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Text

Forwards Response to NRC Request for Addl Info Re Fsar.Info Will Be Incorporated in Future Amend
	ML17266A489
Person / Time
Site:	Saint Lucie
Issue date:	08/19/1981
From:	Robert E. Uhrig; FLORIDA POWER & LIGHT CO.
To:	Eisenhut D; Office of Nuclear Reactor Regulation
References
	L-81-362, NUDOCS 8108250481
	Download: ML17266A489 (310)
	v • d • e

ION ISTRIBUTION S- EM (R IDS)

'EGULATORYWNFORMAT ACCESSION NBR i 8108250481 DOC ~ DATE;! 81/08/19 NOTARIZED;: NO DOCKET FAGILi050'89 st+ Lucie- Planti Unit 2'E, Flor ida Power L L'ight>> 05000389.

UHR NAME'~

I G p R, K',

~ NAMKI

'lorida AUTHOR AFFILIATION Power- L Light Co ~

RECIPIENT AFFIL>>IATION 'ECIP coB.'UTHB KiISKNHUT'~D.G, Division of Licensing SUBJECT Forwards- response to NRC, request for addi info. re>> FSAR~;I'nfo will be. incorporated in future'mend;.

DISTRIBUTIoN CODES BOO>>0 COPIES RECEIVED:LTR L EN'CL 'IZE:: 'g' PSAR/FSAR AMDTS and Re.lated Correspondence '-ITLKl:"

NOTES!

COPIES RECIPIENT COPIES ACT>>ION ~ '/O'I RECIPIENT'Di'ODE'/NAMEl CENSNG LICI BR ¹3 LA LiTTR ENCL>

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BR12'MRG EMRG PRP DEV 35 1 1 3 3 EQUIP, QUAL BR13>> 3 FEMA~REP DIV 39 1 GEOSCIENCES 28. ? 2 HUM FACT ENG 40 1 HYD'/GEOI BR 30 ~ 2 2 ILC SYS BR 16 1 1' ILE) 06 3>> 3 L'IC'UID BR 33 LIC'UAL BR 32! 1 1 MATL>> ENG BR 17 1 1 MECH. ENG BR 18 1 1 MPA 0.

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Q FLORIDA POWER & LIGHT COMPANY August 19, 1981 L-81-362 Office of Nuclear Reactor Regulation

+c i/g Attention: Nr. Darrell G. Eisenhut, Director Division of Licensing U. S. Nuclear Regulatory Commission Washington, D. C. 20555

Dear ttr. Eisenhut:

Re: St. Lucie Unit 2 Docket No. 50-389 Final Safety Analysis Report Re uests for Additional Information Attached are Florida Power 8 Light Company (FPL) responses to NRC staff requests for additional information which have not been formally submitted on the St. Lucie Unit 2 docket. These responses will be incorporated into the St. Lucie Unit 2 FSAR in a future amendment.

Very truly yours, Robert E. Uhrig Vice President Advanced Systems 8 Technology REU/TCG/cf Attachments cc: J. P. O'Reilly, Director, Region II (w/o attachments)

Harold F. Reis, Esquire {w/o attachments) pool g/~

z;:lkJ P>t A,...

t PDR ADOCK 8i0819 8i0825048i 05000389 POB PEOPLE... SERVING PEOPLE

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Attachments to L-81-362 A. Information on ECCS pump NPSH requested by N. Rubin on 8/3l/8l.

B. Revised responses to 492.7, 492.9 and 492.15 C. Additional information supplied in response to 490.1 D. Draft writeup on CEA Ejection with Loss of Offsite Power.

E. Revised response to 440.1, 440.5, 440.9, 440.14, 440.25, 440.39, 440.41 and 440.44 F. Draft Technical Specification for steam generator inspec'tion 3/4.4.6 G. Revised response to 251.8 and 251.10.

H. MEB review meeting list of confirmatory items.

I. Revised responses to 420.3, 420.4, 420.14, 420.54 and 420.56 J. Neeting minutes and commitments from 8/11/81 meeting on preservice ins pec t ion.

K. Flordia Power 5 Light Company position on feedwater hamner testing.

L. Record of conversation and commitments made. with the Accident Evalua-tion Branch (Malt Pasedag) on 8/18/81.

H. Documentation and proposed FSAR revisions to incorporate additional underground cable data.

N. St. Lucie Unit 1 (proposed St. Lucie Unit 2) design criteria to be used for reevaluation of the masonry walls per SEB question 220.37

0. Revised response to 430.49 8108250481

REcl.aCvt.AvZOM PUMP hPSH DATA C.ohJTAXAME.MY SPPAY PvvP Elevation of Pump Suction, Ft -6.bd -6.43 Elevation of Source, Ft 21.$ 2 2J.42 Fluid Temperature, F 240 Fluid Vapor Pressure, Ft 60. 9 Head Loss Due to Friction, Ft 3.5 J,5 NPSB Available, Ft 24 5 26.35 hPSH Required at Pump Runout, Ft QO. 2l.o The following formula is used:

8 P S H (available) Pt Pv Pa + Ps + Pe Pi Pv where: Pt ~ pressure at pump suction centerline Pv ~ vapor pressure of pumped water Pa ~ air pressure Ps = steam pressure Pe ~ elevation pressure

