveillance Program (ISP) Implementation Plan," Final Report, dated October 2012.

8.

Engineering Report 2012 No. RBS-NE-17-00003, Latest Revision, "License Renewal Input for RBS Pressure-Temperature Limits Report Up to 54 Effective Full Power Years"

9.

Engineering Report No. RBS-NE-17-00002, Latest Revision, "License Renewal Input for RBS Fluence Project Up to 54 Effective Full Power Years (EFPY)"

10.

Electric Power Research Institute (EPRI) BWRVIP-135, Revision 3: BWR Vessel and Internals Project Updated BWR Integrated Surveillance Program (ISP) Data Source Book and Plant Evaluations, Final Report, dated December 2014.

11.

DELETED

RBS USAR TABLE 5.3-1 Revision 27 1 of 1

1) Vessel Plate (Beltline)

Percent Heat Number C

Mn Si P

S Ni Cu Mo V

C3138-2 0.19 1.37 0.25 0.012 0.015 0.63 0.08 0.58 C3054-1 0.19 1.30 0.26 0.007 0.020 0.70 0.09 0.57

• C3054-2 0.19 1.30 0.26 0.007 0.012 0.70 0.09 0.57

2) Vessel Welds (Beltline)

Percent Heat/Lot No.

C Mn Si P

S Ni Cu Mo V

492L4871/

0.07 1.06 0.37 0.018 0.025 0.95 0.04 0.50 0.02 A421B27AE 492L4871/

0.07 1.17 0.32 0.020 0.020 0.98 0.03 0.51 0.02 A421B27AF

• 5P6756/0342(1) 0.078 1.24 0.53 0.010 0.012 0.938 0.084 0.46 0.006

• 5P6756/0342(2) 0.063 1.27 0.57 0.010 0.011 0.938 0.084 0.45 0.006

• Selected for reactor vessel test specimen.

(1) Tandem wire process (2) Single wire process

RBS USAR Revision 27 Page 1 of 3 Table 5.3-2 Shell #3 and Axial Welds, Circumferential Weld AC Thickness in inches= 5.41 54 EFPY Peak I.D. fluence = 3.43E+17 n/cm2 54 EFPY Peak 1/4 T fluence = 2.48E+17 n/cm2 Shell #2 and Axial Welds Thickness in inches= 5.41 54 EFPY Peak I.D. fluence = 8.34E+18 n/cm2 54 EFPY Peak 1/4 T fluence = 6.03E+18 n/cm2 Shell #1 and Axial Welds, Circumferential Weld AB Thickness in inches= 5.813 54 EFPY Peak I.D. fluence = 7.68E+17 n/cm2 54 EFPY Peak 1/4 T fluence = 5.42E+17 n/cm2 N12 Water Level instrumentation Nozzle Thickness in inches= 5.41 54 EFPY Peak I.D. fluence = 2.99E+18 n/cm2 54 EFPY Peak 1/4 T fluence = 2.16E+18 n/cm2 N6 RHR/LPCI Nozzle Thickness in inches= 5.41 54 EFPY Peak I.D. fluence = 2.33E+17 n/cm2 54 EFPY Peak 1/4 T fluence = 1.68E+17 n/cm2 COMPONENT HEAT

%Cu

%Ni CF Adjusted CF Initial RTNDT

°F 1/4 T fluence n/cm2 54

()3<

RTNDT

°F I

Margin

°F 54 EFPY Shift

°F 55 EFPY ART

°F PLANT SPECIFIC CHEMISTRIES Plates:

Shell #3 C2904-2 C3001-2 C2929-2 0.11 0.04 0.12 0.65 0.66 0.64 75 26 84 10

-40

-50 2.48E+17 2.48E+17 2.48E+17 14.7 5.1 16.4 0

0 0

7.3 2.5 8.2 14.7 5.1 16.4 29.3 10.2 32.8 39.3

-29.8

-17.2 Shell #2 C3054-1 C3054-2 C3138-2 0.09 0.09 0.08 0.70 0.70 0.63 58 58 51

-20 10 0

6.03E+18 6.03E+18 6.03E+18 49.8 49.8 43.8 0

0 0

17.0 17.0 17.0 34.0 34.0 34.0 83.8 83.8 77.8 63.8 93.8 77.8 Shell #1 C2904-1 C2879-1 0.11 0.12 0.65 0.61 75 83 10 10 5.42E+17 5.42E+17 22.8 25.4 0

0 11.4 12.7 22.8 25.4 45.7 50.9 55.7 60.9

RBS USAR Revision 27 Page 2 of 3 Table 5.3-2 (Cont.)

COMPONENT HEAT

%Cu

%Ni CF Adjusted CF Initial RTNDT

°F 1/4 T fluence n/cm2 54

()3<

RTNDT

°F I

Margin

°F 54 EFPY Shift

°F 55 EFPY ART

°F AXIAL WELDS:

Shell #3 BJ, BK, BM Shell #3 BJ, BK, BM 5P5657/Linde 124/0931 (S)[4]

5P5657/Linde 124/0931 (T)[4]

0.07 0.04 0.71 0.89 95 54

-60

-60 2.48E+17 2.48E+17 18.6 10.6 0

0 9.3 5.3 18.6 10.6 37.3 21.2

-22.7

-38.8 Shell #2 BE, BF, BG Shell #2 BE, BF, BG 5P6756/Linde 124/0342 (S)[4]

5P6756/Linde 124/0342 (T)[4]

0.08 0.09 0.93 0.92 108 122

-60

-50 6.03E+18 6.03E+18 92.7 104.7 0

0 28.0 28.0 56.0 56.0 148.7 160.7 88.7 110.7 Shell #1 BA, BB Shell #1 BA, BB 5P5657/Linde 124/0931 (S)[4]

5P5657/Linde 124/0931 (T)[4]

0.07 0.04 0.71 0.89 95 54

-60

-60 5.42E+17 5.42E+17 29.0 16.5 0

0 14.5 8.3 29.0 16.5 58.1 33.0

-1.9

-27.0 Shell #2 to Shell #3: AC Shell #2 to Shell #3: AC 5P6771/Linde 124/0342 (S)[4]

5P6771/Linde 124/0342 (T)[4]

0.03 0.04 0.88 0.95 41 54

-30

-20 2.48E+17 2.48E+17 8.0 10.6 0

0 4.0 5.3 8.0 10.6 16.1 21.2

-13.9 1.2 CIRCUMFERENTIAL WELDS:

Shell #2 to Shell #3: AC Shell #2 to Shell #3: AC 5P6771/Linde 124/0342 (S)[4]

5P6771/Linde 124/0342 (T)[4]

0.03 0.04 0.88 0.95 41 54

-30

-20 2.48E+17 2.48E+17 8.0 10.6 0

0 4.0 5.3 8.0 10.6 16.1 21.2

-13.9 1.2 Shell #1 to Shell #2: AB Shell #1 to Shell #2: AB Shell #1 to Shell #2: AB Shell #1 to Shell #2: AB 4P7216/Linde 124/0751 (S)[4]

4P7216/Linde 124/0751 (T)[4]

4P7465/Linde 124/0751 (S)[4]

4P7465/Linde 124/0751 (T)[4]

0.06 0.04 0.02 0.02 0.85 0.83 0.82 0.80 82 54 27 27

-50

-80

-60

-60 5.42E+17 5.42E+17 5.42E+17 5.42E+17 25.1 16.5 8.3 8.3 0

0 0

0 12.5 8.3 4.1 4.1 25.1 16.5 8.3 8.3 50.1 33.0 16.5 16.5 0.1

-47

-43.5

-43.5 NOZZLES:

N6 Forging N6 Weld N6 Weld Q2QL4W 5P6771/Linde 124/0342 (S)[4]

5P6771/Linde 124/0342 (T)[4]

0.10 0.03 0.04 0.86 0.88 0.95 67 41 54

-20

-30

-20 1.68E+17 1.68E+17 1.68E+17 10.3 6.3 8.3 0

0 0

5.2 3.2 4.2 10.3 6.3 8.3 20.7 12.7 16.7 0.7

-17.3

-3.3 N12 Forging [1]

N12 Weld [1]

C3054-2 Inconel 182 0.09 0.7 58 10 2.16E+18 34.1 0

17.0 34 68.1 78.1

RBS USAR Revision 27 Page 3 of 3 Table 5.3-2 (Cont.)

COMPONENT HEAT

%Cu

%Ni CF Adjusted CF Initial RTNDT

°F 1/4 T fluence n/cm2 54

()3<

RTNDT

°F I

Margin

°F 54 EFPY Shift

°F 55 EFPY ART

°F BEST ESTIMATE CHEMISTRIES From BWRVIP-135 Shell #2 C3054-2 0.08 0.67 51 10 6.03E+18 43.8 0

17.0 34 77.8 87.8 Shell #3 BJ, BK, BM Shell #3 BJ, BK, BM 5P5657/Linde 124/0931 (S)[4]

5P5657/Linde 124/0931 (T)[4]

0.034 0.034 0.824 0.824 46 46

-60

-50 2.48E+17 2.48E+17 9.1 9.1 0

0 4.5 4.5 9.1 9.1 18.1 18.1

-41.9

-41.9 Shell #2 BE, BF, BG Shell #2 BE, BF, BG Shell #2 to Shell #3: AC Shell #2 to Shell #3: AC 5P6756/Linde 124/0342 (S)[4]

5P6756/Linde 124/0342 (T)[4]

5P6771/Linde 124/0342 (S)[4]

5P6771/Linde 124/0342 (T)[4 0.08 0.08 0.034 0.034 0.936 0.936 0.934 0.934 108 108 46 46

-30

-20

-30

-20 6.03E+18 6.03E+18 2.48E+17 2.48E+17 92.7 92.7 9.1 9.1 0

0 0

0 28 28 4.5 4.5 56 56 9.1 9.1 148.7 148.7 18.1 18.1 88.7 98.7

-11.9

-1.9 Shell #1 BA, BB Shell #1 BA, BB Shell #1 to Shell #2: AB Shell #1 to Shell #2: AB Shell #1 to Shell #2: AB Shell #1 to Shell #2: AB 5P5657/Linde 124/0931 (S)[4]

5P5657/Linde 124/0931 (T)[4]

4P7216/Linde 124/0751 (S)[4]

4P7216/Linde 124/0751 (T)[4]

4P7465/Linde 124/0751 (S)[4]

4P7465/Linde 124/0751 (T)[4]

0.034 0.034 0.038 0.038 0.02 0.02 0.824 0.824 0.820 0.820 0.807 0.807 46 46 51 51 27 27

-60

-60

-50

-80

-60

-60 5.42E+17 5.42E+17 5.42E+17 5.42E+17 5.42E+17 5.42E+17 14.1 14.1 15.7 15.7 8.3 8.3 0

0 0

0 0

0 7.1 7.1 7.9 7.9 4.1 4.1 14.1 14.1 15.7 15.7 8.3 8.3 28.2 28.2 31.4 31.4 16.5 16.5

-31.8

-31.8

-18.6

-48.6

-43.5

-43.5 INTEGRATED SURVEILLANCE Plate [2]

Weld [3]

Weld [3]

C3054-2 5P6756/Linde 124/0342 (S)[4]

5P6756/Linde 124/0342 (T)[4]

0.08 0.08 0.08 0.673 0.936 0.936 51 154 154 10

-60

-50 6.03E+18 6.03E+18 6.03E+18 43.8 132.1 132.1 0

0 0

17.0 14.0 14.0 34.0 28.0 28.0 77.8 160.1 160.1 87.8 100.1 110.1 Notes:

[1] The N12 Water Level Instrumentation Nozzle occurs in the beltline region. Because the forging is fabricated from stainless steel, the ART is calculated using the plate heats where the nozzles occur. The weld connecting the forging to the vessel shell is Inconel 182 material, and is not required to be evaluated.

[2] The ISP plate material is not the vessel target material, but does occur within the beltline region (Lower-Intermediate Shell). Therefore, this material is considered in determining the limiting ART. Only one set of surveillance data is currently available; therefore, upon testing of a second ISP capsule, the CF can be reviewed.

[3] The ISP weld material is the vessel target material and occurs within the beltline region. Therefore, this material is considered in determining the limiting ART.

The adjusted CF is determined to be the [RG 1.99 CF(vessel material)/RG 1.99 CF(surveillance material)] x CF(fitted). For this material, the adjusted CF =

[108°F/82°F] x 116.9°F = 154°F. The surveiOODQFHGDWDLVFUHGLEOHWKHUHIRUHLVUHGXFHGDVSHUPLWWHGE\\5*

[4] S = Single Wire; T = Tandem Wire

RIVER BEND STATION UPDATED SAFETY ANALYSIS REPORT REVISION 26 Schematic of the RBS RPV Showing Arrangement of Vessel Plates and Welds FIGURE 5.3-7

RBS USAR Revision 27 5.4-1 5.4 COMPONENT AND SUBSYSTEM DESIGN 5.4.1 Reactor Recirculation System 5.4.1.1 Safety Design Bases The reactor recirculation system has been designed to meet the following safety design bases:

1.

An adequate fuel barrier thermal margin is assured during postulated transients.

2.

A failure of piping integrity does not compromise the ability of the reactor vessel internals to provide a refloodable volume.

3.

The system maintains pressure integrity during adverse combinations of loadings and forces occurring during upset, emergency, and faulted conditions.

5.4.1.2 Power Generation Design Bases The reactor recirculation system meets the following power generation design bases:

1.

The system provides sufficient flow to remove heat from the fuel.

2.

The system provides an automatic load following capability over the range of 75 to 100 percent rated power.

3.

System design minimizes maintenance situations that require core disassembly and fuel removal.

5.4.1.3 Description Note:

River Bend Station administratively chose not to operate the recirculation flow control system in the master auto or flux auto modes. These modes allow the system to automatically respond and adjust reactor power due to changes in turbine load or neutron flux.

The reactor recirculation system consists of the two recirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps (Fig. 5.4-1 and 5.4-2). Each external loop contains one high capacity motor-driven recirculation pump, a flow control valve, and two motor-operated gate valves (for pump maintenance). Each pump suction line contains a flow measuring system. The recirculation loops are part of the RCPB and are located inside the drywell structure. The jet pumps are reactor vessel internals. Their location and mechanical design are discussed in Section 3.9.5B. However, certain operational characteristics of the jet pumps are discussed in this section. A tabulation of the important design and performance characteristics of the reactor recirculation system is shown in Table 5.4-1. The head, NPSH, flow, and efficiency curves are shown in Fig. 5.4-3. Instrumentation and control description is provided in Section 7.7.1.2.

The recirculated coolant consists of saturated water from the steam separators and dryers that has been subcooled by incoming feedwater. This water passes down the annulus between the reactor vessel wall and the core shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the

RBS USAR Revision 27 5.4-2 two external recirculation loops discharges high pressure flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel.

The remaining portion of the coolant mixture in the annulus becomes the driven flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the driving flow. The flows, both driving and driven, are mixed in the jet pump throat section and result in partial pressure recovery. The balance of recovery is obtained in the jet pump diffuser (Fig. 5.4-4). The adequacy of the total flow to the core is discussed in Section 4.4.

The allowable heatup rate for the recirculation pump casing is the same as that for the reactor vessel. If one loop is shut down, the idle loop can be kept hot by leaving the loop valves open; this permits the reactor pressure plus the active jet pump head to cause reverse flow in the idle loop.

Because the removal of the reactor recirculation gate valve internals would require use of jet pump plugs or unloading the core due to the resulting draining of coolant, the objective of the valve trim design is to minimize the need for maintenance of the valve internals. The valves are provided with high-quality backseats that permit renewal of stem packing while the system is full of water.

When the pump is operating at 25 percent speed, the head provided by the elevation of the reactor water level above the recirculation pump is sufficient to provide the required NPSH for the recirculation pumps, flow control valve, and jet pumps. When the pump is operating at 100 percent speed, most of the NPSH is supplied by the subcooling provided by the feedwater flow. Temperature detectors are provided in the recirculation suction lines. The difference between this reading and the dome temperature provides a measurement of the subcooling. If the subcooling falls below approximately 8°F, the 100 percent speed power supply is tripped off to prevent cavitation of the associated recirculation pump, jet pumps, and/or the flow control valve.

If subcooling falls below the established setpoint in both loops simultaneously, the 100 percent power source is tripped to the 25 percent speed power source for both recirculation pumps.

When preparing for hydrostatic tests, the nuclear system temperature must be raised above the vessel nil ductility transition temperature limit. The vessel is heated by core decay heat and/or by operating the RHR pumps.

The recirculation pump is driven by a constant speed motor with a low-frequency motor-generator (LFMG) set and is equipped with mechanical shaft seal assemblies. The two seals built into a cartridge can be readily replaced without removing the motor from the pump. Each individual seal in the cartridge is designed for pump operating pressure so that any one seal can adequately limit leakage in the event that the other seal should fail. The pump shaft passes through a breakdown bushing in the pump casing to reduce leakage in the event of a gross failure of both shaft seals.

The cavity temperature and pressure drop across each individual seal can be monitored.

Each recirculation pump motor is a constant speed, vertical, solid shaft, totally enclosed, air-water cooled, induction motor in conjunction with an LFMG set. The combined rotating inertias of the recirculation pump and motor provide a slow coastdown of flow following loss of power to the drive motors so that the core is adequately cooled during the transient. This inertia requirement is met without a flywheel.