~ Head loss due to friction in the suction piping.,

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2/ re&~'g~OA~' F 548 553 OPC h,'reactor ndeler temperature, F 5.I 611.2 612.5 595.7 Number nf loops 5.1 Design pressure, psig 2 '85 5.1 .2,485 2,485 2,485 Design Temperature> F 650 5.1 650 650 650 e /
Hydrostatic test pressure (cold), psig 3>110 5.1 3,110 3,110 3,110
~
Princi al Desi n Parameters of the Reactor Vessel Haterial See Table 5,2 3 5,2 See Table 5.2-2 Sh 533> Grade B ~ Sh 533, Grade B, Class I, low Class 1, low alloy steel, alloy steel, internally clad internally clad with Type 304 with Type 304 austenitic SS austenitic SS
~
Design pressure, psig 2,485 2>485 2,485 2,485 Design temperature, F 650 4.4 650 650 650 Operating pressure, psig . 2>235 4.4 2>235 21235 2,235 Inside diameter of shell, in. 172 5.3 172 157 172 Outside diameter across noxsles> in. 253 5.3 253 238 253 Overall height of vessel and enclosure head, 41-10 3/8 5.3 ~ 43-6-1/2 43-4-1/6 41-11-3/4 ft-in. to top of CEDM nosxle Hinimum clad thickness, in. 1/8 5.3 1/8 1/8 5/16 Princi al Desi n Parameters of the Steam Generators Number of Units 5.4
SL2- FSAR TABLE 4.4-7
. RCS FLOWRATES Flow Path Flow (ibm/hr)
Total RCS flow 139.P' 10 Core bypass'low 5+x l 10 Core flow 134.3 x 10 6
Hot leg flow 69.)f x 10 Cold leg flow~ 34. x 10 Qs-
T'inlet ~ 548 F 4,4 46
(
SL2- FSAR TABLE 4.4-10 REACTOR COOLANT SYSTEM CONPONENT THER.'fAL AND HYDRAULIC DATA
~Coo anent Data Reactor Vessel Rated core thermal power, MWt 2560 Design pressure, psia .2500
,Operating pressure, psia 2250 Design temperature, F 650 Coolant outlet'emperature F ,$ 46~ gt..
Coolant inlet temperature 548 Coolant outlet Subcooled state'otal, coolant flow, ibm/hr 139;f x 10
'ore average coolant enthalpy Inlet, 545 Btu/lb Btu/lb'utlet, 610 e
Average coolant density Inlet, Ib/ft3 3 47.0 Outlet, lb/ft 43.4 Steam Generators Number of units g~h~ t',t side {tube side)
+'~~
Design pressure/temperature; psia/F 2500/650 Operating pressure, psia 2250 Inlet temperature, F Rh'-4 5 gg Outlet temperature, F 548 ~
Flow rate, 10 lb/hr - 61 Design pressure/temperature, psi;a/F 1000/550 Operating pressure/temperature, 815/520.3 psia/F (warranted)
To)al steam flow per generator, ~
5. 603 10 lb/hr Steam quality, 99.8 4.4-52
TABLE 4.4-10 (Cont'd)
~Com onent Data Pipe size ( inside di arne ter), in.
Hot leg 42 Suction leg (cold leg) 30 Discharge leg (cold leg) 30 Design pressure/temperature, psia/P 2500/650 Operating pressure/temperature, psia/F Hot leg 2250/Se m Cold leg 250/548
.a. Full power conditions 4,4<<54
SL2-FSAR TABLE 5.1-1 DESIGN PARAMETERS OF REACTOR COOLANT SYSTEM Design Thermal Power, Mwt (Including net heat addition from RCP's) 2570 Thermal Power, Btu/hr 8.77x10 tk.sign Pressure, 2500 psia'esxgn Temperature (exrept Pressurizer), F 650 Pressurizer Design Temperature, F 700
'f 6 Reactor Coolant Flow Rate, lb/hr 139. x10 O~~f e~ 548 Cold LegATemperature, F
+~ a~WAve rage~'Fempe rapture,: .Fi.'-. . 572/
fi'~
1 I
~
C)(era Hot Leg+Temper8ture, F ~MS 9c Normal Operating Pressure (psia) 2250 5.1-3
4 60 59 hot 580 5 7R.
570 A
LAJ
'I average 560 I-I 550 548.
OC ED L
CJ cold 540 532 530
'520 0'5 50 STEAN GEt/ERATOR POWER, ~
75 loo FLORIDA POWER 8 LIGHT COMPANY ST. LUCIE PLANT UNIT 2 TEMP ERATURE CONTROL P ROGRAM FIGURE 4.4-)0
SL2 PSAR TABLE 5.1-3 PROCESS DATA POINT TABULATION SOCn 2A1 RCP 2hl R.Ve RCP 2A2 S.ue 2Bl RCP 281 RCP 282 Parameter peuuuutitee ~xid int Outlet ~xid oint Outlet ~xsd oint outlet outlet Data Point Pigures 5.1-3 and 5.1-4 2 3 4 Pressure, psia 2250 2237 2296 2277 2296 2237 2296 2295 Teaperacure, P 653 .372)( S46 372d774 548 372+ 548 548 Aass Plow Race, E 5 S iblnr 69.7]{x!0 34.6/x!O 139.4)xlO 74.6/x!O 69.7+16 3>> 9)bid .34 8)PI06 Voluaecric Plow Race, gpss 1919850 92,500 3839700 929500 1919850 92 ~ 500 92 ~ 500 lA sdl 8
63e 8
O n
o
(D uestion In Subsection 7.2.1.1.2.4, Analog Core Protection Calculators, you state that analog computers provide input to thermal margin/low pressure tr ip, .the local power density trip, and the high power trip.'ou further state that a calculated low pressure limit related to departure from nucleate boiling ratio {DNBR) is determined using preset coefficients as a function of the measured cold leg temperature, axial offset, and the higher of the thermal power or neutron flux power. This calculated low pressure limit is an input to the thermal margin/low pressure trip. Provide the functional relationship of the low pressure trip setpoint and the above parameters; and describe h'ow these functions are obtained.
Provide information to indicate the similarity of the Analog Core Protection Calculator used for St. Lucie Unit 2 to that used in St. Lucie 1. St. Lucie Unit 1 is currently under review for the next cycle reload since a statistical combination of uncertainties (SCU) is proposed in conjunction ooth calculations used in the Analog Core Protection Calculator. Is this same approach planned for St. Lucie Unit 2 currently or for, future cycles?
Answer (~ee pe+ p~e)
r Answer 9'72
'I a) The functional relationship for the low pressure trip setpoint is:
= e TC + g
~ ~
Pvar ~
A1 gR1 g where:
P var
= calculated low pressure limit, T measured cold leg temperature,
<~p, p== scfq:+ c NP; i 4s)
C function of axial shape index (see attached figure),
gR1
= function of the higher of the thermal power or neutron flux power.
attached figures show A1, gRI, a, 8 and y for St. Lucie Unit 1
'he
~
2560 MWt. At present these are the targets for St. Lucie Unit II.
This analysis is currently underway as part of the St. Lucie Unit II Technical Specification effort(+~ g~ ~~(~~ Q> ~.-f A general discussion of the methodology used to generate the Thermal Margin/Low Pressure (TM/LP) LSSS is contained in CENPD-199-P "C-E Setpoint Methodology," with further information available in "Response to First Round questions on the Statistical Combination of Uncertainties Program, Part 1 and Part 3 (CEN-124(B)-P." Per NRC request, C-E is currently updating CENPD-199 P for final NRC review and approval.
-b) The attached functional diagrams for the St. Lucie Unit 1 (FSAR Figure 7.2-14) and the St. Lucie Unit 2 (FSAR Figure 7.2-5) Thermal Margin trips show that these calculators are functionally identical.
c) Application of statistical combinations of uncertainties for St. Lucie Unit II is not now planned for the first or future cycles; however, it may be applied in future cycles after NRC approval.
1.40 t ~ ~+ ~ ~ ~ ~ ~~ ~ 04 ~
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~ O.G .O.n 0.2 0.2 O.n O.G AXIALGI )A)'E INDEX, Yl t 2 FIGURE 2.2-3 I n)ermal Margin/Low Pressure Trip Setpoint
~ I
~
Part 1 (YI Versus A1)
~ ~
I
~ 'I ~ ~
~0 N ~
VfHEBEt A> x QR1 Q os
'ND '>~>< ~ 1765 x Qow+ + 14.13T<< - 7586 1.0 0.54 1.0 ==-=
0.8 0.6 0.4 0.32 0.2 OA 0.6 0.8 1.0 FRACTION OF RATED THERMAL POY(ER Thermal Margin/Low Pressure Trip S tooint Part 2 (Fraction of RATED THER.'ilALPOi')ER Versus QR1)
~ .o
~ ~
ST. LUCIE Ui'lIT g,
~ ~
0
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cn W 0 S3: FLOYD DEPENDENT SETPOINT 5=LECTOR SV~ITCH IN RPSCIP 2.cg 0 'C POSITIONS - I. 4 PUMiPS f 3 2. 3 PUMPS
~
Q ~ 3. 2 PUMPS - OPP. LOOPS 0 z 4. 2 PUMPS - LOOP l 0 ~ S3{RPSCIP)
5. 2 PUMPS - LOOP 2 A
0 ICAL PTCAL
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"U CY IV PiP SCIL) 0 AXIAL OFFSET I
0 Y 0 CAL QRI AXIALFUNCTION ~PvCa
]~~~as (CONT Q ~DNB B" LO'>>')
S" (RPSCIP)
CEA FUNCTION ~33 4~ i TRIP CALCULATION:
P VAR MAX ALARM: VAR DNB ~ CAL
{ABOVE) SEL WHERE TCAL TC+KCB, Q ~MAX (O,B)
PRETRIP PRETRIP TRIP UNIT TP.IP: TRIP VAR' IN P = PRIMARY 7 P < PTPIP MIN 0 "i. c<UgE 'RP
'RETRJP
0 Cy S3: FLOW DEPENDENT SETPOINT SELECTOR SWITCH lN RPSCIP POSITIONS- l. 4 PUMPS z
',~ 3 2
2. 3 PUMPS
3. 2 PUMPS- OPP. LOOPS
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~
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5- (RPSCIP)
CEA FUNCTION ~42 3
I TRIP CALCU.l.ATION:
'PVAR MAX ALAPA: VAR DNS P CAL
'(A8OVE) SEl.
PRETRIP WHER PRETRIP TRIP CAL C+
IOO UNIT TP.IP:
7 P
'X~VAR MIN)
C8'RIP MIN P = PRIMARY <PTPIP PP.ESSURE PRETRIP TRIP
~
uestion ~
In Subsection 7.2.1.1.2.4, Analog Core Protection Calculators, you state that analog computers provide input .to thermal margin/low pressure trip, the local power density trip, and the high power trip. You further state that a calculated low pressure limit related to departure from nuc1eate boiling ratio {DHBR) is determined using preset coefficients as a function of the measured cold leg temperature, axial offset, and the higher of the thermal power or neutron flux power. This calculated low pressure limit is an input to the thermal margin/lou pressure trip.~)provide the functional relationship of the 'low pressure trip setpoint and the above parameters; and describe h'ow these functions are obtained.