The pump discharge flow control valve can throttle the discharge flow of the pump proportionally to an instrument signal. The flow control valve is provided with an equal percentage characteristic.

RBS USAR Revision 27 5.4-3 The recirculation loop flow rate can be rapidly changed, within the expected flow range, in response to rapid changes in system demand.

The design objective for the recirculation system equipment is to provide units that do not require removal from the system for rework or overhaul. Pump casing and valve bodies are designed for a 40-yr life and are welded to the pipe.

The pump drive motor, impeller, and wear rings and flow control valve internals are designed for as long a life as is practical. Pump mechanical seal parts and the valve packing are expected to have a life expectancy which affords convenient replacement during the refueling outages. The recirculation system piping is of all-welded construction and is designed and constructed to meet the requirements of the applicable ASME and ANSI codes.

The reactor recirculation system pressure boundary equipment is designed as Seismic Category I equipment. As such, it is designed to resist sufficiently the response motion for the SSE at the installed location within the supporting structure. The pump is assumed to be filled with water for the analysis. Snubbers located at the top of the motor and at the bottom of the pump casing are designed to resist the seismic reactions.

The recirculation piping, valves, and pumps are supported by hangers to avoid the use of piping expansion loops that would be required if the pumps were anchored. In addition, the recirculation loops are provided with a system of restraints designed so that reaction forces associated with the postulated pipe breaks do not jeopardize drywell integrity. This restraint system provides adequate clearance for normal thermal expansion movement of the loop. The criteria for the protection against the dynamic effects associated with a postulated pipe rupture are contained in Section 3.6B.

The recirculation system piping, valves, and pump casings are covered with thermal insulation having a total maximum heat transfer coefficient of approximately 0.4 Btu/in/hr/sq ft - °F with the system at rated operating conditions. This heat loss includes losses through joints, laps, and other openings that may exist in the insulation.

The insulation is comprised of fiberglass insulation totally encapsulated in fiberglass cloth. It is prefabricated into components for field installation. Removable insulation is provided at various locations to permit periodic inspection of the equipment.

5.4.1.4 Safety Evaluation Reactor recirculation system malfunctions that pose threats of damage to the fuel barrier are described and evaluated in Chapter 15. It is shown in Chapter 15 that none of the malfunctions result in significant fuel damage. The recirculation system has sufficient flow coastdown characteristics to maintain fuel thermal margins during abnormal operational transients.

The core flooding capability of a jet pump design plant is discussed in detail in the ECCS document filed with the NRC as a GE topical report(1). The ability to reflood the BWR core to the top of the jet pumps is shown schematically in Fig. 5.4-5 and is discussed in Reference 1.

Piping and pump design pressures for the reactor recirculation system are based on peak steam pressure in the reactor dome, appropriate pump head allowances, and the elevation head above the lowest point in the recirculation loop. Piping and related equipment pressure parts are chosen

RBS USAR Revision 27 5.4-4 in accordance with applicable codes. Use of the listed code design criteria assures that a system designed, built, and operated within design limits has an extremely low probability of failure caused by any known failure mechanism.

GE purchase specifications require that the recirculation pumps' first critical speed be at least 130 percent of operating speed. Calculation submittal was verified by GE design engineering.

GE purchase specifications require that integrity of the pump case be maintained through all transients and that the pump remain operable through all normal and upset transients. The design of the pump and motor bearings are required to be such that dynamic load capability at rated operating conditions is not exceeded during the SSE. Calculation submittal was required.

Pump overspeed occurs during the course of a LOCA due to blowdown through the broken loop pump. Design studies determined that the overspeed is not sufficient to cause destruction of the motor; consequently, no provision is made to decouple the pump from the motor for such an event.

5.4.1.5 Inspection and Testing Quality control methods were used during fabrication and assembly of the reactor recirculation system to assure that design specifications are met. Inspection and testing is carried out as described in Chapter 3. The reactor coolant system is thoroughly cleaned and flushed before fuel is loaded initially.

The reactor recirculation system is hydrostatically tested at 125 percent reactor vessel design pressure. Preoperational tests on the reactor recirculation system include checking operation of the pumps, flow control system, and gate valves and are discussed in Chapter 14.

During the startup test program, horizontal and vertical motions of the reactor recirculation system piping and equipment are observed; supports are adjusted, as necessary, to assure that components are free to move as designed. Nuclear system responses to recirculation pump trips at rated temperatures and pressure are evaluated during the startup tests, and plant power response to recirculation flow control is determined.

5.4.1.6 Bi-stable Flow Evaluation Recirculation flow fluctuations (bi-stable flow) have been observed at RBS and other BWRs, and are characterized by amplitude, frequency and flow mode duration. Bi-stable flow is a high and low flow pattern caused by alternative formation and dissipation of vortices at the recirculation header crosses and header side branches, and occurs at RBS in both Reactor Recirculation (RRS) Loops A and B.

Process data from RBS for key variables at conditions near power and rated core flow were reviewed and analyzed with bounding characteristics of observed fluctuations. The subjects investigated and the conclusions reached are provided below:

1.

For items that potentially could affect safety Effects on the following were considered: accident and transient analyses, RRS piping and reactor internals vibrations, core flow measurement system, local power measurements; and flow-biased scram measurement. Based on this review, it is

RBS USAR Revision 27 5.4-5 concluded that plant safety is not compromised and that the impacts of the observed bi-stable flow fluctuations are acceptable.

2.

Equipment and component lifetime The changes in flow are predicted to have a negligible effect on the bundles, fuel channels, RRS pump, motor and piping. The duty on the flow control valve is bounded by the design basis. There will be no increased increased erosion of the pipe wall resulting from vortex velocities in the RRS discharge-piping header.

3.

Plant operation Criteria concerning core flow runout and jet pump surveillance need not be changed. The effect of bi-stable flow on the implementation and benefits of spectral shift is negligible.

However, some minor plant operating procedure changes (listed below) have been made to accommodate the potential of bi-stable flow effects and ensure they are properly accounted for.

1.

Normal power operation procedures can be followed, since the basis for the thermal limit safety limits allows variation up to 2% in core power, as long as the average power over an 8-hour period is less than or equal to the licensed thermal power.

2.

Core flow and recirculation pump flow ratio data is taken at the same flow condition, to assure that the flow-biased scram system is porperly calibrated. If the measurements are collected at random times, the additional uncertainties due to bi-stable flow will be considered when applying setpoint methodology calculations.

5.4.2 Steam Generators (PWR)

Section 5.4.2 is not applicable to this USAR.

5.4.3 Reactor Coolant Piping The reactor coolant piping is discussed in Sections 3.9.3.1.4B and 5.4.1. The recirculation loops are shown in Fig. 5.4-1 and 5.4-2. The design characteristics are presented in Table 5.4-1.

Avoidance of stress corrosion cracking is discussed in Section 5.2.3.4.1.

5.4.4 Main Steam Line Flow Restrictors 5.4.4.1 Safety Design Bases The main steam line flow restrictors were designed:

1.

To limit the loss of coolant from the reactor vessel following a steam line rupture outside the containment to the extent that the reactor vessel water level remains high enough to provide cooling within the time required to close the MSIVs.

2.

To withstand the maximum pressure difference expected across the restrictor, following complete severance of a main steam line.

RBS USAR Revision 27 5.4-6

3.

To limit the amount of radiological release outside the drywell prior to MSIV closure.

4.

To provide trip signals for MSIV closure.

5.4.4.2 Description A main steam flow restrictor (Fig. 5.4-6) is provided for each of the four main steam lines. The restrictor is a complete assembly welded into the main steam line. It is located in the drywell.

The restrictor limits the coolant blowdown rate from the reactor vessel in the event a main steam line break occurs outside the containment to the maximum (choke) flow of 5.43 x 106 lb/hr at 1055 psig upstream pressure. The restrictor assembly consists of a venturi-type nozzle insert welded, in accordance with applicable code requirements, into the main steam line. The flow restrictor is designed and fabricated in accordance with ASME Fluid Meters, Sixth Edition, 1971.

The flow restrictor has no moving parts. Its mechanical structure can withstand the velocities and forces associated with a main steam line break. The maximum differential pressure is conservatively assumed to be 1,375 psig, the reactor vessel ASME Code limit pressure.

The ratio of venturi throat diameter to steam line inside diameter of approximately 0.512 results in a maximum pressure differential (unrecovered pressure) of about 13.57 psia at a flow rate of 3.345 x 106 lb/hr per steam line. This design limits the steam flow in a severed line to less than 200 percent of rated flow, yet it results in negligible increase in steam moisture content during normal operation. The restrictor is also used to measure steam flow to initiate closure of the MSIVs when the steam flow exceeds preselected operational limits.

5.4.4.3 Safety Evaluation In the event a main steam line should break outside the containment, the critical flow phenomenon would restrict the steam flow rate in the venturi throat to less than 200 percent of the rated value.

Prior to isolation valve closure, the total coolant losses from the vessel are not sufficient to cause core uncovering and the core is thus adequately cooled at all times.

Analysis of the steam line rupture accident (Chapter 15) shows that the core remains covered with water and that the amount of radioactive materials released to the environs through the main steam line break does not exceed the guideline values of published regulations.

Tests on a scale model determined final design and performance characteristics of the flow restrictor. The characteristics include maximum flow rate of the restrictor corresponding to the accident conditions, unrecoverable losses under normal plant operating conditions, and discharge moisture level. The tests showed that flow restriction at critical throat velocities is stable and predictable.

The steam flow restrictor is exposed to steam of about 0.2 percent moisture flowing at velocities of approximately 150 ft/sec (steam piping ID) to approximately 600 ft/sec (steam restrictor throat).

ASTM A351 (Type 304) cast stainless steel was selected for the steam flow restrictor material, because it has excellent resistance to erosion-corrosion in a high velocity steam atmosphere.

The excellent performance of stainless steel in high velocity steam appears to be due to its resistance to corrosion. A protective surface film forms on the stainless steel which prevents any surface attack and this film is not removed by the steam.

RBS USAR Revision 27 5.4-7 Hardness has no significant effect on erosion-corrosion. For example, hardened carbon steel or alloy steel erodes rapidly in applications where soft stainless steel is unaffected.

Surface finish has a minor effect on erosion-corrosion. If very rough surfaces are exposed, the protruding ridges or points erode more rapidly than a smooth surface. Experience shows that a machined or a ground surface is sufficiently smooth and that no detrimental erosion occurs.

5.4.4.4 Inspection and Testing Because the flow restrictor forms a permanent part of the main steam piping and has no moving components, no testing program is planned. Only very slow erosion occurs with time, and such a slight enlargement has no safety significance. Stainless steel resistance to erosion has been substantiated by turbine inspections at the Dresden Unit 1 facility, which have revealed no noticeable effects from erosion on the stainless steel nozzle partitions. The Dresden inlet velocities are about 300 ft/sec and the exit velocities are 600 to 900 ft/sec. However, calculations show that, even if the erosion rates are as high as 0.004 in/yr, after 40 yr of operation the increase in restrictor choked flow rate would be no more than 5-percent. A 5 percent increase in the radiological dose calculated for the postulated main steam line break accident is not significant.

5.4.5 Main Steam Isolation System 5.4.5.1 Safety Design Bases The MSIVs, individually or collectively, are designed to:

1.

Close the main steam lines within the time established by design basis accident analysis to limit the release of reactor coolant. Motive force for closure within this time is provided by the combination of compressed air and springs.

2.

Close the main steam lines slowly enough that simultaneous closure of all steam lines does not induce transients that exceed the nuclear system design limits.

3.

Close the main steam line when required, despite single failure in either valve or in the associated controls, to provide a high level of reliability for the safety function.

4.

Use separate energy sources as the motive force to close independently the redundant isolation valves in the individual steam lines.

5.

Use local stored energy (compressed air and/or springs) to close at least one isolation valve in each steam line without relying on the continuity of any variety of electrical power to furnish the motive force to achieve closure.

6.

Be able to close the steam lines, either during or after seismic loadings, to assure isolation if the nuclear system is breached.

7.

Have capability for testing, during normal operating conditions, to demonstrate that the valves are functional.

RBS USAR Revision 27 5.4-8 5.4.5.2 Description Two isolation valves are welded in a horizontal run of each of the four main steam lines; one valve is as close as possible to the inside of the drywell and the other is just outside the containment.

Fig. 5.4-7 shows an MSIV. Each is a 24-in, Y-pattern globe valve. Rated steam flow rate through each valve is 3.361 x 106 lb/hr. The main disc or poppet is attached to the lower end of the stem.

Normal steam flow tends to close the valve, and higher inlet pressure tends to hold the valve closed. The bottom end of the valve stem closes a small pressure-balancing hole in the poppet.

When the hole is open, it acts as a pilot valve to relieve differential pressure forces on the poppet.

Valve stem travel is sufficient to give flow areas past the wide open poppet greater than the seat port area. The poppet travels approximately 90 percent of the valve stem travel to close the main seat port area; approximately the last 10 percent of valve stem travel closes the pilot valve. The air cylinder actuator can open the poppet with a maximum differential pressure of 200 psi across the poppet in a direction that tends to hold the valve closed.

A 45-deg angle permits the inlet and outlet passages to be streamlined; this minimizes pressure drop during normal steam flow and helps prevent debris blockage. The pressure drop at 105 percent of rated flow is 10 psi maximum. The valve stem of each outboard MSIV penetrates the valve bonnet through a stuffing box that has two sets of replaceable packing. A lantern ring and leak-off drain are located between the two sets of packing. Live loading of stem packing has been installed on all MSIVs and stem leak-offs have been deleted on inboard MSIVs. Anti-rotation kit is installed in each MSIV to reduce flow induced rotation of the valve poppet and minimize LLRT related failures.

Attached to the upper end of the stem is an air cylinder that opens and closes the valve and a hydraulic dashpot that controls its speed. The speed is adjusted by a valve in the hydraulic return line bypassing the dashpot piston. Valve closing time is adjustable to between 3 and 10 sec.

The air cylinder is supported on the valve bonnet by actuator support and spring guide shafts.

Helical springs around the spring guide shafts close the valve in conjunction with air pressure.

The motion of the spring seat member actuates switches in the near open/near closed valve positions.

The valve is operated by pneumatic pressure and by the action of compressed springs. The control unit is attached to the air cylinder. This unit contains three types of control valves (pneumatic, ac from bus A, and ac from bus B) that open and close the main valve and exercise it at slow speed. Remote manual switches in the main control room enable the operator to operate the valves.

Operating air is supplied to the valves from the plant air system. An air accumulator between the control valve and a check valve provides backup operating air.

Each valve is designed to accommodate saturated steam at plant operating conditions, with a moisture content of approximately 0.25 percent, an oxygen content of 30 ppm, and a hydrogen content of 4 ppm. The valves are furnished in conformance with a design pressure and temperature rating in excess of plant operating conditions to accommodate plant overpressure conditions.

RBS USAR Revision 27 5.4-9 In the worst case, if the main steam line should rupture downsteam of the valve, steam flow would quickly increase to less than 200 percent of rated flow. Further increase is prevented by the venturi flow restrictor inside the containment.

During approximately the first 75 percent of closing, the valve has little effect on flow reduction, because the flow is choked by the seat opening. After the valve is approximately 75 percent closed, flow is reduced as a function of the valve curtain area versus stem lift.

The design objective for the valve is a minimum of 40-yr service at the specified operating conditions. Operating cycles (excluding exercise cycles) are estimated to be 50 cycles per year during the first year and 20 cycles per year thereafter.

In addition to minimum wall thickness required by applicable codes, a corrosion allowance of 0.120 in minimum per wetted area is added to provide for 40-yr service.

The MSIVs are designed to close and remain closed based on ambient environmental temperature, humidity, pressure, and radiological conditions found in the drywell during accident conditions. Also, the MSIVs are designed to remain closed for an additional 100 days following an accident based on drywell environmental conditions during this time. For the inboard MSIVs, the drywell environmental conditions during normal, accident, and post-accident operation are bounding with respect to the environmental conditions expected for the outboard MSIVs. The installed life of all major components, seals, gaskets, and hydraulic fluid in the actuator and controls is controlled by the plants Preventive Maintenance Program and limited life components are replaced prior to end of life.

To resist sufficiently the response motion from the SSE, the MSIV installations are designed as Seismic Category I equipment. The valve assembly is manufactured to withstand the SSE forces applied at the mass center of the extended mass of the valve operator, assuming the cylinder/spring operator is cantilevered from the valve body and the valve is located in a horizontal run of pipe. The stresses caused by horizontal and vertical seismic forces are assumed to act simultaneously. The stresses in the actuator supports caused by seismic loads are combined with the stresses caused by normal operating loads. The allowable stress for this combination of loads is based on a percentage of the allowable yield stress for the material. The parts of the MSIVs that constitute a process fluid pressure boundary are designed, fabricated, inspected, and tested as required by the ASME Section III.

5.4.5.3 Safety Evaluation In a direct cycle nuclear power plant, the reactor steam goes to the turbine and to other equipment outside the containment. Radioactive materials in the steam are released to the environs through process openings in the steam system, or escape from accidental openings. A large break in the steam system can drain the water from the reactor core faster than it is replaced by feedwater.