lo) Provide information to indicate the similarity of the Analog Core Protection Calculator used for St. Lucie Unit 2 to that used in St. Lucie 1. St. Lucie Unit 1 is currently under review for the next 'cycle reload since a
~ ~
statistical combination of uncertainties (SCU) is proposed in conjunction
~ ~ ~ ~
with calculations used in the Analog Core Protection Calculator. c) Is this
~ ~ ~
same approach planned for St. Lucie Unit 2 currently or for future cycles?
~ ~
Answer The Analog Core Prot ion Calculator used zn St Luc.ie ni't it 2 2 i functionally is identical to that used > t Lucie.Unit l.
S ONj The Statistical Combination o +ncert inties(methodology can be applied to St, Lucie Unit 2. d'C'elis not~Wrre ly employedz how auar> If ~~f 4c.
JC.dc4 L +e a~4& gC~ (w as a>4'~ W 2y+ 4ffd/a,
e SL-2 Round One uestions 492.15 Provide justification for using the Macbeth correlation in the CHF (15.0) correlation for Chapter 15 transients. Do the applicability ranges of the correlation cover all expected conditions?
~Res onse:
The Macbeth correlation (Ref. I) is used only for the determination of DNBR during the post-trip return to power portion of the main steam line break (NSLB) transients presented in Appendix 15A of the FSAR.
('lots of DNBR versus time for these transients have been furnished in the Response to guestion 440.14). For all other Chapter 15 tran-sients the CE-I correlation is used in the TORC code (References 2 and 3) to calculate DNBR. For determination of DNBR during the post-trip return to power portion of NSLB transients the methods applied by Lee (Ref. 4) are employed in order to use the thcbeth correlation for rod bundles to predict burnout as a function of axial height, accounting for non-uniform axial heat flux.
Macbeth demonstrated that five parameters were necessary for correlation
= of critical heat flux (CHF) data for rod bundles with vertical upf low:
mass channel flux, G; inlet subcooling, hH; pressure, P; heated diameter, dh, and lenght, 1. However the channel length is eliminated from the correlation by application of Lee's method to predict CIIF as a function of axial height. To determine applicability, the height at which minimum DNBR occurs is compared with the channel lengths for the experiments from which Macbeth drew his data.
The data used for the Macbeth rod bundle correlations with vertical upflow has a range of'alues for G of from 0.18 to 4.1 million lbm/hr ft2 (Ref. 5). The uniformity of the correlation of the CHF data for rod bundles as a function of G over this range and the data and correlations for CHF in heated tubes give confidence to extend the lower end of the range of applicability of the rod bundle correlation to at least 0.09x 106 Ibm/hr ft~. (The Macbeth correlations for heated tubes are based on data for 0.01 < G x 10 -6 < 7.8 lbm/hr ft2.)
The range of values of hH upon which the rod bundle correlations is based is -150 < hH < 380 BTU/lbm (Ref. 5). The rod bundles from which the CHF data was obtained had values of dh between 0.113 and 0.902 inches and lengths of. from 17 to 72 inches (Ref. 1).
The data used for the rod bundle correlations is all for 1000 psia.
However application of Macbeth's correlations for heated tubes indi-cates that using the correlation developed for 1000 psia at lower pressures produces values for DNBR which are conservative. Further, other correlations for rod bundles, such as those of Bowring (Ref. 6),
yield a variation in DNBR of the order of 10$ as pressure varies from 500 to 1000 psia for the range of G and hH of interest. This is of the same order as the uncertainty in Macbeth's correlation and is much smaIler than the margin to DNB calculated for the post-trip return to power portion of the MSLB transients presented in the FSAR.
Table 492.15 suomerizes the above applicability ranges and compares them with the values of'he parameters obtained for the MSLB transients presented in Appendix 15A of the FSAR. The applicability ranges cover all the expected conditions for the post-trip return to power portion of these MSLB transients.
References:
l. Macbeth, R. V., "An Appraisal of Forced Convection Burn-out Data,"
Proc. Instn. Mech. En rs, Vol. 180, Pt3c, pp 37-50, 1965-66.
2. "TORC Code - A Computer Code for Determining the Thermal Margin of a Reactor Core," CENPD-161-P, July 1975, Proprietary Information.
3. "TORC Code - Verification and Simplified Modeling Methods,"
CENPD-206-P, January 1977, Proprietary Information.
4. Lee, D. H., "An Experimental Investigation of Forced Convection Burn-out in High Pressure Water-Part IV, Large Diameter Tubes at About 1600 psia," A. E. E. W. Report R479, 1966.
5. Macbeth, R. V., "Burn-out Analysis - Part 5: Examination of Published World Data for Rod Bundles," A. E. E. W. Report R358, 1964.
6. Bowring, R. W., "A New Mixed Flow Cluster Dryout Correlation for Pressures in the Range 0.6 - 15.5 !IN/m 2 (90-2250 psia)-
For Use in a Transient Blowdcr~~n Code," I Mech E Conference Publications 1977-8, pp 175-182, 1977,
~ ~
Table 492.15-1 Comparison of applicability ranges for Macbeth CHF correlation for vertical uplfow in rod bundles with values obtained for the MSLB transients presented in Appendix 15A of the SL-2 FSAR.
Range of Values A Obtained for MSLBs Parameter Range of Availability During Post-trip
Return to Power.
G (10 6 ibm/hr ft2) 0.09 - 4.1 0.09 -. 3.0 (.16) hH {BTU/ibm) -150 - 380 'I00 - 250 {244)
P (Psia) 500 - 1000 545 - 960 (956) dh (inches) .113 - .902 0.471 (inches) 17 - 72 22 - 33 (26)**
Values in parenthesis are those for minimum DNBR predicted.
Height at which minimum DNBR is predicted to occur.
High burnup performance experience, as described in Subsection 'ias p ovided evidence that the fuel will perform satisfactorily under design conditions. The current core design bases do not include a specific re-quirement for testing of irradiated fuel rods. However, the fuel assembly design alloi:s disassembly and reassembly to facilitate such inspections, should the need arise.
A fuel rod irradiation program has been developed to.evaluate the perform-ance of fuel rod designed for use in the 16 x 16 fuel assembly. The pro-gram includes the irradiation of six standard 16 x 16 assemblies, two each for 1, 2, and 3 cycles, respectively, n the Arkansas Nuclear One-Unit 2 reactor (ANO-2). Each ssembly will contain a minimum of 50 precharacter-ized, removabl rods distributec within the assembly to obtain a spectrum of exposure levels for evaluation purposes in the interim and terminal examinations. Interim examination of all six assemblies is planned dur'ng refueling shutdowns after each cycle.
Th'e ANO-2 fuel rcd and specific compcnents of the fuel rcds have received a detailed pre-characterization. The program calls for substantial clad-
- ding characterization to include m chanical properties, texture, hydride orientation and out of reactor low strain rate behavior. In addition to the ID and OD dii ensional data normally obtained on the clad tubing material, a minimum of 300 fuel 'rods will be measured to obtain as loaded dimensions. Suf ficient fuel rods will be profiled to obtain diameter and ovality measurements such that changes in these parameters can be tracked by similar measurements during interim inspections. Also, a random selec-tion of appro..im"tely 100 UO pellets from each lot per. batch used vill be characterized dimensionality and the density distribution vill be deter-mined. About one half of these pellets will be placed in known axial locaticns in selected fuel rods wliile the remainder will be set aside as archives.
A poolside non destructive examination vill be made during each of the Pfirst three refuelingSat ANO-2. Tne six 16 x 16 asseiablies with character-ized rods will be removed from the reactcr at each refueiing and moved to the spent fuel pool for leak testing (if failed fuel is in the core) and for visua1. inspection. The length of the a"sembly and peripheral rod" will be measured. During the shutdown, a target of 20 pre-charactPrized rod" per batch will he scheduled for examination and mPasurement. At some time
~
after the refueling outage, pre-characterized'ods retained in discharged assemblies will be measured. A target of 100 rods will b" eddi testerl aftP Pacli shutdni.w. g Z,~
8+
A -ost Y irradiation aeL surv e Lllance ~gram for St Lucie=Knit 2 is, being planned. Spec'~e requirements th~P. pl "n vill Je-'determined bhsed on the results f the ANO-2 Dr" an. ~ liow'.acr F!~24~r: irrontlv ~lans to when the oui~ assemblics apl~re-.ovo<l Pw friz the Dre Old Dlac. d in t e spent fuel stor-gi. pool.
s >n.3 (,
I
%s
SL2-FSAR 4.2.1.5 Surveillance Pror ra 4.2.1.5.1
~ ~ ~ ~ Requirements for Surveillance and Testing of'rradiated Fuel Rods High burnup performance experience, as described in Subsection 4.2.3 has provided evidence that the fuel will perform satisfactorily under design conditions. The current core design bases do not include a specific re-quirement for testing of irradiated fuel zods. However, the fuel assembly design allows disassembly and reassembly to facilitate such inspections, ~