The analysis of a complete, sudden steam line break outside the containment is described in Chapter 15. The analysis shows that the fuel barrier is protected against loss of cooling if MSIV closure is within specified limits, including instrumentation delay to initiate valve closure after the break. The calculated radiological effects of the radioactive material assumed to be released with the steam are shown to be well within the guideline values for such an accident.

RBS USAR Revision 27 5.4-10 The shortest closing time (approximately 3 sec) of the MSIVs is also shown in Chapter 15 to be satisfactory. The switches on the valves initiate reactor scram when specific conditions (extent of valve closure, number of pipelines included, and reactor power level) are exceeded (Section 7.2.1). The pressure rise in the system from stored and decay heat may cause the nuclear system relief valves to open briefly, but the rise in fuel cladding temperature is insignificant. No fuel damage results.

The ability of this 45-deg, Y-design globe valve to close in a few seconds after a steam line break, under conditions of high pressure differentials and fluid flows with fluid mixtures ranging from mostly steam to mostly water, has been demonstrated in a series of dynamic tests. A full-size, 20-in valve was tested in a range of steam-water blowdown conditions simulating postulated accident conditions(2).

The following specified hydrostatic, leakage, and stroking tests, as a minimum, are performed by the valve manufacturer in shop tests:

1.

To verify its capability to close at settings between 3 and 10 sec (response time for full closure is set prior to plant operation at 3.0 sec minimum, 5.0 sec maximum),

each valve is tested at rated pressure (1,000 psig) and no flow. The valve is stroked several times, and the closing time is recorded. The valve is closed by springs only and by the combination of air cylinder and springs. The closing time is slightly greater when closure is by springs only.

2.

Leakage is measured with the valve seated and backseated. The specified maximum seat leakage, using cold water at design pressure, is 2 cm³/hr/in of nominal valve size. In addition, an air seat leakage test is conducted using 50 psi pressure upstream. Maximum permissible leakage is 0.1 scfh/in of nominal valve size. There must be no visible leakage from either set of stem packing at hydrostatic test pressure. The valve stem is operated a minimum of three times from the closed position to the open position, and the packing leakage still must be zero by visual examination.

3.

Each valve is hydrostatically tested in accordance with the requirements of the applicable edition and addenda of the ASME Code. During valve fabrication, extensive nondestructive tests and examinations are conducted. Tests include radiographic, liquid penetrant, or magnetic particle examinations of casting, forgings, welds, hardfacings, and bolts.

4.

The spring guides, the guiding of the spring seat member on support shafts, and rigid attachment of the seat member assure correct alignment of the actuating components. Binding of the valve poppet in the internal guides is prevented by making the poppet in the form of a cylinder longer than its diameter and by applying stem force near the bottom of the poppet.

RBS USAR Revision 27 5.4-11 After the valves are installed in the nuclear system, each valve is tested as discussed in Chapter

14.

Two isolation valves provide redundancy in each steam line so either can perform the isolation function, and either can be tested for leakage after the other is closed. The inside valve, the outside valve, and their respective control systems are separated physically.

The design of the isolation valve has been analyzed for earthquake loading. The cantilevered support of the air cylinder, hydraulic cylinder, springs, and controls is the key area. The increase in loading caused by the specified earthquake loading does not result in stresses exceeding material allowables, or prevent the valve from closing as required.

Electrical equipment that is associated with the isolation valves and operates in an accident environment is limited to the wiring, solenoid valves, and position switches on the isolation valves.

The expected pressure and temperature transients following an accident are discussed in Chapter 15.

5.4.5.4 Inspection and Testing The MSIVs can be functionally tested for operability during plant operation and refueling outages.

The test provisions are listed as follows. During a refueling outage, the MSIVs can be functionally tested, leak-tested, and visually inspected.

The MSIVs can be tested and exercised individually to the 85 percent open position, because the valves still pass rated steam flow when 85 percent open.

The MSIVs can also be tested and exercised individually to the fully closed position if reactor power is reduced sufficiently to avoid scram from reactor overpressure or high flow through the other steam line flow restrictors. In addition, reactor power is administratively limited to 75% of rated should closure of a single MSIV be required. This limit preserves the integrity of the remaining open MSIVs by preventing the possibility of high flow induced vibration. Reactor operation at greater than 75% of rated with one MSIV closed will cause higher than rated steam flow to pass through the remaining 3 live steam lines. Higher than rated steam flow through the remaining operable steam lines could cause excessive flow induced vibration and potentially damage the MSIVs.

Leakage from the valve stem packing becomes suspect during reactor operation from measurements of leakage into the drywell, or from observations or similar measurements in the steam tunnel. During shutdown while the nuclear system is pressurized, the leak rate through the inner packing can be measured by collecting and timing the leakage. Leakage through the inner packing would be collected from the packing drain line.

The leak rate through the pipeline valve seats (pilot and poppet seats) can be measured accurately during shutdown by the following procedure:

1.

With the reactor between approximately 125°F and 200°F, and normal water level and decay heat being removed by the RHR system in the shutdown cooling mode, all MSIVs are closed utilizing both spring force and air pressure on the operating cylinder.

RBS USAR Revision 27 5.4-12

2.

Nitrogen is introduced into the reactor vessel above normal water level and into the connecting main steam lines, and pressure is raised to 20-30 psig. An alternate means of pressurizing the upstream side of the inside isolation valve is to utilize a steam line plug capable of accepting the 20-30 psig pressure acting in a direction opposite the hydrostatic pressure of the fully flooded reactor vessel.

3.

A pressure gauge and flow meter are connected to the test tap between each set of MSIVs. Pressure is held below 1 psig, and flow out of the space between each set of valves is measured to establish the leak rate of the inside isolation valve.

4.

To leak-check the outer isolation valve, the reactor and connecting steam lines are flooded to a water level that gives a hydrostatic head at the inlet to the inner isolation valves slightly higher than the pneumatic test pressure to be applied between the valves. This assures essentially zero leakage through the inner valves. If necessary to achieve the desired water pressure at the inlet to the inner isolation valves, gas from a suitable pneumatic supply is introduced into the reactor vessel top head.

Nitrogen pressure (20-30 psig) is then applied to the space between the isolation valves. The stem packing is checked for leaktightness. Once any detectable packing leakage has been corrected, the seat leakage test is conducted by shutting off the pressurizing gas and observing any pressure decay. The volume between the closed valves is accurately known. Corrections for temperature variation during the test period are made, if necessary, to obtain the required accuracy. Pressure and temperature are recorded over a long enough period to obtain meaningful data.

An alternate means of leak-testing the outer isolation valve is to utilize the previously noted steam line plug and to determine leakage by pressure decay or by inflow of the test medium to maintain the specific test pressure.

During prestartup tests following test following a refueling outage, the valves receive the same reactor pressure vessel inservice leakage test that is imposed on the primary system.

Such a test and leakage measurement program ensures that the valves are operating correctly and that a leakage trend is detected.

5.4.6 Reactor Core Isolation Cooling System 5.4.6.1 Design Basis The RCIC system is a safety system which consists of a turbine, pump, piping, valves, accessories, and instrumentation designed to assure that sufficient reactor water inventory is maintained in the reactor vessel to permit adequate core cooling to take place. This prevents reactor fuel overheating during the following conditions:

1.

Should the vessel be isolated and maintained in the hot standby condition

2.

Should the vessel be isolated and accompanied by loss of coolant flow from the reactor feedwater system

3.

Should a complete plant shutdown under conditions of loss of normal feedwater system be started before the reactor is depressurized to a level where the shutdown coolant system can be placed into operation

RBS USAR Revision 27 5.4-13

4.

Deleted.

Following a reactor scram, steam generation continues at a reduced rate due to the core fission product decay heat. At this time, the turbine bypass system diverts the steam to the main condenser, and the feedwater system supplies the makeup water required to maintain reactor vessel inventory.

In the event the reactor vessel is isolated and the feedwater supply unavailable, relief valves are provided to automatically (or remote manually) maintain vessel pressure within desirable limits.

The water level in the reactor vessel drops due to continued steam generation by decay heat.

Upon reaching a predetermined low level, the RCIC system is initiated automatically. The turbine driven pump supplies demineralized makeup water from the condensate storage tank to the reactor vessel; an alternate source of water is available from the suppression pool. The turbine is driven with a portion of the decay heat steam from the reactor vessel, and exhausts to the suppression pool. Suppression pool water is not maintained demineralized and is only used in the event all sources of demineralized water have been exhausted. The Upper Containment Pool also provides an alternate source of water and is only used during a FLEX Beyond Design Basis External Event.

The RCIC pump is located in the auxiliary building sufficiently below the water level in the suppression pool to assure a flooded pump suction and to meet pump NPSH requirements with the containment at atmospheric pressure and the suction strainers 50 percent plugged. (The design pressure drop at this condition is 1.0 psi.)

During RCIC operation, the suppression pool acts as the heat sink for steam generated by reactor decay heat. This results in a rise in pool water temperature. Heat exchangers shown in the residual heat removal (RHR) system are used to maintain pool water temperature within acceptable limits by cooling the pool water directly.

The RCIC system is equipped with a discharge line fill pump that operates to maintain the pump discharge line in a filled condition. Keeping the discharge line filled reduces the lag time between pump startup and attainment of full flow to the RPV. Additionally, its operation eliminates the possibility of RCIC pumps discharging into a dry pipe and minimizes water hammer effects. The fill pump is classified as Seismic Category I and Safety Class 2. The pump motor is Class 1E and is powered from a Class 1E source. Indication of pump operating status is provided in the main control room. Low discharge line pressure is also indicated in the main control room.

5.4.6.1.1 Residual Heat and Isolation 5.4.6.1.1.1 Residual Heat The RCIC system initiates and discharges, within 30 sec, a constant flow of 600 gpm into the reactor vessel over a specified pressure range. The RCIC water discharged into the reactor vessel varies between a temperature of 40°F up to and including a temperature of 140°F. The cool RCIC water does the following:

1.

Removes reactor residual heat

2.

Replenishes reactor vessel inventory.

RBS USAR Revision 27 5.4-14 Redundantly, the HPCS system performs the same function, hence, providing single failure protection. Both systems use different electrical power sources of high reliability, which permit operation with either onsite power or offsite power. Additionally, the RHR system performs a residual heat removal function.

The RCIC system design includes interfaces with redundant leak detection devices, namely:

1.

A high pressure drop across a flow device in the steam supply line equivalent to 300 percent of the steady state steam flow at 1,192 psia.

2.

A high area temperature, utilizing temperature switches as described in the leak detection system. High area temperature is alarmed in the main control room.

3.

A low reactor pressure of 50 psig minimum.

4.

A high pressure between the turbine exhaust rupture diaphragms.

These devices, activated by the redundant power supplies, automatically isolate the steam supply to the RCIC turbine.

Other isolation bases are defined in the following section. HPCS provides redundancy for RCIC should RCIC become isolated, hence, providing single failure protection.

5.4.6.1.1.2 Isolation Isolation valve arrangements include the following:

1.

The RCIC steam line which branches off one of the main steam lines between the reactor vessel and the MSIV has two automatic motor-operated isolation valves.

One is located inside and the other outside the drywell. An automatic motor-operated inboard RCIC isolation bypass valve is used. The isolation signals noted earlier close these valves.

2.

The abandoned RCIC pump discharge line penetrates the containment; however, the line is capped in the Auxiliary building and capped at the refueling cavity floor.

3.

The RCIC turbine exhaust line vacuum breaker system line has two automatic motor-operated valves and two check valves. This line runs between the suppression pool air space and the turbine exhaust line downstream of the exhaust line check valve. Positive isolation is automatic via a combination of low reactor pressure and high drywell pressure.

The vacuum breaker valve complex is placed outside primary containment due to a more desirable environment. In addition, the valves are readily accessible for maintenance and testing.

4.

The RCIC pump suction line, minimum flow pump discharge line, and turbine exhaust line all penetrate the containment and are submerged in the suppression pool. The isolation valves for these lines are all outside the containment and require remote-manual operation from the main control room for isolation.

RBS USAR Revision 27 5.4-15 5.4.6.1.2 Reliability, Operability, and Manual Operation 5.4.6.1.2.1 Reliability and Operability The RCIC system, as noted in Table 3.2-1, is designed commensurate with the safety importance of the system and its equipment. Each component is individually tested to confirm compliance with system requirements. The system as a whole is tested during both the startup and pre-operational phases of the plant to set a base mark for system reliability. To confirm that the system maintains this mark, functional and operability testing is performed at predetermined intervals throughout the life of the reactor plant (Section 5.4.6.2.4).

A design flow functional test of the RCIC system may be performed during normal plant operation by drawing suction from the condensate storage tank and discharging through a full flow test return line to the condensate storage tank. The injection valve remains closed during the test, and reactor operation remains undisturbed. All components of the RCIC system are capable of individual functional testing during normal plant operation. System control provides automatic return from test to operating mode if system initiation is required. There are three exceptions: 1)

Auto/manual initiation on the flow controller is required for operator flexibility during system operation. 2) Closure of either or both of the steam inboard/outboard isolation valves requires operator action to properly sequence their opening. An alarm sounds when either of these valves leaves the fully open position. 3) Other bypassed or otherwise deliberately rendered inoperable parts of the system are automatically indicated in the main control room at the system level.

5.4.6.1.2.2 Manual Operation In addition to the automatic operational features, provisions are included for remote-manual startup, operation, and shutdown of the RCIC system, provided initiation or shutdown signals do not exist.

5.4.6.1.3 Loss of Offsite Power The RCIC system power is derived from a highly reliable source that is maintained by either onsite or offsite power (Section 5.4.6.1.1.1).

5.4.6.1.4 Physical Damage The system is designed to the requirements of Table 3.2-1 commensurate with the safety importance of the system and its equipment. The RCIC is physically separate and utilizes different divisional power (and separate electrical routings) than its redundant system as discussed in Sections 5.4.6.1.1.1 and 5.4.6.2.4.

Occasionally the steam isolation valves are temporarily closed for maintenance; the main steam drain system, in conjunction with administrative control and specific operating procedures, precludes the possibility of thermal shock or water hammer to the steamline, valve seats, and discs. Operating procedures provide for opening the outboard isolation valve allowing the condensate to drain through the steam supply drain system, warming the steam line by throttling open the warmup valve located on a pipeline bypassing the inboard isolation valve, and then opening the inboard isolation valve.

Water hammer effects at the turbine exhaust are limited by existing design features which prevent water from accumulating in the exhaust line. A vacuum breaker system is installed close to the

RBS USAR Revision 27 5.4-16 RCIC turbine exhaust line-suppression pool penetration to avoid syphoning water from the suppression pool into the exhaust line as steam in the line condenses during and after turbine operation. The vacuum breaker line runs from the suppression pool air volume to the RCIC exhaust line through two normally open, motor-operated globe valves and two piston check valves arranged to allow air flow into the exhaust lines, precluding steam flow to the suppression pool air volume. In addition, the turbine exhaust line includes a check valve to supplement the vacuum breaker system in preventing water from accumulating in the exhaust line. Under certain limited operating conditions, such as during brief RCIC turbine operations when the exhaust line is not able to achieve normal operating temperatures, vacuum breaker system action may not prevent siphoning of water into the exhaust line. However, the check valve will close upon isolation of steam flow to the RCIC turbine thus assisting the vacuum breaker system in preventing water from accumulating in the exhaust line.

5.4.6.1.5 Environment The system operates for the time intervals and the environmental conditions specified in Section 3.11.

5.4.6.2 System Design 5.4.6.2.1 General 5.4.6.2.1.1 Description A summary description of the RCIC system is presented in Section 5.4.6.1, which defines in general the system functions and components. The detailed description of the system, its components, and operation is presented in the following sections.

5.4.6.2.1.2 Diagrams The following diagrams are included for the RCIC systems:

1.

A schematic piping and instrumentation diagram (Fig. 5.4-8) shows all components, piping, points where interface system and subsystems tie together, and instrumentation and controls associated with subsystem and component actuation.

2.

A diagram of the RCIC turbine exhaust line sparger is shown in Fig. 5.4-9a. The sparger is mounted vertically and is fabricated from 12-in nominal OD, 150-lb stainless steel pipe. Holes are drilled in the pipe as shown to provide an even distribution of steam being discharged and condensed in the suppression pool.

5.4.6.2.1.3 Interlocks The following defines the various electrical interlocks:

1.

There is one key-locked valve (F068) and two key-locked resets (the isolation resets).

2.

F031's limit switch activates when fully open and closes F010, F022, and F059.

RBS USAR Revision 27 5.4-17

3.

F068's limit switch activates when fully open and clears F045 permissive so F045 could open. Reactor vessel high water level closes F045.

4.

F045's limit switch activates when F045 is not fully closed, permits F013 to open, energizes a 15-sec time delay for low pump suction pressure trip, and also initiates a startup ramp function. This ramp resets each time F045 is closed.

5.

F045's limit switch activates when fully closed, permits F004, F005, F025, and F026 to open, and closes F013 and F019.

6.

The turbine trip throttle valve (part of C002) limit switch activates when fully closed and closes F013 and F019.

7.

The combined pressure switches at reactor low pressure and high drywell pressure when activated close F077 and F078.

8.

High turbine exhaust pressure, low pump suction pressure, or an isolation signal actuates and closes the turbine trip throttle valve. When signal is cleared, the trip throttle valve must be reset from the main control room.

9.