should the need arise.
A fuel rod irradiation program has been developed to evaluate the perform-ance of fuel rod designed for use in the 16 x 16 'fuel assembly. The pro-gram includes the irradiation of six standard 16 x 16 assemblies, two each for 1, 2, and 3 cycles, respectively, in the Arkansas Nuclear One-Unit 2 reactor (ANO-2). Each assembly will contain a minimum of 50 precharacter-ized, removable rods distributed within the assembly to obtain a spectrum of exposure levels for evaluation purposes in the interim and terminal examinations. Interim examination of all six assemblies is planned during refueling shutdowns after each cycle.
The ANO-2 fuel rods and specific components of the fuel rods have received a detailed pre-characterization. The program calls for substantial clad-ding characterization to include mechanical properties, texture, hydride orientation and out of reactor low strain rate behavior. In addition to the ID and OD dimensional data normally obtained on the clad tubing material, a minimum of 300 fuel. rods will be measured to obtain as loaded dimensions. Sufficient fuel rods will be profiled to obtain diameter and ovality measurements such that changes in these parameters can be tracked by similar measurements during interim inspections. Also, a .random selec-tion of approximately 100 UO pellets from each lot per batch'used will be characterized dimensionality and the density distribution will be deter-mined. About one half of these pellets will be placed in known axial locations in selected fuel rods Wile the remainder wi)l be set aside as archives.
A poolside non destructive examination will be made during each of the
'~~first three refuelingSat ANO-2. The six 16 x 16 assemblies with character-ized rods will be xemoved from the reactor at each refueling and moved to the spent fuel pool for leak testing (if failed fuel is in the core) and for visual inspection. The length of the assembly and peripheral rods will .
be measured. During the shutdown, a target of 20 pre-characterized rods per batch will be scheduled for examination and measurement. At some time after the refueling outage, pre-characterized rods retained in discharged assemblies will be measured. A target of 100 rods. will be eddy current tested after each shutdown. Z<~s g7-Y~~R: &1&~q g A post xrradiatpdn fuel surveys ance program o
~ a~~~~
Sacr'.Eic requireme~ts of the plan wild~be determined bus d on,.
,planned.
the resul fono tAti
~
of the ANO-2 program. However~+PSL currently pfanS to per-iospootioZ<pre~ram
~
Qc~sYcJck rool <ocro io 3 Cz init core when thWfuel. assemble,are removed fr t'e core an~laced
~
~o e:.spent fuel;-storage pool. ~
" =-"..=
ma'~L 4,2-30
A post irradiation fuel surveillan'ce program for 54lucre 4+/ is planned.
,This program shall consist of a visual inspection of a minimum of six .irradi-ated assemblies prior to replacement of the Reactor Vessel Head at each of the first three refueling outages. The six assemblies inspected shall con-sist of two assemblies of 'each fuel type and will be from core locations which are non adjacent. Visual inspections shall consist of viewing the top and sides of each fuel assembly via an underwater TV Camera or Periscope.
The visual inspection will include observation with special attention to gross problems involving cladding defects, spacer grid damage and other major structural abnormalities. No special measurement devices for these affects are intended to be provided for'his visual inspection.
If major abnormalities are detected during this visual inspection or if plant instrumentation indicates gross fuel failures," the fuel vendor will be in-formed and further inspections shall be performed. Depending on the'ature of the observed condition, further examination could include fuel sipping, single rod examination, and other examinations. The 16 x 16 fuel design en- .
ab)es reconstitution. Individual fuel rods and other structural components may be examined and replaced, if required. Under unusual circumstances, de-structive examination of a fuel rod may be required but this would not be accomplished on site or during the refueling outage.
The NRC shall be contacted regarding gross fuel failure detec'ted by plant in-
'strumentation or major abnormalities observed during the post irradiation in-
.spections described above.
The post fuel irradiation fuel surveillance program shall be continued the first three cycles of operation of Sf:Lu;.el';$ ~, Six assemblies fol-'owing shall be visually inspected during each refueling outage, not necessarily prior to replacement of the reactor vessel head. The visual inspection shall consist. of viewing the tops and sides of each fuel assembly via an underwater TV camera or periscope. The visual inspection will include obser-vation with special attention to gross problems involving .cladding defects, spacer grid damage, and other major structural abnormalities. The NRC will be notified of major abnormalities noted as a result of these inspection activities.
15.C.3
~ ~ CEA Ejection with Loss of Offsite
~
Power.~
The. following CEA ejection cases were requested t , b an lj'zed without offsite I
power: ~
(1) CEA ejection with control element h u i g upture and subsequent rapid blowdown into containment.
II (2) CEA ejection where the control element housing does not rupture and the primary system leaks to the secondary system through leaks in the steam generator tubes.-
The analysis of a CEA ejection with a rapid blowdown into containment is pre-sented in Section 15.4.5.1. This analysis also assumed a failure of the 4.16 KY bus to fast transfer following turbine trip. The main impact of this is the assumption that the condenser is unavailable for one hour. The analysis of a CEA ejection where the housing does not rupture is discussed in this'section.
This case was analyzed without offsite power.
Figures 15.C.3-1 and 15.C.3-2 are the pressure versus time curves for primary and secondary side pressures, respectively. Table 15 AC.3-1 presents information associated with radiological release calculations.
Table 15.C.3-1 CEA Ejection with Loss of Offsite Power Radiological Release Information
l. Steam Released to Atmosphere During Cooldown (ibm) 0 - 2 hours:
NSSYs 74400'51
':ADVs 000 Entire Event; NSSVs 74400 ADVs 572000
2. Fuel Pin Failure (/) 9.5 (See Section 15.4.5.1)
3. Primary Iodine Concentration 8.3 x 103 Based on 9.5% Failed Fuel (pCi/gm).
4. Secondary Iodine Concentration
.Based on Tech. Spec. Limits (pCi/gm).
5. Decontamination Factor for 10 Steam Generator Iodine Transport
6. Two Exclusion Boundary 16.7 Thyroid Dose from Secondary Releases (Rem).
0 gazoo I+OP gaoe izOd lc Oo p-sn)g, 5F C'nMbX
1050 1000
~ 950 K
D 900 0
. ~ ~
~ K Q
~ ~ ~ ~
~~ ~ ~
850 UJ I
800 750 0 100 200 . 300 500 TIME, SFCONOS
\ ~ ~ ~ ~ ~ ~ ~ ~ ~
FLORIDA P O>U 5 R 8 LIGH T COMPANY ST. LUCIE PLANT UNIT 2 STEAM GEH. PRESSURE ij'S. TIME
XP5+L 7 8 " Gsppnce+ ~+a'I) g ~(g(
NI On the basis of experience, thehT value of 100'F used in the analysis is larger than any hT that might be expected during plant operation. During RCS cooldown using the shutdown cooling sy'tem, coolant circulation with the reactor coolant pumps serves to cool the steam generator to keep the temperature difference between the reactor vessel and the steam generator minimal.
a Steam dumps are used to reduce steam generator secondary fluid to below 220'F. If the steam generator were held at 220'F and the reactor vessel were cooled to the refuelinq temperature, the steam generator - reactor vessel AT would still be less than 'l00'F. In fact, procedures will direct the operator to maintain the h,T below approximately 20 F.
Q LTOP transients have not been analyzed for the simultaneous startup.
of more than one reactor coolant pump (RCP). Such operation is procedurally .precluded, since the ooerator starts only one RCP at a time and a second RCP is not started until system pressure is stabilized. Additionally, there is an LTOP transient alarm that should indicate that a pressure transient is occurring and that a second RCP should 'not be started.
The results of the analyses provided in Figures 5.2-24 and 5.2-25 show that the use of the PORYs provide sufficient pressure relief capacity to mitigate the most limiting LTOP events identified above.
A Technical Specification will be written to require 2~5-'~ RA if
~ mfa.o~~
the bT exceeds 100 F. However, as mentioned above, r~f administrative procedures will ensure that the hT is maintained
~l<<l>f below approximately 20 F.
gCJiSr'rrL.
Also, a Technical Specification will be written to ensure that appropriate action is taken if one PORV is out of service during the LTOP mode of operation.