A maximum Turbine overspeed of 120 percent of the original maximum rated turbine speed trips the mechanical trip at the turbine which closes the trip throttle valve. The mechanical trip mechanism is manually reset at the turbine.

10.

An isolation signal closes F031, F063, F064, F076, and other valves as noted in items 6 and 8.

11.

An initiation signal opens F010 if closed, F013 and F045; starts gland seal system; and closes F022 and F059 if open.

12.

High and low inlet RCIC steam line drain pot levels, respectively, open and close F054.

13.

The combined signal of low flow plus sufficient pump discharge pressure opens F019. High flow closes F019 (see items 5 and 6).

5.4.6.2.2 Equipment and Component Description 5.4.6.2.2.1 Design Conditions The RCIC components are:

1.

One 100 percent capacity turbine and accessories

2.

One 100 percent capacity pump assembly and accessories

3.

Piping, valves, and instrumentation for:

a.

Steam supply to the turbine

b.

DELETED

RBS USAR Revision 27 5.4-18

c.

Turbine exhaust to the suppression pool

d.

Makeup supply from the condensate storage tank to the pump suction

e.

Makeup supply from the suppression pool to the pump suction

f.

DELETED

g.

Pump discharge to the feedwater system, including a test line to the condensate storage tank, a minimum flow bypass line to the suppression pool, and a coolant water supply to accessory equipment.

The basis for the design conditions is ASME Section III, Nuclear Power Plant Components.

5.4.6.2.2.2 Design Parameters Design parameters for the RCIC system components are listed as follows (see Fig. 5.4-8 for cross-reference of component numbers):

1. RCIC Pump Operation (C001)

Flow Rate Injection flow - 600 gpm cooling water flow 25 gpm total pump discharge Flow - 625 gpm (includes no margin for pump wear)

Water temperature 40°F to 140°F range NPSH 21 ft minimum Developed head 3045 ft @ 1246 psia reactor pressure 550 ft @ 165 psia reactor pressure BHP, not to exceed 725 hp @ 3045 ft developed head 125 hp @ 550 ft developed head Design pressure 1,525 psia Design ambient 60°F to 127°F temperature

RBS USAR Revision 27 5.4-19

2. RCIC Turbine Operation (C002)

H.P. Condition L.P.Condition (psia)

(psia)

Reactor pressure (sat. temp.)

1,246 165 Steam inlet pressure 1,231 min 150 min Turbine exhaust Pressure 25 max 25 max Design inlet pressure 1,250 psig at saturated temperature Design exhaust 165 psig at saturated pressure temperature

3. RCIC Orifice Sizing Minimum flow orifice Sized for 75-95 gpm with MO-F019 (D005) fully open and with the turbine/pump at maximum speed Test return orifice Sized with piping arrangement to (D006) simulate pump discharge pressure required when the RCIC system is injecting design flow with the reactor vessel pressure at 165 psia. Valve E51-F022 must be throttled for system testing at a simulated 1045 psia reactor pressure Leakoff orifices Sized for 1/8-in diameter minimum, (D008, D010) 3/16-in diameter maximum Steam exhaust drain Sized for 1/8-in diameter minimum, pot orifice 3/16-in diameter maximum (D004)

Subsystem fill pump Sized for minimum water leg pump minimum flow orifice flow and located in a pipe run of (D011) sufficient length to act as a heat sink, thus permitting continuous water leg pump operation without pump over-heating Flow Element (N001)

Flow at full meter differential pressure 800 gpm Full meter differential pressure 340 in water at 68°F Normal temperature 40°F to 170°F Orifice design

RBS USAR Revision 27 5.4-20 pressure/temperature 1,525 psig/140°F Maximum unrecoverable loss at normal flow 4.5 psi Installed accuracy

+/- 1% at normal flow and normal temperature Cooling loop back Sized orifice to maintain 16-25 gpm pressure orifice to lube oil cooler based on pump (D012) suction line pressure varying due to condensate storage tank level to minimum NPSH value Accuracy Combined accuracy of flow element N001, flow transmitter N003 and flow indicator R600

+/- 2.5% maximum Combined accuracy of pressure Transmitter N004, and Pressure indicator R001

+/- 2.5% maximum

4. Valve Operation Requirements The maximum expected differential pressure (MEDP) for each motor-operated valve (MOV) is determined under the River Bend Station Generic Letter 89-10 program by evaluating system operating conditions and required functions.

Steam supply valve Open against maximum expected (MPL No. E51-MOVF045) differential pressure within 15 seconds. Close against maximum expected differential pressure within 30 seconds.

Pump discharge valve Open against maximum expected (MPL No. E51-MOVF013) differential pressure within 27 seconds Pump minimum flow Open or close against maximum Bypass Valve expected differential pressure (MPL No. E51-MOVF019) within 6 seconds RHR and RCIC Steam Close against maximum expected Supply Isolation Valve differential pressure within (MPL No. E51-MOVF063 29 seconds. Close within Technical

& F064)

Requirements Manual time limit for containment isolation.

Cooling water pressure Self-contained downstream sensing control valve (MPL No.

control valve capable of maintaining E51-PCVF015) constant down-stream pressure of 125 psia. Diaphragm of pressure control valve must be of elastomer type.

Pump suction relief 90 psig relief setting; 10 gpm at

RBS USAR Revision 27 5.4-21 Valve (MPL No 10% accumulation E51-RVF017)

Cooling water relief Sized to prevent over-pressurizing Valve (MPL No.

piping, valves, and equipment in the E51-RVF018) coolant loop in event of failure of pressure control valve F015 Pump test return valve Capable of throttling control (MPL No. E51-MOVF022) against differential pressures up to and closure against the maximum expected differential pressure.

Pump suction valve, Open or close against the maximum suppression pool expected differential pressure.

(MPL No. E51-MOVF031)

Close within Technical Requirements Manual Time Limit for containment isolation.

Turbine exhaust Open or close against maximum isolation valve expected differential pressure at (MPL No. E51-MOVF068) temperature of 330°F. Physically located in the line on a horizontal run, as close to the containment as practical.

Isolation valve, Open or close against maximum steam warmup line expected differential pressure with (MPL No. E51-MOVF076) minimum travel of 4 in/min. Close within Technical Requirements Manual time limit for containment isolation.

Vacuum breaker Close against maximum expected isolation valves differential pressure at a minimum (MPL No. E51-MOVF077 rate of 4 in/min. Close within

& F078)

Technical Requirements Manual time limit for containment isolation.

Vacuum breaker check Full flow and open with a minimum Valves (MPL No.

pressure drop (less than 0.5 psi)

E51-VF079 & F081) across them.

Steam exhaust drain pot system isolation valves (MPL No. E51-AOVF004 &

F005)

Open or close against a differential pressure of 75 psi. Operate only when RCIC system is shut down allowing draining to reactor building equipment drain system.

Condensate storage tank isolation valve (MPL No.

E51-MOVF010)

Open or close against a maximum expected differential pressure. Isolates the condensate storage tank so suction may be drawn from the suppression pool.

RBS USAR Revision 27 5.4-22 Steam inlet drain pot system isolation valves (MPL No.

E51-AOVF025 & F026)

Open or close against a differential pressure of 1231 psi. Allows for drainage of the steam inlet drain pot.

Steam inlet trap bypass valve (MPL No. E51-AOVF054)

Open or close against a differential pressure of 1231 psi. Bypasses restriction orifice RO 158.

Pump test return valve (MPL No. E51-MOVF059)

Close against maximum expected differential pressure. Allows water to be returned to the condensate storage tank during RCIC system test.

Thermal relief valve (MPL No. E51-RVF090) 1,525 psig relief setting; size as required to protect the discharge line between valves E51-F022 and E51-F059 from thermal expansion due to abnormal ambient temperature of 212°F and water at 40°F.

5. Rupture Disc Assemblies (D001 & D002)

Utilized for turbine casing protection; includes a mated vacuum support to prevent rupture disc reversing under vacuum conditions Rupture pressure flow capacity 150 psig +/- 5% at 212°F 75,000 lb/hr at 165 psig

6. Instrumentation For instruments and control definition refer to Chapter 7.

7. Condensate Storage Requirements Total reserve storage for RCIC and HPCS systems is a maximum of 125,000 gal.

8. Piping RCIC Water Temperature The maximum water temperature range for continuous system operation shall not exceed 140°F. However, due to potential short-term operation at higher temperatures, piping expansion calculations were based on 170°F.

9. Turbine Exhaust Vertical Reaction Force The turbine exhaust sparger is capable of withstanding a vertical pressure unbalance of 20 psi. Pressure unbalance is due to turbine steam discharge below the suppression pool water level.

10. Ambient Conditions Temperature Relative Humidity

RBS USAR Revision 27 5.4-23 Normal plant operation 60°F-122°F 20-90%

Isolation conditions 150°F-210°F 100%

11. Suction Strainer Sizing The suppression pool suction strainer shall be sized so that:

a. Pump NPSH requirements are satisified when strainer is 50% plugged

b.

Particles over 3/32-in diameter are restrained from passage into the pump (refers to GE-supplied components).

5.4.6.2.3 Applicable Codes and Classifications The RCIC system components within the drywell up to and including the outer isolation valve are designed in accordance with ASME Code,Section III, Class 1, Nuclear Power Plant Components.

The RCIC system is also designed as Seismic Category I.

The RCIC system component classifications and those for the condensate storage system are given in Table 3.2-1.

5.4.6.2.4 System Reliability Considerations To assure that the RCIC operates when necessary and in time to prevent inadequate core cooling, the power supply for the system is taken from immediately available energy sources of high reliability. Added assurance is given in the capability for periodic testing during station operation.

Evaluation of reliability of the instrumentation for the RCIC shows that no failure of a single initiating sensor either prevents or falsely starts the system.

The most limiting potential operating condition for the RCIC pump occurs when the pump takes suction from the suppression pool and operates at its maximum rated flow of 645 gpm. This represents the limiting operating condition because of the minimum static suction head (16.5 ft) and the maximum temperature/vapor pressure (170°F/6.0 psia) of the water that might exist during RCIC system operation. The NPSH margin during this condition is 1.8 ft (NPSH available

= 22.8 ft, NPSH required = 21 ft). The RCIC system meets the requirements of Regulatory Guide 1.1 since the calculation of NPSH available takes no credit for increased containment atmospheric pressure accompanied by a LOCA and is computed using the maximum anticipated water temperature of 170°F.

In order to assure HPCS or RCIC availability for the operational events noted previously, certain design considerations are utilized in design of both systems.

Physical Independence

RBS USAR Revision 27 5.4-24 The two systems are located in separate areas of the auxiliary building. Piping runs are separated, and the water delivered from each system enters the reactor vessel via different nozzles.

Prime Mover Diversity and Independence Prime mover independence is achieved by using a steam turbine to drive the RCIC pump and an electric motor driven pump for the HPCS system. The HPCS motor is supplied from either normal ac power or a separate diesel generator.

Control Independence Control independence is secured by using different battery systems to provide control power to each unit. Separate detection initiation logics are also used for each system.

Environmental Independence Both systems are designed to meet Safety Class 1 or Safety Class 2 requirements, as applicable.

Environment in the equipment rooms is maintained by separate auxiliary systems.

Periodic Testing A design flow functional test of the RCIC can be performed during plant operation by taking suction from the condensate storage tank and discharging through the full flow test return line back to the condensate storage tank. The injection valve remains closed during the test, and reactor operation is undisturbed. All components of the RCIC system are capable of individual functional testing during normal plant operation. Control system design provides automatic return from test to operating mode if system initiation is required. The three exceptions are as follows:

1.

The auto/manual station on the flow controller. This feature is required for operator flexibility during system operation.

2.

Steam inboard/outboard isolation valves. Closure of either or both of these valves requires operator action to properly sequence their opening. An alarm sounds when either of these valves leaves the fully open position.

3.

Bypassed or other deliberately rendered inoperable parts of the system are automatically indicated in the main control room.

Additionally, all components of the RCIC system are capable of individual functional testing during normal plant operation.

General Periodic inspections and maintenance of the turbine-pump unit are conducted in accordance with manufacturer's instructions. Valve position indication and instrumentation alarms are displayed in the main control room.

5.4.6.2.5 System Operation Various modes of RCIC are initiated as defined in the following paragraphs.

RBS USAR Revision 27 5.4-25 Automatic startup of the RCIC system due to an initiation signal from reactor low water level requires no operator action. To permit this automatic operation, the operator must verify that steps have been taken to prepare the system for the standby mode.

The test loop operating mode is manually initiated by the operator.

The most limiting single failure with the RCIC system and its HPCS backup system is the failure of HPCS. With an HPCS failure, the capacity of the RCIC system is adequate to maintain reactor water level automatically if it has been placed in the standby mode, or through manual initiation.

If the RCIC capacity is inadequate, the operator may also initiate the ADS system described in Section 6.3.2.

5.4.6.3 Performance Evaluation The analytical methods and assumptions in evaluating the RCIC system are presented in Chapter 15 and Appendix 15A. The RCIC system provides the flows required from the analysis within a 30-sec interval based upon considerations noted in Section 5.4.6.2.4.

5.4.6.4 Preoperational Testing The preoperational and initial startup test program for the RCIC system is presented in Chapter

14.

5.4.7 Residual Heat Removal System 5.4.7.1 Design Bases The RHR system is composed of three independent loops. Each loop contains its own motor-driven pump, piping, valves, instrumentation, and controls. Each loop has a suction source from the suppression pool and is capable of discharging water to the reactor vessel via a separate nozzle, or back to the suppression pool via a full-flow test line. In addition, the A and B loops have heat exchangers which are cooled by the normal or standby service water. Loops A and B can also take suction from the reactor recirculation system suction or the fuel pool cooling and cleanup system, and can discharge into the reactor via the feedwater line or fuel pool cooling discharge. Loop C can take suction from the reactor recirculation system for testing.

Loop C also interfaces with the Suppression Pool Cleanup, Cooling, and Alternate Decay Heat Removal system. The Suppression Pool Cleanup, Cooling, and Alternate Decay Heat Removal system is discussed in Section 9.3.8.

5.4.7.1.1 Functional Design Basis The RHR system has three operating modes, each of which has its own functional requirements.

Each mode is discussed separately to provide clarity.

5.4.7.1.1.1 Residual Heat Removal Mode (Shutdown Cooling Mode)

The functional design basis of the shutdown cooling mode is to have the capability to remove decay and sensible heat from the reactor primary system so that the reactor outlet temperature is reduced to 125°F, 20 hr after the control rods have been inserted, to permit refueling when the

RBS USAR Revision 27 5.4-26 service water temperature is 85°F, the core is "mature," and the tubes are completely fouled (see Section 5.4.7.2.2 for exchanger design details). The capacity of the heat exchangers is such that the time to reduce the vessel outlet water temperature to 212°F corresponds to a cooldown rate of 100°F per hr with both loops in service. However, the flushing operation associated with shutdown prevents attaining 212°F coolant temperature at the minimum time.

If 2 hr are used for flushing, the minimum time required to reduce vessel coolant temperature to 125°F (at 50° per hour cooldown rate) is depicted by Fig. 5.4-10.

The design basis for the most limiting single failure for the RHR system (shutdown cooling mode) is that one exchanger loop is lost and the plant is then shutdown using the capacity of a single RHR heat exchanger and related service water capability. Fig. 5.4-11 shows the nominal time required to reduce vessel coolant temperature to 212°F using one RHR heat exchanger.

RHR lines in the upper containment pool are used in conjunction with the shutdown cooling mode of the RHR during refueling operations when the reactor pressure vessel head is removed. In this alignment, reactor water is pumped from one of the recirculation loops through the RHR system heat exchangers and back to the RPV through the RHR flow distribution spargers located in the upper containment pool. This flow path provides nonlateral flow loads on the fuel during fuel movement. Operation of the RHR in this alignment is initiated and terminated by the operator.

RHR loop C piping provides the primary interface with the Suppression Pool Cleanup, Cooling, and Alternate Decay Heat Removal (SPC) system. This interface provides a suction and return path to the suppression pool during normal power operation, and to the reactor during plant shutdowns. ADHR/SPC System can be lined-up simultaneously with one of the loops of the RHR for the shutdown cooling during refueling outages. Automatic, safety-related isolation valves, RHS-AOV62, AOV-63, and AOV-64, are provided with automatic closure signals as described in Section 6.2.4.3.7. These valves are also provided with automatic closure signals on low suppression pool level and low containment fuel storage pool level. Interlocks are provided between E12-VF067, E12-MOV021, and E12-MOVF105 to prevent draining the vessel to the suppression pool.

5.4.7.1.1.2 Low Pressure Coolant Injection Mode The functional design basis for the LPCI mode is to pump a total of 5,050 gpm of water per loop using the separate pump loops from the suppression pool into the core region of the vessel, when the vessel pressure is 20 psi over drywell pressure. Injection flow commences at 225 psi vessel pressure above drywell pressure.

The initiating signals are: low vessel water level or high drywell pressure. The pumps attain rated speed in 27 sec and injection valves fully open in 37 sec.

5.4.7.1.1.3 Suppression Pool Cooling Mode The functional design basis for the suppression pool cooling mode is that it has the capacity to ensure that the suppression pool temperature immediately after a LOCA event with subsequent blowdown through either the SRVs or the vents does not exceed 170°F and anytime after the blowdown does not exceed 185°F.

RBS USAR Revision 27 5.4-27 5.4.7.1.1.4 DELETED 5.4.7.1.2 Design Basis for Isolation of RHR System from Reactor Coolant System The RHR suction lines incorporate two motor-operated valves as the low pressure/high pressure interface. These valves are provided with interlocks that prevent the operator from opening these valves when reactor pressure is high. The trip unit set points are set at 135 psig, as compared to a pressure rating of 200 psig for the suction piping downstream of these valves. The two isolation valves in the suction line have divisionally separated controls. These valves are manually controlled, pressure-interlocked valves. Each valve control circuit has two pressure interlocks, either of which prevents the valve from being opened. A failure of all four transmitter trip unit channels is required to permit operation of both valves when reactor pressure is high.

The interlocks are controlled by analog pressure transmitters, which measure reactor coolant pressure and transmit a signal proportional to the pressure to a solid-state trip unit and a visual indicator. This design permits on-line monitoring of the transmitter outputs on analog indicators in the main control room, so that cross comparison of the output values can be made between channels and other main control room pressure indicators. Technical Specifications require that a channel check of these systems be made every 12 hr. The trip units are located in the main control room for ease of calibration and testing.

In addition to these automatic protection features, administrative controls do not permit placing the RHR system in the shutdown cooling mode until reactor pressure has been reduced to less than 135 psig. The pressure indications used for determining reactor pressure when placing the system in the shutdown cooling mode are located on the main control panel and are different from those used in the overpressure protection trip system.

In addition, River Bend Station has incorporated LRG II position 2-ICSB concerning low pressure ECCS injection lines and modified the existing relay interlock circuitry. This modification removed the LOCA signal bypass. Thus, the MOV will be interlocked shut for all reactor pressures greater than ECCS design pressure, given a postulated failure of the check valve. (See Section 7.3.1 for additional details.)

The low pressure portions of the RHR system are isolated from full reactor pressure whenever the primary system pressure is above the RHR system design pressure (see Section 5.4.7.1.3 for further details). In addition, automatic isolation may occur for reasons of vessel water inventory retention which is unrelated to line pressure rating (see Section 5.2.5 for an explanation of the leak detection system and the isolation signals).

The RHR pumps are protected against damage from a closed discharge valve by means of automatic minimum flow valves, which open on low main line flow and close on high main line flow.

Possible operator errors during plant startup and cooldown when the RHR system is not isolated from the RCS have been minimized through the implementation of the following design bases:

1.

The low-pressure suction piping is protected from inadvertent opening of valves F008 and F009 by pressure interlocks on these valves.

RBS USAR Revision 27 5.4-28

2.

The probability of draining some reactor water to the suppression pool is reduced by the existence of an interlock on valve F006 which prevents its opening unless valve F004 is closed.

3.

The pump cannot be started unless a suction path is open.

5.4.7.1.3 Design Basis for Pressure Relief Capacity The relief valves in the RHR system are sized on one of three bases:

1.

Thermal relief only

2.

Valve bypass leakage only

3.

Transients are treated by item 1, and item 2 has resulted from an excessive leaking past isolation valves. E12-F036 was originally sized to maintain upstream pressure at 75 psig and 10 percent accumulation with both PCV E12-F065A and B failed open; however with disabling of the steam condensing mode of operation of the RHR system, this valve now only serves as over pressure protection for that isolated section of piping. RHS-RV67, E12-F005, F017, F025, F030, and F101 are set at the design pressure specified in the process data drawing plus 10 percent accumulation.

Redundant interlocks prevent opening valves to the low pressure suction piping when the reactor pressure is above the shutdown range. These same interlocks initiate valve closure on increasing reactor pressure.

In addition, a high pressure check valve closes to prevent reverse flow if the pressure should increase. Relief valves in the discharge piping are sized to account for leakage past the check valve.

5.4.7.1.4 Design Basis with Respect to General Design Criterion 5 The RHR system for this unit does not share equipment or structures with any other nuclear unit.

5.4.7.1.5 Design Basis for Reliability and Operability The design basis for the shutdown cooling mode of the RHR system is that this mode is controlled by the operator from the main control room. The only operations performed outside the main control room for a normal shutdown is manual operation of local flushing water admission valves, which are the means of providing clean water to the shutdown portions of the RHR system.

Two separate shutdown cooling loops are provided, and although both loops are required for shutdown under normal circumstances, the reactor coolant can be brought to 212°F in less than 20 hr with only one loop in operation. With the exception of the shutdown suction, and shutdown return, the entire RHR system is part of the ECCS and containment cooling system, and is therefore required to be designed with redundancy, flooding protection, piping protection, power separation, etc, required of such systems (see Section 6.3 for an explanation of the design bases for the ECCS). Shutdown suction and discharge valves are required to be powered from both offsite and standby emergency power for purposes of isolation and shutdown following a loss of offsite power. In the event either of the two shutdown supply valves fail to operate, an operator is sent out to operate the valve manually. If this is not feasible and the plant must be shut down

RBS USAR Revision 27 5.4-29 as soon as possible, the alternate shutdown method is employed. In this procedure, water is drawn from the suppression pool, pumped through the RHR heat exchanger and delivered into the shroud region of the reactor. The vessel water is allowed to overflow the steam lines and discharges back to the suppression pool via the ADS valve discharge lines. A complete loop is thereby established, with sensible and decay heat being transferred to the pool and then to service water via the RHR heat exchanger. A pressure drop calculation has been performed which confirms that both A and B loops of RHR are capable of performing alternate shutdown cooling operations under conditions postulating worst case flow path hydraulic resistance. The time required to achieve cold shutdown using the alternate shutdown cooling mode is less than the time to achieve cold shutdown using the normal shutdown cooling mode of the RHR system.

5.4.7.1.6 Design Basis for Protection from Physical Damage Pumps A, B, and C are physically separated. Each is housed in a separate room. Rooms A and B contain their respective pumps and two RHR heat exchangers. Room C contains Pump C and the RHR discharge line fill pump.

The design basis for protection from physical damage, such as internally generated missiles, pipe break, and seismic effects, is discussed in Sections 3.5, 3.6, and 3.7, respectively.

5.4.7.2 Systems Design 5.4.7.2.1 System Diagrams All components of the RHR system are shown in Fig. 5.4-12. A description of the controls and instrumentation is presented in Section 7.3.1.1.

The functional control diagram (FCD) for the RHR system is provided in Section 7.

Interlocks are provided: 1) to prevent drawing vessel water to the suppression pool; 2) to prevent opening vessel suction valves above the suction line or the discharge line design pressure, and

3) to prevent pump start when suction valve(s) are not open.

5.4.7.2.2 Equipment and Component Description System Main Pumps The RHR main system pumps are motor-driven deepwell pumps with mechanical seals and cyclone separators. The motors are air cooled by the ventilating system. The pumps are sized on the basis of the LPCI mode and the minimum flow mode. Design pressure for the pump suction structure is 200 psig with a temperature range from 32°F to 360°F. Design pressure for the pump discharge structure is 500 psig. The bases for the design temperature and pressure is maximum shutdown cut-in pressures and temperature, minimum ambient temperature, and maximum shutoff head. The pump casing is carbon steel, the shaft and impellers are stainless steel. A comparison between the available and the required NPSH can be made using Section 6.3.2.2 and the pump characteristic curves provided in Fig. 5.4-14. Available NPSH is calculated in accordance with Regulatory Guide 1.1. as shown in Section 6.3.2.2.

Suction Strainers

RBS USAR Revision 27 5.4-30 Details of the RHR pumps suction strainers located inside the suppression pool are provided in Section 6.2.2.2.

Heat Exchangers The RHR heat exchangers are sized on the basis of the duty for suppression pool cooling mode.

All other uses of these exchangers require less cooling surface.

Flow rates are 5,050 gpm (rated) on the shell side and 5,800 gpm (rated) on the tube side (service water side). Rated inlet temperature is 185°F shell side and 95°F tube side. The overall heat transfer coefficient is 279 BTU per hour square foot -°F. The exchangers contain 11,394 sq ft of effective surface (with 5% tubes plugged). Design temperature of the shell side is 32°F to 480°F.

Design temperature on the tube side is 32°F to 480° F. Design pressure is 500 psig on the shell side and 150 psig on the tube side, fouling factors are 0.0005 shell side and 0.001 tube side. The construction materials are carbon steel for the pressure vessel with 70-30 Cu-Ni tubes and 70-30 Cu-Ni clad tube sheet.

Valves All of the directional valves in the system are conventional butterfly, gate, globe, and check valves designed for nuclear service. The injection valves, reactor coolant isolation valves, and pump minimum flow valves are high speed valves, as operation for LPCI or vessel isolation requires.

Valve pressure ratings are as necessary to provide the control or isolation function; i.e., all vessel isolation valves are rated as ASME III, Class 1 nuclear valves rated at the same pressure as the primary system.

ECCS Portions of the RHR System The ECCS portions of the RHR system include the suppression pool suction strainers, suction piping, RHR pumps, discharge piping, injection valves, and drywell piping into the vessel nozzles and core region of the reactor vessel.

Steam condensing components include steam supply piping and valves, heat exchangers, and condensate piping are installed. However these are disabled permanently for steam condensing mode of operation at RBS.

Pool cooling components include pool suction strainers, suction piping, pumps, heat exchangers and pool return lines.

5.4.7.2.3 Controls and Instrumentation Controls and instrumentation for the RHR system are described in Chapter 7.

The relief valve capacity and setting are shown in Table 5.4-3. The discharge piping is routed to drain into the suppression pool as shown on Fig. 5.4-12.

The RHR pressure relief valve discharge lines are designed in accordance with ASME Section III, NC-3652 requirements. The pressure relief valve blowdown transient is included in the design of the discharge lines. Adequate design margin is provided to accommodate water (steam) hammer loads.

RBS USAR Revision 27 5.4-31 5.4.7.2.4 Applicable Standards, Codes, and Classifications Piping, Pumps, and Valves

1.

Process side ASME III Class 1/2

2.

Service water side ASME III Class 3 Heat Exchangers

1.

Process side ASME III Class 2 TEMA Class C

2.

Service water side ASME III Class 3 TEMA Class C Electrical Portions

1.

IEEE 279

2.

IEEE 308 5.4.7.2.5 Reliability Considerations The RHR system has included the redundancy requirements of Section 5.4.7.1.5. Two completely redundant loops have been provided to remove residual heat, each powered from a separate, emergency bus. With the exception of the common shutdown line, all mechanical and electrical components are separate. Either loop is capable of shutting down the reactor within a reasonable length of time.

The following design is incorporated to assure that systems connected to the RHR system do not degrade the reliability of the RHR system:

1.

LPCI initiation causes automatic recovery of all required system automatic valves from any any other mode to their LPCI alignment.

2.

Valves are provided to isolate RHR from various other systems by the following methods:

a.

Normally closed manually operated valves are provided which require the operator to follow operating and maintenance guidelines;

b.

Normally closed remote manually motor-operated valves are provided with position indication lights in the control room; or

c.

Simple check valves in series with normally open stop check valves are provided.

RBS USAR Revision 27 5.4-32

d.

Normally open automatically operated valves are provided with automatic closure signals on a LPCI initiation signal and are provided with position indication lights in the control room.

5.4.7.2.6 Manual Action Residual Heat Removal (Shutdown Cooling Mode)

In shutdown operation, when vessel presssure is 135 psig or less, the pool suction valve may be closed for the initial shutdown loop. Then local manually operated flushing valves are opened, and the stagnant water flushed to radwaste via valves El2-F040 and F049 which are operated from the main control room. At the end of this nominal flush, the lower half of the shutdown loop may be prewarmed by opening vessel suction valves, with effluent directed through the heat exchanger to radwaste as before. The radwaste effluent valves are closed when increasing temperature is noted at the heat exchanger inlet. Service water flow is then established. After process side valve alignment, an RHR pump is started and the heat exchanger bypass valve (E12-F048) is then throttled open to establish a stable flow. The heat exchanger outlet valve (E12-F003) is then throttled open and cooldown of the vessel is in progress. The cooldown rate is controlled via valves E12-F048 (heat exchanger bypass flow) and E12-F003 (heat exchanger flow). All operations are performed from the main control room except for opening and closing of local flush water valves. Alternate methods for ensuring the shutdown cooling loops contain reactor quality water, such as flushing via the suppression pool cooling system lineup, may be used.

When reactor coolant temperature is less than or equal to 200 degress F, various RHR valves may be manually realigned to place an alternate decay heat removal configuration of the Suppression Pool Cleanup, Cooling, and Alternate Decay Heat Removal system into service.

The manual actions required for the most limiting failure are discussed in Section 5.4.7.1.5.

Steam Condensing DELETED 5.4.7.3 Performance Evaluation Thermal performance of the RHR heat exchangers is based upon containment cooling in the suppression pool cooling mode. This provides excess capability for the shutdown mode. Because shutdown is usually a controlled operation, maximum service water temperature less 10°F is used as the service water inlet temperature. These are nominal design conditions; if the service water temperature is higher, the exchanger capabilities are reduced and the shutdown time is longer and vice versa.

5.4.7.3.1 Shutdown with All Components Available No typical curve is included here to show vessel cooldown temperatures versus time due to the infinite variety of such curves that may be due to: 1) clean steam systems that may allow the main condenser to be used as the heat sink when nuclear steam pressure is insufficient to maintain steam air ejector performance; 2) the condition of fouling of the exchangers; 3) operator use of one or two cooling loops; 4) coolant water temperature; and 5) system flushing time. Since the exchangers are designed for the fouled condition with relatively high service water

RBS USAR Revision 27 5.4-33 temperature, the units have excess capability to cool when first cut in at high vessel temperature.

Total flow and mix temperature must be controlled to avoid exceeding 100°F per hr cooldown rate (see Section 5.4.7.1.1.1 for minimum shutdown time to reach 212°F).

5.4.7.3.2 Shutdown with Most Limiting Failure Shutdown under conditions of the most limiting failure is discussed in Section 5.4.7.1.1.1. The capability of the heat exchanger for any time period is balanced against residual heat, pump heat, and sensible heat. The excess over residual heat and pump heat is used to reduce the sensible heat.

NOTE: HISTORICAL INFORMATION 5.4.7.4 Preoperational Testing The preoperational test program and startup test program as discussed in Chapter 14 are used to generate data to verify the operational capabilities of each piece of equipment in the system:

each instrument, each set point, each logic element, each pump, each heat exchanger, each valve, and each limit switch. In addition, these programs verify the capabilities of the system to provide the flows, pressures, cooldown rates, and reaction times required to perform all system functions as specified for the system or component in the system data sheets and process data.

Logic elements are tested electrically; valves, pumps, controllers, relief valves are tested mechanically; finally, the system is tested for total system performance against the design requirements as previously specified using both offsite power and standby emergency power.

Preliminary heat exchanger performance can be evaluated by operating in the suppression pool cooling mode, but a vessel shutdown is required for the final check due to the small temperature differences available with suppression pool cooling.

NOTE: END OF HISTORICAL INFORMATION 5.4.8 Reactor Water Cleanup System The RWCU system is classified as a primary power generation system (not an engineered safety feature); a small part of which is part of the RCPB up to and including the second isolation valve.

The other portions of the system are not part of the RCPB and are isolatable from the reactor.

The RWCU system may be operated at any time during planned reactor operations or it may be shutdown if water quality is within the Technical Specifications limits.

The reactor coolant limits and corrective actions to be taken are specified in the plant Technical Requirements Manual. The chemical analysis methods to be used for the determination of pH, conductivity, and chlorides content are presented in approved plant procedures which are available for review at the plant site.

RBS USAR Revision 27 5.4-34 5.4.8.1 Design Basis 5.4.8.1.1 Safety Design Basis The RCPB portion of the RWCU system meets the requirements of Regulatory Guides 1.26 and 1.29 in order to:

1.

Prevent excessive loss of reactor coolant

2.

Prevent the release of radioactive material from the reactor

3.

Isolate the major portion of the RWCU system from the RCPB.

5.4.8.1.2 Power Generation Design Basis The RWCU system:

1.

Removes solid and dissolved impurities from reactor coolant, and measures the reactor water conductivity in accordance with Regulatory Guide 1.56

2.

Discharges excess reactor water during startup, shutdown, and hot standby conditions to the main condenser or radwaste

3.

Minimizes temperature gradients in the main recirculation piping and reactor pressure vessel during periods when the main recirculation pumps are unavailable

4.

Minimizes the RWCU system heat loss

5.

Enables the major portion of the RWCU system to be serviced during reactor operation

6.

Prevents the standby liquid reactivity control material from being removed from the reactor water by the cleanup system when required for shutdown.

5.4.8.2 System Description The system takes its suction from the inlet of each reactor main recirculation pump and from the RPV bottom head. The process fluid is circulated with the cleanup pumps through a regenerative and nonregenerative heat exchanger for cooling, through the filter demineralizers for cleanup, and back through the regenerative heat exchanger for reheating. The processed water is returned to the RPV and/or the main condenser or radwaste (Fig. 5.4-15).

The major equipment of the RWCU system is located outside the drywell. This equipment includes pumps, regenerative and nonregenerative heat exchangers, and filter-demineralizers with precoat equipment. Flow rate capacities for the major pieces of equipment are presented in Table 5.4-2.

The temperature of the filter-demineralizer units is limited by the resin operating temperature.