J
'L2-FSAR e
capabi) ity to determine heat removal, coo)down rate, shutdown cooling flow, amd the capability to detect. degradation in the f)ow or heat removal capacity. The instrumentation provided for the SDCS consists of:
e
1) Temperature measurements - Shutdown coo)ing heat exchanger inlet and the temperature of the shutdown cooling f)ow to the )ow pressure header. A).1 temperatures are indicated in the cohtrol room. The shutdown cooling heat exchangers'nlet temperature, and the low pressure header temperatures are recorded to faci)itate control'f the Reactor Coolant System coo)down rate.
2) Pressure Heasurement.s - LPSI header pressure and shutdown cooling heat exchanger inlet pressure. These pressures are indicated in the control room, and, when used with the ).ow-pressure pump performance curves, provide i e an al>>
ternate means of measuring system flowrate.
3) Plow Heasurements - Total shutdown cooling flow rate xs measured by flow indicator/control)ers FIC-3301 and 3306.
The instiumentation is discussed further in Sections 7.4 and 5e4.7.2.3 Overpressure Control 7.6.'ction is provided by relief valves and
~ ~
againstoverpressure of the SDCS rlocks. A ~ description of relief valves is provided
~
below and in Sub-section 6.3.2.2.6.1.
~ ~
There are six relief valves in the SDCS suction lines. These valves are sized to protect the components and piping from overpressure due to thermal expansion of the fluid. Valves V-3482 and V-3469 have a set pressure of 2485 psig and a capaci:ty 'of five gpm. Relief fluid from these valves is collected in the quench tank. These va)ves are located in Sections E-4 and D>>5 of CE P&ID E-13172"310-131 and are deeiened to 1974 AS>E, Section NBGuelity Group A(~ee F~ure.
Valves V<<3483 and V-3468 have a set pressure of 335 psig and a capacity of 155 gpm. Relief fluid from these valves is collected in a holdup tank in the Mast.e Hanagement System. These valves are located in Sections D-7 and D-6 of CE P&ID E-13172-310-131 and are designed to 1974 ASHE, SeCtion BC, Guelity Group B(za ep;~a re. '4 y /S) ~
In addition to protecting the components and piping from overpressure due to the thermal expansion of the fluid, valves V-366 an are size d to'ro to'otect ec the components and pip-ng from overpressure due to ina d verrtent en starting of the chargi'ng pumps, HPSI pumps, s and p ressurizer an heaters, These valves have a set. pressure of 335 psig an d a ca p ac1t y e
2300 gpm. m. Relief e xe 'fIuid col)ected from these valves is collected th e cono tainment sump. These valves are located in Sec t ions C-6
>d D-6 of CE P&ID E-13172-310"131 and are designed to 1974 ASSHE Section YC (too 1975 summer addenda) Quality Group B Mhen calcu)ating the capacity of valves V-3666 and V-3667, the cap. sty o e s<~ F'q~ 0
~
3-l<)
5e4-24 Amendment No. 4, (6/81)
SL2- FSAR 9Vo ( e(~$8~
TMo-manual~cefa 1 eJ ormally after the SITs
~~ .
are ovine either.
RCS depressurization isolated or dcpressurized.
is carried on
~ Primary Boration and Inventory Makeup The St ~ Lucie Unit 2 design incorporates three safety grade charging pumps (Seismic Category I , ASME Code o e Class 2), redundant safety grade charging pump i
i" Category I ASME Code Class 2 boric acid ma e-up an s),
redundant charging pump suction paths, and redundant charging n um deliver pump e very paths. The charging pumps and all related automatic control valves are connected to vital power if the normal power supply system should fail,'xcept 1 V-2504 harging pump suction from, the RMT. During the lant cooldown, the charging system borates the RCS to cold shutdown boron oron concentration and.accommo d . d a t es the reactor coolant shrinkage, taking suction from either the boric acid makeup or refueling water tanks. The minimum i
amount of storedd b or c ac id so lution
'is u that is maintained in either boric acid tank sufficient to bring the plant to a safe shutdown condition. The capability of the Chemical and Volume Control System (CVCS) to borate and to makeup is not compromised by stopping letdown flow. An analysis of boration without letdown hhas bbeen comp 1 ete an is confirmed in FSAR Subsection 9.3.4.3.
ted and A single failure of one emergency power train would leave at least one charging pump opera bl e on th other emergency power train. One charging pump still 1 al11 ows t h e RCS to o be borated to a cold shutdown boron concentration within the two hours ours thata thee . plant is initially held at hot standby, even without the letdown system operable. Thus, the charging ssysstem satisfies the single failure criteria. See FSAR Subsection 9.3.4 for more information.
4. Secondary tfakeup During cooldown, the auxiliary feedwater system (ASS) and atmospheric dump valves provi e.a means o bri n'g the reactor coolant system temperature down to the shutdown cooling system entry temperature- The auxiliary feedwater
~
pump(s) are started and the safety grade auxiliary feed isolation valves,
~
5 9, -10 -11, -12, are opened from the control room. The auxiliary feedwater system is designed such that no single active failure coupled with a loss of offsite power, prevents plant cooldown. A failure modes and effects analysis i.s provided in the. St. Lucie Unit 2 FSAR Table 10.4.3.
The APTS contains one steam driven and two motor driven auxiliary feedwater the b i,t driven or lf i either apable of maintaining the RCS in hot standby.
of the motor driven auxiliary feedwater pumps Also, steam is capable of delivering enough feedwater condensate for a plant cooldown.
The APTS is designed to safety grade requirements {Seismic Category I Safety 1 3 AS'K C d Section III). Each of the motor driven auxiliary feedwater
~
pumps utilize a Class lE ac safety related power supply and the turbine d i pump train relies strictly -on dc power supply. Xf the motor driven auxiliary h
. 5.4-28e Amendment No. 4, (6/81)
)
SL2- FSAR +9o (
NCH POSITION e preoperational and initial start'up test program shall be in conformance with Regulatory Guide 1.68 tests with supporting analysis to (a)
'he program for PHRs shall include confirm that adequate mixing of borated water added prior to or during cooldown can be achieved under natural circulation conditions and permit estimation of the times required to achieve such mixing, and" (b) confirm that'he cooldown under natural circulation conditions can be achieved withi'n the limits specified in the emergency operating procedures. Comparison with performance of previously tested plants'f similar design may be substituted for these tests.
RESPONSE
The preoperational and startup test programs will conform the Regulatory Guide 1,68 (R2). Boron mixing under natural circulation conditions, will be demonstrated in a prototypical test at the San Onofre Nuclear Generation
~50>MS~ 1 g ~~~4 o F Htt's $4'IVY~ a~/ ~i ~ e 4"cpot hl c.
4Mc. W~'i 2. Ps8P A natural circulation test and simulator training will be performed for St.
Lucie Unit 2 to demonstrate the capability of cooling the plant to shutdown cooling system initial conditions within several hours under minimum cooling
'istaff capability. A detailed plan will be reported to the NRC in a forthcoming FSAR amendment. St. Lucie Unit 1 submittals to the NRC concerning Natural i culation cooldown have been reviewed with resPect to th'eir aPPlicability to Strhueie Unit 2. Xt is FPL's opinion that the suheittals provided to the for Unit 1 are directly applicable to Unit 2. In summary, Unit 2 will revise emergency operating procedures to reflect a more stringent cooldown rate than the existing 75F/hr rate. However, it is our position that the more stringent cooldown rate is not required to preclude safe cooldown or plant shutdown. All,evaluations completed by our NSSS Uendor (C-E) concur with our i i Th St Lucie Uni,t 2 response to the above question is addressed in FPL'letters L-80-343 dated October 17, 1'980 and L-80-431 dated December 30 1980.
5. 4-28n Amendment No. 4, (618'1)
PucsL'>.<>r> 440.5 Provic)o <letails <>>> t)re alr>>ms a>>cl ir>dicatior>s w)rich woul<l iriform thu <>)>orate>rs t:hat: a SDC suet:ion li>>e ir;o-lation valve )raw closed while the plant i. ir> sh<<Lclowr>
cooling. Is there ar>y commor> failure which would re.-
sult: i>> hot:h valves being closed while in slruLdowrr coo linc) ~
I tlhen LPSI )>sm)> miniflow isolation valv<g sl>ut:down <:oolir>g, what worrld pr<.vor>t pump clamage iF a prcssure transie>>C were t.o occur which causes RCS pressure: to exccc.d LPSI deadhead pressure? Nher> t: he plant is in the SDCS mode, is thc:re any sir>glu Failure which would c:a0se the suction of both SDC p>>mps to bu switched from the hot leg piping to the dry sumps?
~~Respor>se: The SDC is'olation valves are V-3480, -3481, -3651, and~~
~~-3652.~~
~~Chen any of these valves are closed, a light is displayed on a panel in the rontrol room.~~