Therefore, the reactor coolant must be cooled before being processed in the filter-demineralizer units. The regenerative heat exchanger transfers heat from the tubeside (hot process inlet) to the shellside (cold process inlet). The shellside flow returns to the reactor. The nonregenerative heat

RBS USAR Revision 27 5.4-35 exchanger cools the process further by transferring heat to the reactor plant component cooling water system.

The filter-demineralizer units (Fig. 5.4-15) are pressure precoat type filters, using filter aid and mixed ion-exchange resins. Spent resins are not regenerable and are sluiced from the filter-demineralizer unit to a backwash receiving tank from which they are transferred to the radwaste system for processing and disposal. To prevent resins from entering the reactor recirculation system in the event of failure of a filter-demineralizer resin support, strainers are installed on the influent and effluent of the filter-demineralizer unit. Each strainer and filter-demineralizer vessel has a main control room alarm that is energized by high differential pressure.

Upon further increase in differential pressure from the alarm point, the filter-demineralizer automatically isolates.

The backwash and precoat cycle for a filter-demineralizer unit is entirely automatic to prevent human operational errors, such as inadvertent opening of valves that would initiate a backwash or contaminate reactor water with resins. The filter-demineralizer piping configuration is arranged to ensure that transfers are complete and crud traps are eliminated. A bypass line is provided around the filter-demineralizer units.

Flow rates through both RWCU filter-demineralizer vessels are measured by flow elements and flow transmitters on the discharge lines of the demineralizer vessels, with each flow being recorded on a flow recorder located locally on the filter-demineralizer control panel and indicated in the main control room.

In the event of low flow or loss of flow in the system, flow is maintained through each filter-demineralizer by its own holding pump. Sample points are provided in the common influent header and in each effluent line of the filter-demineralizer units for continuous indication and recording of system conductivity. High conductivity is annunciated in the main control room. The alarm set points of the conductivity meters at the inlet and outlet of the RWCU filter-demineralizers are 1.0 PS/cm and 0.15 PS/cm, respectively. The influent sample point is also used as the normal source of reactor coolant grab samples. Sample analysis also indicates the effectiveness of the filter-demineralizer units.

The suction line (RCPB portion) of the RWCU system contains two motor-operated isolation valves, which automatically close in response to signals from RPV low-low water level, leak detection system, and actuation of the standby liquid control system. Section 7.6 describes the leak detection system requirements, which are summarized in Table 5.2-8. This isolation prevents the loss of reactor coolant and release of radioactive material from the reactor and prevents removal of liquid reactivity control material by the cleanup system should the SLCS be in operation. The RCPB isolation valves may be remote manually operated to isolate the system equipment for maintenance or servicing. The requirements for the RCPB are specified in Section 5.2.

The motor-operated isolation valve on the suction of the RWCU pumps automatically closes in response to a nonregenerative heat exchanger high outlet temperature. This isolation prevents damage of the filter-demineralizer resins due to high temperature.

A remote manually operated gate valve on the return line to the reactor provides long-term leakage control. Instantaneous reverse flow isolation is provided by check valves in the RWCU system piping.

RBS USAR Revision 27 5.4-36 Operation of the RWCU system is controlled from the main control room. Resin-changing operations, which include backwashing and precoating, are controlled from a local control panel.

The time required to remove a unit from the line, backwash, and precoat is less than 1 hr.

5.4.8.3 System Evaluation The RWCU system in conjunction with the condensate treatment system, and the fuel pool cooling and cleanup system maintains reactor water quality during all reactor operating modes (normal, hot standby, startup, shutdown, and refueling).

This type of pressure precoat cleanup system was first put into operation in 1971 and is in use in all operating BWR plants started since. Operating plant experience has shown that the RWCU system as designed in accordance with these criteria provides the required BWR water quality.

The nonregenerative heat exchanger is sized to maintain the required process temperature for filter demineralization when the cooling capacity of the regenerative heat exchanger is reduced due to partially bypassing a portion of the return flow to the main condenser or radwaste. The control requirements of the RCPB isolation valves are designed to the requirements of Section 7.3.1. The component design data (flow rates, pressure, and temperature) are presented in Table 5.4-2. All components are designed to the requirements of Section 3.2, according to the requirements of Fig. 5.4-15.

5.4.9 Main Steam Line and Feedwater Piping 5.4.9.1 Design Bases The design bases for these lines:

1.

The main steam and feedwater lines within the RCPB are designed to accommodate operational stresses, such as internal pressures and SSE loads, without a failure that could lead to the release of radioactivity in excess of the guideline values in published regulations

2.

They are provided with suitable accesses to permit inservice testing and inspections

3.

The main steam, feedwater, and associated drain lines are evaluated for damage due to potential fluid jets, missiles, reaction forces, pressures, and temperatures due to pipe breaks and are protected as necessary.

4.

The main steam lines are designed to conduct steam from the reactor vessel over the full range of reactor power operation.

5.

The feedwater lines are designed to conduct water to the reactor vessel over the full range of reactor power operation.

5.4.9.2 Description The main steam piping is designed to conduct steam from the reactor vessel through the primary containment to the steam turbine (Fig. 10.3-la through 10.3-1c). There are four main steam lines between the reactor and the turbine. The use of multiple lines permits main turbine stop valve and MSIV tests during unit operation with a minimum amount of load oscillation. To fully achieve this objective, and to ensure that the turbine bypass system is connected to the active steam

RBS USAR Revision 27 5.4-37 lines, the four main steam lines are headered upstream of the main turbine stop valves. The bypass system is connected at the header. Drain lines are connected to the low points of each main steam line inside and outside the drywell to permit continuous draining of the main steam line low points. An additional drain is provided at the main steam header to permit draining the main steam lines to the main condenser for maintenance.

The main steam piping from the reactor vessel up to and including the first weld outside the impingement wall is designed to ASME III, Code Class 1. Each main steam line contains a flow restrictor as described in Section 5.4.4 and MSIVs as discussed in Section 5.4.5. SRVs are located upstream of the first isolation valves on horizontal sections of the main steam lines.

Discharge from the SRVs is piped to the suppression pool. Steam supply to the RCIC turbine is taken from one main steam line inside the drywell. Main steam piping and valves including branch lines up to and including the first isolation valve are Safety Class 1 and Seismic Category I.

Quality group classifications are listed in detail in Table 3.2-1.

The feedwater piping consists of two 20-in outside dia lines which penetrate the containment and drywell and branch into four 12-in lines which connect to the reactor vessel. Each line includes three containment isolation valves consisting of one check valve inside the drywell, one motor-operated gate valve, and one spring load piston actuated check valve outside the containment. The design pressure and temperature of the feedwater piping between the reactor and maintenance valve is 1,300 psig and 575°F. The feedwater piping from the reactor through the outboard isolation valve and connected piping of 2-1/2 in or larger nominal pipe size, up to and including the second isolation valve in the connected piping are designed to Seismic Category I requirements.

The feedwater piping is designed to conduct water from sources outside the primary containment to the reactor vessel. The general requirements of the feedwater system are covered in Section 7.7.1.3 and Section 10.4.7.

5.4.9.3 Safety Evaluation Differential pressure on reactor internals under the assumed accident condition of a ruptured steam line is limited by the use of flow restrictors and by the use of four main steam lines. All main steam and feedwater lines of the RCPB are designed in accordance with the requirements defined in Section 3.2 and with GDC 14. The RBS response to GDC 14 is given in Section 3.1.2.14. Design of the piping in accordance with these requirements ensures meeting the design bases.

5.4.9.4 Inspection and Testing Testing and inspection of components within the RCPB are carried out in accordance with ASME Section III, Class 1. Access requirements for inservice inspection are considered in the design of the main steam and feedwater piping to ensure adequate working space and access for inspection of selected components and areas. Details of tests and inspections are given in Section 3.9 and Chapter 14.

5.4.10 Pressurizer (Not Applicable to BWR) 5.4.11 Pressurizer Relief Discharge System

RBS USAR Revision 27 5.4-38 (Not Applicable to BWR) 5.4.12 Valves 5.4.12.1 Design Basis Line valves in the RHR, RCIC, RWCU, HPCS, LPCS, and standby liquid control systems, and located beyond the RCPB, are designed to maintain the integrity of the individual fluid system's boundary.

The valves are designed to operate under the internal pressure and temperature loading as well as the external loading experienced during the various systems' transient operating conditions.

Valves are designed in accordance with the applicable requirements designated in Table 3.2-1.

Compliance with ASME Codes is discussed in Section 5.2.1. The design loading, design procedure, and acceptability criteria are described in Section 3.9.3B.

Valves are analyzed to determine effects of possible pipe rupture and jet impingement of high energy systems. Valves subject to failure due to these forces are protected by either reorienting the valve, erecting a deflector plate, or providing a suitable enclosure. Further discussion of protection of components against damage from missiles and dynamic effects of pipe rupture is provided in Sections 3.5, 3.6A, and 3.6B.

5.4.12.2 Description Valves supplied are manufacturer's standard types of gate, globe, butterfly and check valves, with design, fabrication, certification, installation, testing, and inspection all in accordance with ASME Section III Class 1, 2, or 3.

Valves are designed to meet the environmental conditions applicable to the particular system as described in Section 3.11. All materials, exclusive of seals and packing, are designed for a 40-yr plant life under the environmental conditions applicable to the particular system when appropriate maintenance is periodically performed.

Maximum allowable leakage rates are stated in the purchase specifications for the main seat for gate, globe, butterfly and check valves.

The purchase specifications require that motor-operated valves be capable of closing or opening against maximum unbalanced operating pressures and maximum flow, at a rate of not less than 12 in/min for gate valves and a rate of not less than 4 in/min for globe valves, unless otherwise specified on the data sheet.

5.4.12.3 Safety Evaluation Line valves are designed and manufactured to the requirements of ASME III, Subsections NB, NC, and ND, commensurate with their importance to safety, in accordance with the design pressure, and temperature and code class as listed in Tables 3.9A-10, 3.9A-11, and 3.9B-2.

Loading combinations are discussed in Section 3.9.3B.

RBS USAR Revision 27 5.4-39 Power actuators are subjected to a shop functional test to ensure that the actuators and accessories perform as required. Valve construction materials are compatible with the maximum anticipated radiation dosage for the service life of the valves.

5.4.12.4 Inspection and Testing Line valves have been subjected to the following manufacturer's shop tests, as outlined in the purchase specification:

1.

Operational tests of valves and operator assemblies were conducted, running the valves from the full open to the full closed position and back for each of three cycles, to demonstrate compliance with the operational requirements.

2.

Each valve was hydrostatically tested in accordance with the requirements in ASME Section III. During the valve fabrication, extensive nondestructive tests and examinations are conducted, including radiography, ultrasonic, liquid penetrant or magnetic particle examination of castings, forgings, welds, hardfacing, and bolts.

Valve wall thickness is in accordance with ASME Section III. All valves in Class 1, 2, and 3 are documented by their shop measurements, methods, and controls.

Pressure-retaining parts are subject to the testing and examination requirements of ASME Section III.

Valves serving as containment isolation valves, and which must remain closed or open during normal plant operation, are partially exercised during normal plant operation to assure their operability at the time of an emergency or faulted condition. Other valves, serving as system block or throttling valves, are exercised without jeopardizing system integrity for the same reason.

Motors used with valve actuators have been furnished in accordance with applicable industry standards. Each motor actuator has been assembled, factory tested, and adjusted on the valve for proper operation, position and torque switch setting, position transmitter function (where applicable), and speed requirements. Valves have additionally been tested to demonstrate adequate stem thrust (or torque) capability to open (or close) the valve within the specified time at specified differential pressure. Tests verified no mechanical damage to valve components during full stroking of the valve. Suppliers were required to furnish assurance of acceptability of the equipment for the intended service based on any combination of:

1.

Test stand data

2.

Prior field performance

3.

Prototype testing

4.

Engineering analysis.

Preoperational and operational testing performed on the installed valves consist of total circuit checkout and performance tests to verify speed requirements at specified differential pressure.

5.4.13 Safety and Relief Valves

RBS USAR Revision 27 5.4-40 5.4.13.1 Safety Design Bases Overpressure protection has been provided at isolatable portions of systems in accordance with the rules set forth in ASME Section III for Class 1, 2, and 3 components.

5.4.13.2 Description Pressure relief valves have been designed and constructed in accordance with the same code class as that of the line valves in the system.

Table 3.2-1 lists the applicable code classes for valves. The design criteria, design loading, and design procedure are described in Section 3.9.3B.

5.4.13.3 Safety Evaluation The use of pressure-relieving devices assures that overpressure does not exceed 10 percent above the design pressure of the system. The number of pressure-relieving devices on a system or portion of a system has been determined on this basis.

5.4.13.4 Inspection and Testing No provisions are made for in-line testing of pressure relief valves. Certified set pressures and relieving capacities are stamped on the body of the valves by the manufacturer and further examinations would likely necessitate removal of the component.

5.4.14 Component Supports The RPV supports are discussed in Section 5.3.3.1.4.1. The pedestal supporting the RPV is described in Section 3.8.3. Recirculation pump supports and the recirculation piping suspension system and restraints are presented in Section 5.4.1.3.

5.4.14.1 Design Bases Component supports in the RHR, RCIC, RWCU, HPCS, LPCS, and standby liquid control systems beyond the RCPB, but closely allied with the reactor coolant system, are designed in accordance with the requirements of Section 3.9.3.4B.

Flexibility and seismic analysis for Classes 1, 2, and 3 components conform with the appropriate requirements of ASME Section III. Support types, materials used for fabricated support elements, and recommended pipe support spacing conform to ASME Section III, Section NF.

5.4.14.2 Description The use and location of rigid-type supports, variable or constant spring-type supports, snubbers, and anchors or guides are determined by flexibility and seismic and stress analysis. Component standard supports are utilized to the maximum extent possible. Direct weldments to pipe wall are analyzed.

5.4.14.3 Safety Evaluation

RBS USAR Revision 27 5.4-41 Design loadings used for flexibility and seismic analysis toward the determinaton of adequate component support systems include all mechanical and thermal transient loading conditions expected by each component. Provisions are made to lock spring-type supports for the initial dead weight loading due to hydrostatic testing of steam systems to prevent damage to this type support. Component supports are further discussed in Section 3.9.3.4B.

5.4.14.4 Inspection and Testing After completion of the installation of a support system, all hanger elements are visually examined to assure that they are in correct adjustment in their cold setting position. Upon hot startup operations, thermal growth is observed to confirm that spring-type hangers, snubbers, and constant supports function properly between their hot and cold setting positions. Final adjustment capability is provided on spring supports, snubbers, constant supports, rod hangers, and sway struts. Weld inspection and standards are in accordance with ASME Section III. Welder qualifications and welding procedures are in accordance with ASME Section IX.

References - 5.4

1.

Ianni, P.W. Effectiveness of Core Standby Cooling Systems for General Electric Boiling Water Reactors. APED-5458, March 1968.

2.

Design and Performance of General Electric Boiling Water Reactor Main Steam Line Isolation Valves. APED-5750, General Electric Co., Atomic Power Equipment Department, March 1969.

RBS USAR Revision 27 1 of 3 TABLE 5.4-1 REACTOR RECIRCULATION SYSTEM DESIGN CHARACTERISTICS EXTERNAL LOOPS (2)

Single Loop Approx.

Nominal Piping Description Quantity Length (ft)

Size (in)

Pump suction line Straight pipe 31 1/2 20 Elbows 3

20 Gate valves 1

20 Discharge line Straight pipe 28 20 Elbows 2

20 Flow control valves 1

20 Gate valves 1

20 Discharge manifold Pipe 36 16 Reducer cross 1

20x16 Contour nozzle 4

16x10 Caps 2

16 Concentric reducer 1

20x10 External risers Straight pipe 5

8 10 Elbows 5

10 Design pressure (psig) design temperature (F°)

Suction piping and valve up to and 1,250/575 including pump suction nozzle Pump and discharge piping up to and 1,650/575 including the discharge valve Piping beyond the discharge valve up 1,550/575 to the vessel Pump auxiliary piping and cooling 150/125*

water piping Vessel bottom head drain 1,275/575

• High temperature alarm setpoint

RBS USAR TABLE 5.4-1(Cont)

Revision 27 2 of 3 Operation at Operation at Rated Power Power Uprate and Rated With Increased Core Flow Core Flow Recirculation Pump Flow, gpm 32,500 34,300 Flow, lb/hr 12.29x106 12.95x106 Total developed head, ft 815 836 Suction pressure (static), psia 1,041 1071 Required NPSH, ft 82 91 Water Temperature (max), °F 532.9 538 Pump brake (min), hp 5,820 6,245 Flow velocity at pump suction, fps 41.3 43.5 PUMP MOTOR Voltage rating 4,000 Speed, rpm 1,780 Motor rating, hp 6,300 Phase 3

Frequency, Hz 60 Rotational inertia,* lb-ft 15,200 JET PUMPS Number 20 Total driving flow, lb/hr/jet pump 1.228x106 1.295x106 Throat ID, in 6.0 Diffuser ID, in 13.45 Nozzle ID (five each), in 1.13 Diffuser exit velocity, fps 25.2 26.6 Jet pump head, ft 85.2 94.6 FLOW CONTROL VALVE Type Ball Austenitic Material stainless steel Type actuation Hydraulic Failure mode (on loss of power or control signal)

As is CV 5,750 Valve size diameter, in 20

RBS USAR TABLE 5.4-1(Cont)

???????????????

• Pump and motor Revision 27 3 of 3 RECIRCULATION BLOCK VALVE, DISCHARGE Type Gate Actuator Motor operator Austenitic Material stainless steel Valve size diameter, in 20 RECIRCULATION BLOCK VALVE, SUCTION Type Gate Actuator Motor operator Austenitic Material stainless steel Valve size diameter, in 20 LFMG SET NAMEPLATE Motor horsepower 250 Voltage 460 Generator frequency, Hz 15 Generator voltage325

RBS USAR Revision 27 1 of 1 TABLE 5.4-2 REACTOR WATER CLEANUP SYSTEM EQUIPMENT DESIGN DATA System Flow Rate (lb/hr) 124,000-143,800 Cleanup Pumps Number required 2

Capacity % (each) 50 Design temperature (°F) 575 Design pressure (psig) 1,410 Discharge head at shutoff (ft) 600 Minimum available NPSH (ft) 13 Heat Exchangers Non-Regenerative Regenerative Capacity %

100 100 Shell design pressure (psig) 1420 150 Shell design temperature (°F) 575 370 Tube design pressure (psig) 1,410 1,410 Tube design temperature (°F) 575 575 Filter-Demineralizers Type Pressure Precoat Number required 2

Capacity % (each) 50 Flow rate per unit (lb/hr) 62,000 - 71,900 Design temperature (°F) 150 Design pressure (psig) 1,410

RBS USAR Revision 27 1 of 1 TABLE 5.4-3 RHR RELIEF VALVE DATA Set Capacity Pressure Required/

Max/

ASME Rated Max + 10%

Section/

Valve (gpm)

(psig) Class F005 Thermal 200/220 III/2 Relief F017A,B Thermal 200/220 III/2 Relief F025A,B,C Thermal 500/550 III/2 Relief F030 Thermal 200/220 III/2 Relief F036 1,500/Ltr 75/83 III/2 F101 Thermal 200/220 III/2 Relief V67A,B Thermal 500/550 III/2 Relief

)2

)7 1%

$%

)7 1$

$1

+31/

3

+31/

3

-

127(6

6<67(07,7/(

6<612





 $///,1(,167580(179$/9($1'(48,30(1772%(35(),;(':,7+%(;&(37

+(5($',))(5(1735(),;,66+2:1



7+,6'5$:,1*+$6%((15('5$:1)520*(1(5$/(/(&75,&&203$1<'5$:,1*

12($$











&21752/52''5,9(+<'5$8/,&

&/26('&22/,1*:755($&7253/$17 5(6,'8$/+($75(029$//3&,

5($&725:75&/183 ),/7(5

'5$,16)/225 (48,30(17 6$03/,1*5($&7253/$17

$,5,167580(17

57' 1%

%1

57' 1%

%1

3'7 1%

'5<:(//

(/



5&6 52



%

5&6 52



%

+26(

9)%

%

9)%

%

9)%

%

,16,'('5<:(//



+31/

3

5&6

52



%

3&%%

'5%

=



'5%

=



'5%

=



=



029

)%

%1

5&6 +26(%

)2 37 1$

+31/

3

37 1%

5&6

9

%

5&6

52



$

5&6

52



$

5&6

52



$

)7 1&

$5

)7 1'

$%

)7 1$

$5

5&6

+26(

$

5&6

+26(

$

5&6

9

$

5&6

9

$

5&6

9

$

5&6

9

$

5&6

52



$

+31/

3

'5%

=



'5%

=



'5%

=



'5%

=



'5%

=



)9

)%

+

5&6

9

%

5&6

9

5&6

9

5&6

9

5&6

9

5&6 +26($

5&6 +26($

$

$

$

$

5&6

52



%

5&6

+26(

%

57' 1$

$1

57' 1$

$1

5&6 52



$

5&6 52



$

5&6

9

$

5&6

9

$

3'7 1$

+31/

5&6 52



$

$

9)$

$

9)$

$

9)$

$



=



'5%

=



'5%

=



'5%

=



029

)$

$1

3&$

$

'5<:(//

(/



5&6

)/(;

+26(



7&

&%

7&

&%

7&

&%

&%

7&

&%

7&

&%

/6

&%

8

/6

&%

0

/6

&%

1 7&

&%

63$5(

63$5(

7&

&%

3, 5%

5&6

3, 5%

5&6



%

+31/

3

'5%

'5%

=



029

)%

%1

;5('

+<9

)%

%

6($/

&$9,7<

12

6($/

&$9,7<

12

(

)&

)&

37 1$

3, 5$

3, 5$

+31/

3

+31/

3

+

31/

3

37 1%

)7 1'

%%

5&6

52



%

5&6

52

%

)7 1&

%5

5&6

%

)7 1%

%1

5&6

9

%

5&6

9

%

'5%

=



'5%

=



'5%

=



'5%

=



5&6 5&6 5&6

%

5&6

+26(

%

%

9

5&6

+26(

9%

5&6

9%

5&6

52

%





+26(

9

%

7&

&$

7&

&$

7&

&$

7&

&$

7&

&$

/6

&$

8 7&

&$

/6

&$

1

/6

&$

0 63$5(

63$5(

63$5(

5&6 52



$

5&6

9

$

5&6

9

&

'5%

=



'5%

+<9

)$

$

029

)$

$1

6($/

&$9,7<

12

6($/

&$9,7<

12

;5'&5 7&

&$

$

5&6 +26(

5&6 +26(

$

7&

&%

7&

&%

7&

&%

7&

&%

7&

&%

7&

&%

7&

&%

7&

&%

7&

02725:,1',1*&22/(5%

63$5(

63$5(

/6

&%

5

/6

&%

6 63$5(

63$5(

63$5(

/223%

9)

=



72-(738036

)

=%

$29

)

=5

6$03/(

352%(

6037'

% 5(9

'=

5($&725 9(66(/

7&

&$

7&

&$

7&

&$

7&

&$

7&

&$

7&

&$

7&

&$

02725:,1',1*&22/(5$

/6

&$

6

/6

&$

5 63$5(

/223$

63$5(

63$5(

F0

F/

F)

F'

F0

F(

':*12















F(

F(

D1

F/

D3

F1

F0

F1

F0

F1

F0

D$

D$

F1

F(

F(

F)

F(

F)

F(

F)

D)

F3

D(

D(

D3

F+

D)

D(

D(

F)

F*

D*

D*

D)

D)

D)

F*

D*

D*

D*

D*

D)

9$/9(/,1(836

,1)250$7,2121/<&2168/77+(67$7,2123(5$7,1*352&('85(6623 6)25$&78$/

9$/9(326,7,216'(3,&77+(3/$17,1,761250$/23(5$7,1*02'($1'$5()25 3,3(&$3686('219(17'5$,1$1'7(67&211(&7,2167+$7$5(1250$//<,62/$7('

)5206<67(035(6685($5(1275(48,5('%<7+('(6,*1)256<67(023(5$%,/,7<

214&/$666<67(067+(<$5(5(48,5('%<7+()6$572/,0,7/($.$*(,)9$/9(

/($.$*(2&&856

/





















































































3 1

0

/

+

)

(

3 1

0

+

)

(









'(/(7('

322

),*85(

6<67(0 3 ,'

5(9,6,21

83'$7('6$)(7<$1$/<6,65(3257 5,9(5%(1'67$7,21

D



5($&7255(&,5&8/$7,21

&

3&$

1%(

1%(

3&$

3&$

1%(

52

$

$

%

%

&

&

'

(

'

)

)

(

• 

• 

%

%

$

$

&

&

(

(

• 

)

)

• 

-

+

+

&%

7&

7&

&%

-

63$5(

63$5(

&$

7&

&$

7&

+

+

63$5(

63$5(

-

-

)9

%

'5<:(//

,16,'(

+ 31/

3

+ 31/

3

+ 31/

3

+ 31/

3

+ 31/

3

)7 1$

%5

)7 1%

%%

+ 31/

3

3

+ 31/

5&6

9

%

5&6

9

%

5&6

9

%

,16,'(

'5<:(//

,16,'(

'5<:(//

$29 5&6 +26(

%

,16,'(

'5<:(//

5()(5(1&(6

)$

+31/

3

5&6

9

%

$

+

9 3&$

1%(

+

3&$

1%(

9

1%(

9 3&$

1%(

+

3&$

3&%

1%(

9 3&%

1%(

+

3&%

1%(

$

3&%

1%(

+

3&%

1%(

9 3&%

1%(

+

3&%

1%(

9 3&%

1%(



%7&$',6$'$0$*('63$5(5()&5



7&

&$

'

'

&$

7&

127(

18&/($56$)(7<5(/$7('

5

)5

+31/

3

&

+31/

3

1%(

3&$



&20321(17180%(5$1'6$)(7<&/$66,),&$7,21

5,9(5%(1'67$7,215()(5727+((48,30(17'$7$%$6(('%)257+(3523(5 7+($67(5,6. :$686(',1$35(9,286(48,30(17,'(17,),&$7,216<67(0$7



28



RIVER BEND STATION UPDATED SAFETY ANALYSIS REPORT VESSEL COOLANT TEMPERATURE VERSUS TIME (TWO HEAT EXCHANGERS AVAILABLE)

Figure 5.4-10 REVISION 14 SEPTEMBER 2001

RIVER BEND STATION UPDATED SAFETY ANALYSIS REPORT VESSEL COOLANT TEMPERATURE VERSUS TIME (ONE HEAT EXCHANGER AVAILABLE)

Figure 5.4-11 REVISION 14 SEPTEMBER 2001

9

=

+ 31/

3

+ 31/

3

(

)7 1$

$5

(

)7 1$

$5

0,;,1*7((

):6 %/$$

%/$$

9

$

(

)(

$

(

029

)

(

9)

=

+ 31/

3

)7 1

$5

(

(

7&

1

=1

(

&(

1

=%



6(7#

36,*

(

&(

1$

$5

E-

F+

D'

E-

F+

3

'

H3

E1

D*

E-

$

/





















































































3 1

0

/

+

)

(

3 1

0

+

)

(

)

0

+

E$

F+

E/

M'

(/



$8;%8,/',1*

$

$

F+

+

+

/&

$

9

/0&

/2

$5

12$

37

(

$5

12$

37

(

3

31/

+



$

9)$

(

$5

1$

37

(

$

9)$

(

$

9)$

(

$

5$

3,

(

/&

3,3(

• 8$5'



=

=

( )

=5

)

029

(



36,*

6(7$7

/0&

=

9

9

=

9

=%

)

029

(

=

9

$

=

$

'$

52

(

36,*

6(7$7

( 3&$$5

5(029$/3803$

5(6,'8$/+($7 6757$

7 3(

$

$

$

5$

3,

(

$5

(

029

)$

6

36,*

6(7#

/(9(/

0,1:$7(5

=

9

9

/0&

68335(66,21322/

$

9

/0&

9

$

=

$

9

/&

/0&

$

675$

9)

(



$

9)$

(

$

=

$

)$

59

(

3,3(&$3686('219(17'5$,1$1'7(67&211(&7,2167+$7$5(1250$//<,62/$7('

)5206<67(035(6685($5(1275(48,5('%<7+('(6,*1)256<67(023(5$%,/,7<

21 4&/$66  6<67(06 7+(< $5( 5(48,5(' %< 7+( )6$5 72 /,0,7 /($.$*(,) 9$/9(

/($.$*(2&&856

9$/9(326,7,216'(3,&77+(3/$17,1,761250$/23(5$7,1*02'($1'$5()25

E&











':*12





M'

M'

-

F-

M'

M'

M'

M'









E&

D3

(

029

$5

)$

$5

1$

37

$1

1$

7&

(

$

9

(

7<32)

;

6(59,&(:$7(51250$/

5($&725:75&/183 ),/7(5

/2:35(6685(&25(635$<





)((':$7(5

&21'(16$7(0$.(836725$*( 75$16)(5 5()(5(1&(6







6<612

6<67(07,7/(

5$':$67(/,48,'

)8(/322/&22/,1*





(

$

(%$

$

9

$

9

3(

7

$

(%&

(

=

9)

(

7

$

9

3(

$1

1$

7&

(

,1)250$7,2121/<&2168/77+(67$7,2123(5$7,1*352&('85(6623 6)25

$&78$/9$/9(/,1(836

7+,6,6$*(1(5$/(/(&75,&6<67(0

7+,6'5:$,1*+$6%((15('5$:1)520*(1(5$/(/(&75,&':*12($$

'(127(69$/9(:(/'('723(1(75$7,21

$///,1(,167580(179$/9($1'(48,30(17180%(5672%(35(),;(':,7+

5+6(;&(37:+(5($',))(5(1735(),;,66+2:1



127(6

5($&725&25(,62/$7,21&22/,1*



6$03/,1*785%,1(

6$03/,1*5($&7253/$17

'5$,16)/225 (48,30(17







%%

9)%

(









7811(/

$8;%/'*

5

$

=6



H3

1

F-

E3

F1

M+

M+

E0

9$

/&

/2 9)$

9)$

5

$

=6

$5

)$

$29

(

$5

)$

029

(

$5

)$

029

(







+26(



+26(



$

9)$

(







$5

(

',0 0,1

5(9'=

%

9(66(/

5($&725

',0

0,1

$

9

$

(

=



52



=

'5%



=

'5%

=

9

$

=

$



52

=5

1$

3'7

(

)&

)&

$5

$

57'

$

$

7:

$

=

'5%

$

$

52

$

9

%/'*

6+,(/'

&217$,10(17 3

31/

+

3

+ 31/

(//

'5<

$5

1$

37

(

5

1$

(6

(

$

9

(









1$

&



5($&7255(&,5&8/$7,21

&217$,10(17 6+,(/'

%8,/',1*

'5<:(//



D



127(





7+($,5$&78$725217+,69$/9(+$6%((1',6&211(&7(',17+(

),(/'%<5(029,1*7+(/(9(5$50

),*85(

6<67(0 3 ,'

5(9,6,21

83'$7('6$)(7<$1$/<6,65(3257 5,9(5%(1'67$7,21

D



5(6,'8$/+($75(029$//3&,

$

3

/2

9

/2

9



52

$

$

9$/9(( 029)$+$6%((15(3/$&(':,7+$%/,1')/$1*(5()05

$,56833/<729$/9(( 39)$,6,62/$7('3(505

9$/9(( 029)$,6&855(17/<,167$//(':,7+)/2:29(57+(6($7

9$/9(6( 029)$$1'( 029)$+$9(32:(55(029('5()05









127(

127(

127(



127(





$',$0(7(5+2/(+$6%((1',5//(',17+('2:1675($05($&725 6,'(',6&2)( 029)$723529,'($1,17(5',6&35(6685(5(/,()

3$7+

127(



'(/(7('



,17(51$/65(029(')520&+(&.9$/9(5+6 9



'(/(7('



(

029

)$

$5

(

029

)

=%

(

029

)

=5





9

=

9

=

(

029

)$

$

(

9)$

$

+ 31/

3

(

37 1

=5

(

029

)$

$5

(

59

)

=

(

029

)$

$5

(

029

)$

$5

(

7&

1$

$1

9

$

(

9)$

$

9)$

$

(

9

$

(

9)$

$

9)$

(

$

(

029

)$

$5

9

$

127(

9

$

(

029

)$

$5

(

029

)$

$5

(

029

)%

%%

(

37 1

=5

=6

%

%

(

9)$

$5

(

029

)$

$5

(

59

)

=

7:

9

$

(

9)

=

(

029

)$

$

(

39

)$

$

(

629

)$

$5

(

629

)$

$%

(

/9

)$

$5

(

,3

.$

$5

(

029

)$

$5

(

)(

1

=

(

9)$

$

52

$

$

(

59

)$

$

(

029

)$

$5

72&21752/

&,5&8,7

$'69$/9(6

9

$

5(6,'8$/+($7 5(029$/

+($7(;&+$1*(5 5('(/%2:

9

=

9

$

+ 31/

3

9

=

[

'5$*5(6,6725

5+65$3/$7(7<3(5(675,&7,1*25,),&(5(3/$&(':,7+,1/,1(



127(

=6





7+(3,3,1*&/$66&+$1*()520&/$6672&/$66,66(3$5$7('3/8**('



$77+(35(6685(%281'$5<%<7+,&.3/$7(

7(0325$5<675$,1(56757$(/(0(17+$6%((15(029('



127(

127(

&/

&/

$

59

36,*

6(7#

&/

&/

127(



7+($67(5,6. :$686(',1$35(9,286(48,30(17,'(17,),&$7,216<67(0

$7 5,9(5 %(1' 67$7,21 5()(5 72 7+( (48,30(17 '$7$ %$6( ('% )25 7+(

3523(5&20321(17180%(5$1'6$)(7<&/$66,),&$7,21

18&/($56$)(7<5(/$7('

9

127(

=

/&

1



9$/9((029)+$6%((1'(7(50,1$7('5()05

7:

%

%

(

3, 5%

%

(

3, 5%

%

=

%

9

%

/0&

/&

7 6757%

(

9)%

%

9

%

3(

)%

%

(

59

)