~~Valves V-3480 and -3481 are ir> line with LPSI pump 2A.~~
~~Valves V-3651 and -3652 are in line with LPSI pump 2B.~~
~~Valves.V-3652 a>>d -3481 are on <.lectrical Train A.~~
~~Valves V-3651 ar>d -3480 are on electrical Train B.~~
It should also be noted that there is a cross connect betweer> the two LPSI pump t:rains. This cross co>>>>cct is situated between, the two isolation valv<~~>g is opened and closed via valve V-3545. Power is supplied to the valve from either cl<<c:~~
~~trical Train A or B via thc. swir>g Bus. This cross cor>neet valve can be opened from the co>>trol room and also from a loc:al control station. Open and closed positions arc.~~
~~shown by corresponding liglrts. These licrhts are powered~~
~~.from electrical Bus A. Ir> adc)ition, there is a 0-100";~~
~~indication for t)>is valve powc:red from clcctrica) Bus B.~~
Thrrs, if one of the valves failed ox if one of the diesel ger>erators Failed, there would still hc one functioning LPSI pump train. For example, if valve2A would V-3481 failed closed, the pil>ing line to LPSI pump no longer be opc.nr however, t: he line to LPSI )><>mp 2A would sLill be oper> a>>d opera)>le'. As a second <<xampler clu<.tri<ral Train A failed t: he diesel <3er>erator failed t:o start these valve:s V-3652 and V-3481 would not open. Fl<.ctri-.
cal Trair> B is func Lional ar>d is us<<d to opc>> Lhe SDC cross conr>ec:t valve (V-3545) . tinter flow:- through t.he LPSI )>ump 2A trair> (u)> to t: he cross con>>ccL poirrt), flows thro>>gh t: he cross cc>r>>>e<<t. pipir>g a>>d into the ),PSI p<<mp 2B piping train, thus supp)yir>g LPSI pump 2B with the necessary flow.
~~e/~/z(~~
~~There is nr> s>>><i)c fbi)u>'e which prevorits SDC entry and th< rc is iio si>><))e failure which closes both v>ives i>> a siii<ile trai>> or pruveiits one valve from bci>>g <:lo.,cd.~~
The second t>art of this ouc. tiori addresses the si,tu;itioii whu>> the LPSI pump miniflow isolation valves are closed (di<ri>>q the shutd<iwn'cooling mode) arid a pres-sure trinsient o<><<urs in the RCS which exceeds the LPSI pump deadhead pressure.
r For the Shutdown Cooling Mode, the LPSI pump suction is aligned to the hot leg of the RCS. The flow Crom the discharge side of the pump goes into the cold leg of the RCS. Due to this arrangement, the LPSI pump would not be deadheaded by an RCS pressure surge. Relief valves in the shutdown cooling suction lines prevent isolation of the line for any credible overpressure events.
There is no single failure that would cause both of the LPSI pumps to be aligned to the dry sump during the Shutdown Cooling Mode. The St. Lucie Unit 2 has a num-ber of features incorporated in its design which pre-cludes this.
For thy LPSX pumps to be aligned .in the accident confi-guration sited in the question, the water supply from the RCS would have to be cut off and the path from the containment sump to the LPSX pumps, would hive to be open. An inadvertant RAS wo>>ld open-the isolation valves from the containment sump (I-MV-07-2 A and B).
However, an RAS also turns off the LPSI pumps and does not close the SDC suction isolation valves. Valves V-3444 and V-3432, one in each line, are closed during shutdown cooling and must bc opened to align the LPSX pumps to a dry sump.
~~'I 7g< existing design permits a sa>>gle failure of the A or B battery to close a suction valve in each train nf the shutdown cooling system. 7~ ~<>Q P;g g, P~P~ /g<~~
+ > Ol/~ VAw (+-35 +5) uzi/f bmd+Pa .iM 50 g 4i mh s 44r c. +~~/y
0
/
{15.A) For the large steam line break (SLB) events presented in Apoendix 15A the concern is the possibiliby of degradation in fuel performance during potential post-trip return to power. Pre-trip fuel degradation
. for SLB events is addressed in Section 15.1. (See the response to guestion 440.80(a)). Radiological releases for SLB events are bounded by the LF-3 event to be. presented in Section 15.1.5.1. There is no
('g approach to the 110" of design pressure criterion during SLB events.
Of the possible single active component failures f'r the St. Lucie 2 Plant, only two can imoact the potential for post-trip return to power r
and consequent possible degradation in fuel performance: (a) 're of a main steam isolation valve to close on actuation of in steam isolation signal {MSIV fa(lllure) and (h) failure of
'I high pressure safety injection (HPSI) pump or failure of one PSI pump and one low pressure safety injection (LPS!) pump (the ter case being possible only if offsite power is unavailable). he only significant impact
'hese single failures can have is on tential post-trip degradation in fuel performance. Table 440e9 -1 shows the maximum post-trip reactivities, core average powers, and core average heat fluxes with an assumed MSIV failure and with an assumed HPSI or HPSI pump ft plus'LPSI pump failure, as appropriate, for 6.36 porn~ ~m SLBs.
Cases are presented for SLBs initiated at full power and at zero power, with and without loss of offsite power.
For cases with loss of offsite power, failure of one HPSI pump plus one LPSI pump is seen to present the greatest potential for post-trip degradation in fuel performance. Therefore this was the single failure assumed for the cases with loss of offsite power which are presented in Appendix 15A of the FSAR.
For cases with offsite power available (no reactor 'coolant pump trip) the impact of the two possible single failures is nearly identical.
The analyses presented in Appendix 15A of the FSAR assumed a MSIV failure for cases with offsite power available since this failure yields slighl ty higher core average heat fluxes. No conclusions would be changed by assuming, instead, one HPSI pump failure for these cases.
(9 TABLE 440.9-1 EFFECT OF SINGLE FAILURE OF MSIV OR ONE HPSI PUMP OR ONE HPSI PUMP PLUS ONE LPSI PUMP ON MAXIMUM POST-TRIP REACTIVITY, CORE AVERAGE POWER, AND CORE AVERAGE HEAT FLUX FOR 6.36 FT 2 MAIN STEAM LINE BREAKS. AUTOMATIC ACTUATION OF AUXILIARY FEEDHATER IS ASSUMED.
MAXIMUM POST- TRIP:
INITIAL FF-SITE SINGLE POWER CORE AVERAGE POWER FAILURE CORE AVERAGE LEVEL REACT/V ITY POyiER HEAT FLUX
('10 6p) (X OF FULL X OF 2570 MH)
POgER VALU NE HPSI AND ONE +0.003 8.3 8.5 LPSI PUMP LOSS OF MSIV
-0.05 6.8 t
FULL ONE HPSI -0. 10.4 PUMP AVAIL- 3'0.3 ABLE 10.2 11.2 MSIV NE HPSI AND ONE +0. 3 0.8 1.0 LPSI PUMP LOSS OF
+0. 1 1.6 X 10 0.4 MSIV ZERO ONE HPSI -0.5 1.1 X 10 1.4 PUMP AVAIL-ABLE MSIV
-0.5 1.1 X 10 1.5
0 1
3 m r-IC. 5'u. if~n,w g//9 (F/
SL-2 Round One uestions 440.14 One of the key parameters in LOCA analyses is peak clad temperature.
{15.0) For non-LOCA transients, minimum DNBR (departure from nucleate boiling ratio) is of primary importance. For those transients analyzed in Section 15 of the FSAR, provide graphical output of the DNBR as a function of time.
~Res ense:
DHBR plots are provided for events which show a DNBR decreasing below its initial value for all sections of Chapter 15.
15.1.2.1 attached Figure 15.1.2.1-13 15.1.4.3 FSAR Figure 15.1.1. 3-9 15.1.5.3 'FSAR Figure 15;1.5.3-9 A- attached Figure 15A-l.ls
~2 rs-a, s-3 (~~
attached peal'Jpp 'm~&dlrppc Figure Jb..
15A-+ 5 g~a r.s cd) PAlgR zc ~Micore a8.
Ho event or event combination addressed in Section 15.2 results in a minimum DHBR less than 1.19.
15.2. 1.1 DNBR remains above 3.0.
15.2.1.2 No decrease in DHBR.
15.2.2.1 DHBR remains above 3.0.
15.2.2.2 attached Figure 1 5.2.2.2-12.
15.2.3.2 attached Figure 15.2.3.2-12 15.2.5.2 attached Figure 15.2.5.2-21 Events presented in Section 15.3 of the St. Luci e Unit Ho. 2 FSAR which initiate a decrease in reactor coolant pump flow rate are loss of off-si'te power (15.3.2.3), and one pump resistance to forced flow with a loss of offsi te power as a result of turbine trip (15.3.4,3). Graphical output of DNBR versus time for the loss of offsite power event is pre-sented as Figure 15.3.2.3-1 in the FSAR. For the one pump resistance, to forced flow event with a loss of offsite power as a result of turbine trip,=graphical output of DNBR versus time will be for warded by .the end of August, 1981 (see response to g 440.11).
15.4.1. 3 FSAR Figure 15.4.1.3-7 15.4.2.3 FSAR Figure 15.4.2.3-7 15.4.2.4 No decrease in DNBR 15.4.3.1 FSAR Figure 15.4.3.1-8 15.4.4.2 Ninimum DNBR is greater than for 15.4.4.3.
15.4.4.3 attached Figure 15.4 .4.3-8.
15.4.5.1'5.4.5.3 attached Figure 15.4.5.1-11..
To be submitted with analysi; Ther e are no events in 15.5 for which the NBR decreases below the initial value.
{15.6) The events analysed in Section 15.6 of St. Lucie Unit No. 2 FSAR, which result in a decrease in the RCS inventory are steam generator tube
SL-2 ROUND ONE UESTIONS
440.25 Provide a detailed analysis on the consequences of a RCP shaft seizure (15.3.3) event. Justify selection of limiting single failures. The time at temperature studies which justify your claims of peak clad temperature being limited 'to 1300oF are not accepted by the staff. In assessing fuel failures, any rod which experiences a DNBR of less than 1.19 must be assumed failed. Confirm that the results of the analysis meet the acceptance criteria of SRP 15.3.3.(2). Provide your assump-tions on flow degradation due to the locked rotor in the faulted loop, and reference appropriate studies which verify these assumptions.
Also provide a similar analysis for the locked rotor event presented in section 15.3.4.1, and show that acceptable consequences result.
~Res ense The most severe single failure in conjunction with the RCP shaft seizure event is the loss of offsite power on turbine trip, as discussed in the response to 440.9.
Results show a minimum DNBR of 0.36 at 3.6 seconds, resulting in 13K of the fuel rods 'experiencing DNB (see the response to 440. 11). The 2-hour thyroid dose assuming 13Ã failed fuel 's approximately 30 rems and the peak RCS pressure is The
~ W+s-W:~d <p~:4.~i.~
'less than or equal to 2694 psia (see the response to 440.8).
gg )~~ (~kgc.
flow coastdowns which were used in the analys'is of the one pump resistance to forced flow are presented in Figures 440.25-1 and 440.25-2. The seized shaft is assumed to instantaneously stop at time 0.0 with the seized rotor only as a resistance to flow. This coastdown was generated using the 'cting COAST code as documented in CENPD-98 (see Reference 1).
~~Reference:~~
~~1. 'Coast Code Description", CENPD-98, April 2, 1973.~~
A change to the FSAR, Appendix 15.C.3 will be submitted in September 1981.
440.41 Identify the plant operating conditions under which certain automatic safety injection signals are blocked to preclude unwanted actuation of these systems.
Describe the alarms available to alert the operator to a failure in the primary or secondar s stem during this phase of operation and the time available to mitigate the consequences of such an accident.
~Res onse While the plant is in power operation, the safety injection signals may not be blocked. During the interim phase, while RCS pressure is being reduced to re-fueling mode, it becomes necessary to partially block the SIAS.
A safety injection block is provided to permit shutdown depressurization of the Reactor Coolant System (RCS) without initiating safety injection. This block is accomplished manually after pressurizer pressure has been reduced and a per-missive signal is generated by the Engineered Safety Features Actuation System.
This blocking procedure is under strict administrative control; block and block permissive is a'nnunciated and indicated in the control room. It is not possible to block above 'a preset pressure: if the system is blocked and pressure rises above that point, the block is automatically removed. The block circuit com-plies with the single failure criterion in IEEE 279-1971.
The SIAS block removes only the pressurizer pressure signal from the SIAS trip logic. The high containment pressure transmitters still remain in direct con-nection with the trip logic. Should an event occur whereby the containment pressure is sufficiently raised, high containment pressure alarms sound on RTG B-206 and the SIAS is initiated automatically, regardless of the pressurizer signal block.
The Technical Specifications will permit blockage of'he SIAS in plant modes 5 and 6, while the shutdown cooling system is in operation. In these modes pro-tection against overpressurization of the Reactor Coolant and Shutdown Cooling System, 'due to a spurious actuation of the HPSI, is provided by relief valves V-3666 and Y-3667 in the SDC suction lines. FSAR Tables 7.5-1 and 10.4-5 in-dicates the display instrumentation and their alarms~4:~h<available to the operator to establish primary and secondary system conditions.
~C During cold shutdown or revue ing modes ~ and 6) should a loss of coolant occur, level guages in the containment and cavity summand the safeguards room sump with alarms would alert the operator of suchan accident. During the plant cooldown, operator action is required to continually monitor the S.G. secondary water level and feedwater flow. Because of this the operator is a&are of the secondary system conditions.
During a refueling, for specific maintenance tasks, it is expected that some instrumentation will be inoperable. Administrative procedures will assure that the operator will be able to assess the status of the primary and secondary sys-ems for the specific situations.
Ho FSAR change is required.
440.44 A reported event has raised a question related to the conservatism of NPSH calculations with respect to whether the absolute minimum avail-able NPSH has been taken by the staff as a fixed number supplied through the applicant by either the architect engineer or the pump "-
manufacturer. Since a number of methods exist and the method used can affect the suitability or unsuitability of a particular pump, it is requested that the basis on which the required NPSH was de-termined be branded (i.e., test, Hydraulic Institute Standards) for all the ECCS pumps including the testing inaccuracies be provided.
~Res 'onse The required NPSH of the St. Lucie Unit 2 ECCS pumps is confirmed by test. The high pressure safety injection pumps are supplied by Bingham-Hillamette Co.
These pumps are tested in accordance with the ASNE Power pest Code 8.2 (cen-trifugal pumps).
Similar pumps were also supplied for St. Lucie Unit l. Each of the St. Lucie Unit 1 pumps were also tested for the NPSH re-quired. The results show (see following table) little variance between pumps for similar flow.q7 e, HP>X la~~a ~are Puwf~d ss pradwo-o4'P~fd n~ eAo~$ ;ue; LPSI pumps are supplied by Ing rsol-Rand. The NPSH characteristic is O% J~r <+ro~. 'he by test. Both of the St. Lucie Unit 2 LPSI pumps were tested.
con-'irmed The Hydrualic Institute Standards were used for thy tests. +~m f~~Q J~g i jVP5$ wf ~prswr~~iaJp'Y, J~rn.L,.-~.
NPSH TEST RESULTS FOR ST. LUCIE UNITS 1 AND 2 St. Lucie Unit 1 HPSI Pum s GPH 'NPSH ft f200113 640 19. 7 j/200114 640 , 19.9 ICI200115 640 19.6 St. Lucie Unit 2 HPSI Pum s
$ 14210014 (spare pump) 640 19. 9
.f14210015 631 19.0 Ii'14210016 639 19.4 g loyf. Iq f St. Lucie Unit 2 LPSI Pum s 3$ 'oc (5-, ~
II1076149 3000 .13 q Ca o f1076150 3000 11.0 =
4~/+0 vs. flow curves for the St. Lucie Unit 2 HPSI and LPSI pumps are shown
/7 ~
The NPSH in Figures 6.3-3a, 6.3-3b, 6. 3-4a, and 6.3-4b. Hpg~ ~~ Lp~ ~
s f 45 C C" P i ~> s &C L ta ~ a'g '.-4 ~ . 7-t(
440.39 Identify all ECCS valves that are required to have power locked out; (6, 3) confirm they are included under the appropriate Technical Specifications, with surveillance requirements listed.
s
~Res onse The ECCS valves that are required to have power locked out are listed "below. The Technical Sp cification section of the St. Lucie-2 FSAR is currently being gen-erated. Surveillance requirements for these valves will be listed.
0 V-3614, V-3624, V-3634, Y-3644 - SIT Iso1ation Valves. "Poner rack out to motor required when pressurizer pressure greater than 700 'psig."
V-3613, Y-3623, V-3633, V-3643 - SIT Vent Valves. Power to those val'ves is
~
~
removed in the control room during normal operation.
No FSAR change is required.
REACTOR COOL>>3rr S.ST-,~
3 STE>>M Gc."lFRATOPS LJHITZ3(G CO,'(OITZOt< FOR OP+RATIO,'J
.3.4.6 Each steam generator shall be OPERABLE.
APPLICABILITY: MODES 1, 2, 3 and 4.
ACTION:
Mith one or more steam generators inoperable, restore the inoperable
. generator(s) to OP""itABLE status prior to increasing T avg above 200~F.
SURVEILLANCE REOUIRBIEHTS 4.4'.6.0 Each steam generator shall be demonstrated OPERABLE by performance of the following augmented inservice. inspec ion program and the requirements of Specification 4.0.5.
4..4.6~ 1 Steam Generator Sample Selection and Inspection - Each steam
. generator shall ce detarminea OPERABL:- during snutccIm oy selecting and inspe~cting at. leas. the minimum number of steam generators specified in
. TDle 4.4"1.
4.4.6.2 Steam Generator Tube Sample Selecticn and Insoec icn - The steam
. generator tu"e minimum sample si e, inspec-ion resul- classification, and the corresponding action requir ed shall be as specified in Table 4. 4"2. The inservic inspection cf stean generator tubes shall be performed at the fr'equencies specified in Specifica ion 4.4.6.3 and the inspec.ed tubes shall
~~be verified =ace p able per the acceptance criteria of Spec fication 4. 4. 6. 4.~~
The tubes selected for each insc~ica inspection shall include at least 3X cf
. the total number of tubes in all s earn generators; the tubes selected fo-these inspections shall be selected on a random basis except:
'a 4 )there expe'rience in similar'lan+m with similar water chemis ry indicates critical areas to be inspec-ed, then at least 50 of the tubes 'inspected shall be from these critical areas.