=

675%

%

68335(66,21322/

( 3&%%%

5(6,'8$/+($7 5(029$/3803%

$8;%/'*

(/



0,1

$7(5

/(9(/

6(7#

36,*

6(7#

36,*



)%

%%

029

(

6

&217$,10(17

(

029

)%

%%



9%

5(6,'8$/+($75(029$/

+($7(;&+$1*(5 5(6,'8$/+($75(029$/

+($7(;&+$1*(5

(

37 1%

%%

'%

%

(

37 1%

%%

(

37 1%

%%

(

9)%%

(

9)%

%

(

9)%

%

(

9)%

%

9

%



(

9%

9)%%

+ 31/

3

/2









5($&725&25(,62/$7,21&22/,1*

5($&725:75&/183 ),/7(5

'5$,16)/225 (48,30(17 6$03/,1*785%,1(

127(6



$///,1(,167580(179$/9($1'(48,30(17180%(5672%(35(),;(':,7+5+6

(;&(37:+(5($',))(5(1735(),;,66+2:1



'(127(69$/9(:(/'('723(1(75$7,21



7+,6'5$:,1*+$6%((15('5$:1)520*(1(5$/(/(&75,&&2

':*12($$7+,6,6$*(1(5$/(/(&75,&6<67(0

9$/9(/,1(836

(

59

)%

%

6+,(/'%8,/',1*

(

59

(

9)%

%

(

9)%

%

=

%

=

%

9

%

(

,3

.%

%%

(

7&

1%

%1

3(

7

9%

(

029

)%

%%

(

7&

122%

%1

(

029

)%

%%

(

52 6(7#

36,*

(%%

(

(%'

%

(

029

)%

%%

6<67(07,7/(

6<612

5()(5(1&(6

(

&(

1%

%%

(

7&

1%

%1

7:

%

%

57'

%

%%

629

)&





9%

)&

)&







&21'(16$7(0$.(836725 75$16

)((':$7(5 6(59,&(:$7(51250$/

(

/9

)%

%%

(

029

)%

%%

)%

%%

%5

)%

629

(

(

(

$29

)

=1

(

029

)

=%

029

(

)

=%

(

9)%

%

(

9)%

%

(

9)$

$

(

9)$

$

+ 31/3

( 37 1%

(

37 1%

%%

+ 31/3

9

%

(

9)%

%

52

%

%

9%

(

39

)%

%

(

029

)%

%%

(

029

)%

(

)7 1%

%%

(

)7 1%

%%

(

)(

1%

%

)7

%

%%

%

+ 31/

3

+ 31/

3

9%

(

029

)%

%%

(

029

)%

%%

%%

+ 31/3

+ 31/3

( 37 1$

( 37 1$

( 37 1%

+ 31/3

(

9)%

%

0,;,1*

7((

%/%%

):6 %/%%

(

029

)2%

%%

*

52

%

%

5(9'=

5($&725 9(66(/

=6

%

%

52



=

'5%

=



'5%

=

%







(

9)%

%%

9=

(

9)%

%

=

%

&217$,10(17

9=

/&

(

$29

)%

%%

(

029

)%

%%

(

029

)%

(

029

)%

%%

6)& 9=

50 6+,(/'

%/'*

+26(=

/2

/&

0,1

',67

D &

D '

F+

D'

F'

$

N/

N.

N.

F'









N.

0

N.

N.

F+

':*12







H3

N/

I+

D )

*

E *

F*

E 1

N3

D1

N3

.

D .

.

E 1

D (

F.

F+

D1

D.

F1

F.

D+

9$/9(326,7,216'(3,&77+(3/$17,1,761250$/23(5$7,1*02'($1'$5()25

)5206<67(035(6685($5(1275(48,5('%<7+('(6,*1)256<67(023(5$%,/,7<

214&/$666<67(067+(<$5(5(48,5('%<7+()6$572/,0,7/($.$*(,)9$/9(

/($.$*(2&&856

,1)250$7,2121/<&2168/77+(67$7,2123(5$7,1*352&('85(6623 6)25$&78$/



5($&7255(&,5&8/$7,21



5($&7255(&,5&8/$7,21



)8(/322/&22/,1*

)8(/322/&22/,1*



D

E

D

E



3,3(&$3686('219(17'5$,16$1'7(67&211(&7,2167+$7$5(1250$//<,62/$7('





9%

127(

)253803'5$,16 6((),*N0

127(



7+($,5$&78$725217+,69$/9(+$6%((1',6&211(&7(',17+(),(/'%<

5(029,1*7+(/(9(5$50

),*85(

6<67(0 3 ,'

5(9,6,21

83'$7('6$)(7<$1$/<6,65(3257 5,9(5%(1'67$7,21

E



5(6,'8$/+($75(029$//3&,

%

3

/2

9

/2

9

52

%

%

9$/9(( 029)%+$6%((15(3/$&(':,7+%/,1')/$1*(

5()05

9$/9(6( 029)%$1' 029)%+$9(32:(55(029('

5()05

$,56833/<729$/9(( 39)%,6,62/$7('3(505

9$/9(( 029)%,6&855(17/<,167$//(':,7+)/2:29(5 7+(6($7

( 3712$% ( 3712$%+$9(%((1(/(&75,&$//<

',6&211(&7('$1'6(59(126<67(0)81&7,217+(6(

,167580(176$5(63$5(',13/$&($1'7+(,167580(17 6(16,1*/,1(,6&$33('1($57+(25,*,1$/6285&(

&211(&7,2132,17











127(

127(

127(

127(

127(6

127(

127(

%



'(/(7('

$',$0(7(5+2/(+$6%((1'5,//(',17+('2:1675($05($&725 6,'(',6&2)( 029)%723529,'($1,17(5',6&35(6685(

5(/,()3$7+



127(

127(

,17(51$/65(029(')520&+(&.9$/9(5+6 9





'(/(7('

/





















































































3 1

0

/

+

)

(

3 1

0

+

)

(

5+65%3/$7(7<3(5(675,&7,1*25,),&(5(3/$&(':,7+,1/,1(

'5$*5(6,6725



127(

7+(3,3,1*&/$66&+$1*()520&/$6672&/$66,66(3$5$7('

3/8**('$77+(35(6685(%281'$5<%<7+,&.3/$7(



127(



7(0325$5<675$,1(56757%(/(0(17+$6%((15(029('



,17(51$/%/,1'6322/3,(&(6+$9(%((1,167$//(',13,3,1*3(5(&

18&/($56$)(7<5(/$7('



7+($67(5,6. :$686(',1$35(9,286(48,30(17,'(17,),&$7,216<67(0$7 5,9(5%(1'67$7,215()(5727+((48,30(17'$7$%$6(('%)257+(3523(5

&20321(17180%(5$1'6$)(7<&/$66,),&$7,21

6(7#

36,*

%

59 127(

&/

&/

&/

127(

&/

(

9)

%

3(

%

9

7

%%

)2%

029

(

%

(%%

(

9%

9%

5+6

9

127(

127(

127(

21(7,0('(9,$7,2172$6/()76(735(6685(72/(5$1&()25(59)%

$33529(')25&<&/(21/<3(5(&



28

V179 G36-VF062 V

V194 V193 G36-LT N018 G36-VF076 G36-VF061 PRECOAT TANK D

G36

• VFO36B

• AOV FO06B P-21 G36 CHEMICAL CLEANING CONNECTIONS SYSTEM TITLE SYS NO.

REFERENCES:

106 121 CONDENSATE MAKE-UP STORAGE & TRANSFER 403 603 609 HVAC-CONTAINMENT BUILDING AIR-SERVICE & BREATHING RADWASTE LIQUID DRAINS-FLOOR AND EQUIPMENT NOTES:

EXCEPT WHERE A DIFFERENT PREFIX IS SHOWN.

794E766AA REV. 0. THIS IS A GENERAL ELECTRIC SYSTEM.

4. FILTER HOLDER AND FILTER SHALL BE ATTACHED WHEN SAMPLE IS DESIRED THEN REMOVED.

3. THIS DRAWING HAS BEEN REDRAWN FROM GENERAL ELECTRIC COMPANY DRAWING NO.

1. ALL LINE, INSTRUMENT, VALVE, AND EQUIPMENT NUMBERS TO BE PREFIXED WITH "WCS-G36-VFO46 T

V118 G36-PNLP001 G36-TKA002 AGITATOR SUPPLIED WITH TANK RESIN FEED TANK G36-FO63 DUST COLLECTOR SUPPLIED WITH TANK FC FC AG1 G36-VFO45 G36-VFO25 G36-TKA001 PI RO12 FC PE G36-FG D004 F023 G36-AOV F052 G36-FV F021 G36-AOV FO20 G36-SET AT 150 PSIG AG2 G36-RV FO87 G36-G36-FG DO06B 3

FC G36

• AOV FO14B G36

• AOV F013B G36

• AOV FO15B V139 LMC V

KJB

• Z 5

SHIELD BLDG LMC V

CONTAINMENT PI 42B

• RV 154 (Z-)

AOV 110 2

2 V56

• V55 (Z-)

LMC V141 FC V180 V142 V140 P5B 10"X8" 3

• EJ2B(B-)

2 1/2"X1 1/2" (TYP OF 2)

V136 AUX BLDG TUNNEL RAD BLDG V131

• MOV 173

• MOV 172 (ZR)

• MOV 178 (ZB)

BACKWASH RECEIVING TANK PUMPS SET AT 150 PSIG LC SOV 110 G36-LT NO09 (ZB) 2 1/2"X1" (TYP OF 2)

FC V122 G36-PC003 TYGON TUBING V144 V119 T

FC RESIN METERING PUMP G36-PNLP001 G36-PCV FO89 G36-G36-PI RO13 PE F003A G36-AOV F022 G36-AOV FO24 REACTOR BLDG FL EL 162'-3" G36-PC002 REACTOR BLDG.

FL EL 162'-3" V231 FC

• V77

• V75

• V71

• V69

• V73 RM RM RM 3

T T

T

• V83 V79 V81 G36-

• VFO33A G36*VFO31A FC FC FC 2"X1 1/2" G36

• VFO34A DO13A RM PE PE G36-PT NO13A G36-PDT N004A G36

• RV FO81A

• V67

• V63

• V65 FC G36

• VF029A

• V128

• V130 G36*VFO18A

• STRT DO09A RM RM RM RM G36*VFO38A G36*VFO35A OUTLET INLET CHEMICAL CLEANING CONNECTION G36-FG DO05A G36*VFO37A RM 3

FC 3

RM G36*VFO36A FC G36

• VFO30A PT N015A G36

• STR G36*VFO32A PE G36

• VF069A G36*PCOO1A 3

G36

• FE N001A

• STRT 2A

• AOV FO16A G36

• AOV F008A G36

• AOV F007A G36

• AOV F005A G36

• AOV F006A G36

• AOV FO02A G36

-PDT NO17A G36

-PDT N016A HOLDING PUMP P-19

• V3000 V

SET AT 1410 PSIG G36 T

V133 PE PI 42A STRT 5A STRT 5B V137 V138 3

3 EJ6 EJ5 EJ4 PE EJ3 BACKWASH RECEIVING TANK G36*TKA003 V135 T

V134 P5A 3

FC FC 3"X2 1/2" G36

• AOV FO01A AOV 103 AOV 102 G36

• VFO17A SOV 103 SOV 102 3

3 G36-VFO58 G36-VFO73 G36-PNLP001 PRECOAT PUMP 4"X 3" V123 NOTE 8 G36-PI R011 G36-RV F085 G36-RV F084 G36

• AOV F004A G36

• FV SET AT 150 PSIG A-13 H-12 SET AT 150 PSIG FC G36-VF059 PCV 117 G36-PI RO18A G36-LE N012A G36-FG D007A DO11 3

G36

• DEMIN 3

FC FC CLEANUP FILTER DEMINERALIZER 3

G36-G36-FG D006A FC G36 N006A CES-PNL4

• AOV FO11A

• AOV FO12A

• AOV FO09A

• AOV FO10A

• AOV FO14A G36

• AOV F013A G36

• AOV FO15A G36

-FT N002A G36 G36 G36 G36 G36 FC G36-PI RO10 G36

• VF075 V143 V132 3

PE 10"X8"RED FC

• EJ2A(A-)

T G36-PNLP001 G36

-RV FO86 4"X2 1/2" 3

AOV 171 FC AOV 101 SET AT 150 PSIG V195 SOV 171 SOV 101 3/4" TUBING V

D 7'-6" MINIMUM V196 V197 3

DER-V301 DER-V300 9.2-21c(M-19) 9.3-7h(N-19)

DWG NO.

9.3-7h(J-6) 5.4-15a(C-20) 9.3-7a(J-18) 5.4-15a(A-19)

REACTOR BLDG FL EL 141'-0" 11.2-1d(N-7) 9.3-7g(D-15) 9.3-7h(N-20) 5.4-15a(B-19) 9.3-7a(J-18) 9.3-7b(N-5) 5.4-15a(D-20) 9.3-2c(L-13) 9.4-7b(L-20) 9.3-7a(J-20)

VALVE LINEUPS.

INFORMATION ONLY. CONSULT THE STATION OPERATING PROCEDURES (SOP'S) FOR ACTUAL VALVE POSITIONS DEPICT THE PLANT IN ITS NORMAL OPERATING MODE AND ARE FOR PIPE CAPS USED ON VENT, DRAIN, AND TEST CONNECTIONS THAT ARE NORMALLY ISOLATED FROM SYSTEM PRESSURE ARE NOT REQUIRED BY THE DESIGN FOR SYSTEM OPERABILITY.

ON Q-CLASS 1 SYSTEMS THEY ARE REQUIRED BY THE FSAR TO LIMIT LEAKAGE IF VALVE LEAKAGE OCCURS.

F011B G36 G36 G36 G36 1410 PSIG SET AT FO03B

• FV G36 FO01B

• AOV G36 FO02B

• AOV G36 FO12B

• AOV

• AOV FO10B

• AOV FO09B

• AOV DEMINERALIZER CLEANUP FILTER

• DEMN G36 NO16B PDT G36-G36*STRTDO09B

• V53

• V54

• V96

• V100

• V98 FC FC FC FC 6"X3" RM RM NO17B PDT G36-DO07B FG G36-FO81B

• RV G36 RM 3

3 DO12 6"X3" PNL4 CES-

• V110 KO01B I/P G36-NO02B

• FT G36

• V108 NO01B

• FE G36

• VFO32B G36 V3020B G36*VFO31B DO13B

• STR G36

• V102

• V104

• V106

• VFO34B G36 NO15B PT G36-RM RM NO13B PT G36-NO04B PDT G36-NO12B LE G36-NO06B ZS 3

FO04B

• AOV G36 T

G36*PC001B HOLDING PUMP F008B

• AOV G36 FO16B

• AOV G36 F007B

• AOV G36 F005B

• AOV G36 G36*VFO30B G36*VFO38B G36*VFO35B FC

• VFO37B G36 3

RM RM FC DO05B FG G36-INLET OUTLET 3

• V114

• VFO33B G36 G36*STRT2B 3

• V116 G36*VFO69B FC T

PE

• V112 G36*VFO17B G36*VFO18B

• VFO29B G36 RM RM T

PE PE L

21 20 19 18 17 16 15 14 13 12 11 10 9

8 7

6 5

4 3

2 1

21 20 19 18 17 16 15 14 13 12 11 10 9

8 7

6 5

4 3

2 1

J B

P N

M L

K H

G F

E D

C B

A P

N M

K J

H G

F E

D C

A 5.

6.

G36-PS N019 G36-FIC N020 FLUSH CONNECTION 9.3-1d(N-2)

-ZS 3

3 FIGURE SYSTEM P&ID REVISION22 UPDATED SAFETY ANALYSIS REPORT RIVER BEND STATION 5.4-15b 601 REACTOR WATER CLNUP & FILTER 26-03B AIR-INSTRUMENT 122 INTERNALS TO CHECK VALVE 1G36-VF073 HAVE BEEN REMOVED.

7.

SEE NOTE 7 V3015 9.2-21 9.3-1 9.3-2 9.4-7 11.2-1 9.3-6

2. THE ASTERISK "*" WAS USED IN A PREVIOUS EQUIPMENT IDENTIFICATION SYSTEM AT RIVER BEND STATION. REFER TO THE EQUIPMENT DATA BASE (EDB) FOR THE PROPER COMPONENT NUMBER AND SAFETY CLASSIFICATION.

NUCLEAR SAFETY RELATED G36-AOV VALVE IS DESIGNED TO FAIL CLOSE. HOWEVER ON LOSS OF AIR VALVE MAY NOT MAINTAIN PRESSURE BOUNDARY ISOLATION REQUIRED FOR MAINTENANCE.

VALVE SHOULD NOT BE UTILIZED AS A MAINTENANCE BOUNDARY WITHOUT 8.

GAGGING OR ENSURING AIR IS MAINTAINED TO THE ACTUATOR. REFERENCE NOTE 8 NOTE 8

NOTE 8 NOTE 8

NOTE 8 NOTE 8 G36 NOTE 8 NOTE 8 NOTE 8 NOTE 8 NOTE 8 NOTE 8 NOTE 8 NOTE 8 CR97-2119 AND CR97-0540.

STRT 3 RM RM RM RM VF074 V3020A

RBS USAR APPENDIX 5A Revision 28 5A-1 5A.0 CURRENT CYCLE OVERPRESSURIZATION ANALYSIS This appendix previously contained information on the cycle specific overpressure analysis.

This information has been removed but can be found in the cycle specific SRLR.