~~b. The first sample of tubes selected fcr each inservice inspection (subsequent o the preservice inspection) of each steam generator shall include:~~
- C~S h 3/4 4" 10 Og 01 lcSO
/
REACTOR COOLANT SYSTE.'1
-SVRVEILlAt(CE REOVIREHEHTS (Continued)
All nonplugged tubes that previously had detectable wall penetratiors (greater than 20~).
~~2. Tubes in those areas where experience has indicated potential prob 1 ems.~~
3. A tube inspection (pursuant to Specification 4.4.6.4.a.8) shall be performed on each selected tube. If any selected tube does not permit the passage of the eddy current probe for a tube inspection,'i'.this shall be recorded and an adjacent tube shall be selected and subjected to a tube inspection.
Co. The tubes selected as the second and third samples Table 4.4-2) during each inservice inspection may be subjected to a (if required by partial tube inspection provided:
The tubes selected for these samples include the tubes from those areas of the tube sheet array where tubes with imperfections were previously found.
~~2. -The inspections include those portions of the tubes where imperfections were previously found.~~
The results of each sample inspection shall be classified into one of the following three categories:
Ins ection Results Cate~os'"2
=
Less than 5Ã of the total tubes inspected are degraded tubes and none of the inspected tubes
're defective..
One or more tubes, but not more Chan 1Ã of the
'otal tubes inspected are defective, or between
,SX and 10Ã of the total tubes inspected are degraded tubes.
'"3 Nore than 10~ of the total tubes inspected are degraded tubes or more than 1Ã of the inspected tubes are defective.
Note: In all inspections, previously degraded tubes must exhibit significant (greater than 10~) further wall penetrations to be included in the above percentage calculations.
3/4 4" 11 '-'
OCr o a
\
0
REACTOR COOLANT SYSTE."1S SU ILLANC" P."U~ReMc'O'S Continued 4.4. 6.3 Insnec ion Freouencies - The above required inservice inspections of steam generator -uaes snail oe performed at the following frequencies:
a. The first inservice inspection shall be performed after 6 ffective Full Power Months but within 24 calender months of initial crit" kality. Subsequent inservice inspections shall be performed at intervals of not less han 12 nor more than 24 calendar months after the previous inspection. If two consecuzive inspections following service under AVT conditions, not including the preservice inspection, result in all inspection results falling into the C-1 category or if wo consecutive insp c iona demons "ate that previously observed degradation has not continued and no additional degradation has oc"urred, the inspection interval may be extended to a maximum of once per 40 months.
b. If the. results of the inservice inspec ion of a steam generator conducted in accordance wi h Table 4.4"2 at 40 month intervals fall into Category C-3, the inspection ,requency shall be increased to at least. once per 20 months. The increase in inspection frequency shall apply until the subsequent inspections satisfy he cri.eria of Specification 4. 4. 6.3. a; the interval may then be extended to a maximum of once per 40 months.
l c Additional, unscheduled inservice inspections shall be performed on each s earn generator in accordance wi.h the firs sample inspec ion specified in Table 4.4-2 during the shutdown subsequent to any of the following cond-itions:
~~1. Primary"to-secondary tubes leaks (not including leaks originating from tube-to"tube sheet welds) in excess of .he limits of Specification 3.4. 7. 2.~~
~~2. A seismic occurrence greater than the Operating Basis Earthquake.~~
r
~~3. A loss-of-coolant accident requiring actuation of the engineered safeguards.~~
~~4. A main steam line or feedwater line break.~~
3/4 4-12
-t 0
0
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REACTOR CGOLAHT SYSTEM SURYEILLAHCE REOUIREHEHTS Continued 4.4.6.4 Acceptance Criteria
a. As used in'his Specification Imoerfection means an exception to'he dimensions, finish or contour of a tvbe from that required by fabrication drawings or specifications. Eddy-current testing indications below 20~ of the nominal tube wall thickness, if detectable, may be considered as imperfections.
~~2. ~0i I -I d general corrosion occurring on either inside or outside of a tube.~~
~~3. ~PP than or equal to 20Ã of the nominal wall thickness caused by degradation.~~
K~di affected u
P or removed by degradation.
~~5. Oefect means an imperfection of such severity that it exceeds the plugging limit. A tube containing a defect is defective.~~
~P1 I LI the tube snail be removed from service and is equal to (40)~"
'. of the nominal tvbe wall thickness.
'nserviceable describes the condition of a tube if it 'leaks or contains a defect large enough to affect its structurai integrity in the event of an, Operating 8asis Earthquake, a loss-of-. coolant accident, or a steam line or feedwater line break as specified in 4.4.6.3.c, above.
I
~~8. Tube Inspection means an inspection of the steam generator tube from the point of entry (hot leg side) completely around the~~
'-bend to the top svpport of the cold leg.
Preservice Inspection mieans an inspection of the full length of each tune in eacn s-earn generator performed by eddy cvrrent techniques prior to service to establish a baseline Value to be -determined in accordance with the recommendations of Regulatory Guide 1. 121, Augvst. 1976.
SF ~ L.~c., g 3/4 4" 13 01 loeO OCT
I t
D REACTOR COOLANT S'(ST="H
~ ~
EILi&HCc REOUIREH""!ITS (CcntinuedI e
condition of the tubing. This inspec ion shall be performed fl 7. 4 prior to initial POWER OPERATION using the equipment and techniques expec-ed to be used during suosequent inservice inspections.
b. The steam generator shall be determined OPERABL~ after completing the corr sponding actions (plug all tubes exceeding the plugging limit and all tubes containing through"eall cracks) required by Table 4.4" 2.
~~4.4.6.5 Renorte Following each inservice inspection of steam generator tubes, the number of tubes plugged in each steam genera-'or shall b reported to the Cormnission within 15 days..~~
b. The complete results of the steam generator tube inservice inspection shall be submitted to the Commission in a Special Report pur'suant to Soecification 6. 9. 2 ~sithin 12 months following com-
-0 pletion of the inspection. This Special Report shall include:
1.. Number and extent of tubes inspected.
~~2. Location and percent of eall-thickness penetration for each indication of an imperfec ion.~~
~~3. Edenti fi cat i on o f tubes pl ugged.~~
e c Results of steam generator tube inspec ions which fall into Category C"3 and require prompt notification of he Commission shall be reported pursuant to Soeci ication 6. 9. 1 prior to resumption of plant operation. The ~!ritten folio~up of 4his report shall provide a description of investigations conduc4ed to determine cause of the tube degradation and corrective measures taken to prevent recurrence.
~
'l4 4" 14
0 0
TABLE 4;4-]
l 0
glNIiYiUMNUMBER OF STEAI'4 GEQEQATOPS TO QE .
INSPECTED DURING INSERVICE i flSPPCT)ON Prescrvlce Inspection No Yes No. of Steam Generators per Unit Two Three Four Two Three Four First ln -rvica Inspection All One Two Two Second 5 Subsequent Inscrvlce Inspections One> Ona2 One3 Table Nota'.Ion:
~~1. The inscrvica Inspection may be~~
'I limited to one steam generator on a rotating schedule encompassing 3 N ol the tubes Iwhcre N is thc nun>bcr of stcam generators In the plan!) If the results of the first or previous Inspections indicate that all stcam generators are performing in a like manner. Note that under some circumstances, the operating conditions In onc or more stcam generators may be tound to be mora scvcre than those in other stcam generators. Under suclt circum.
stances tire sanrple sequence sltall be modified to Inspect the most scvcre conditions.
~~2. Titc otl>cr steam generator not inspected during the first inscrvice Inspection shall be inspected. The third and subsequent:~~
~~inspections should follow tl>c Instructions described in 1 above.~~
3. Eacl) of the other two steam gcncrators not inspected during the first inservlce Inspections shall ba Inspected during the second and third inspections. Tha fourth and subsequent inspections shall foltow tlte instructions described in 1 above.
~
n CD I
0 TABLE 4.$ -2 STEAM GENERATOR TUB'E INSPECTION n
)ST SAMPLE INSPECYfON 2ND SAMPLE INSPECTION 3RD SAMPLE INSPECTION Sample Slee Aeiult Action Rmtufrcd R e suit Action flcqulrcd Result Action Acquired A mlnhnum of C-I None N/A S Tubes per N/A'/A S. G.
C-2 Plug dclcctlvo tubes C-I Nono end Inspect eddltlonal C-1 Plllg defective tubes 2S tubes In tlils S. G. C-2 end Inspect additional C-2 Plug defective tiibcs 4S tubas In tlils S. G.
Perform aciion for C-3 C-3 result of first siW lip la Perform action for C-3 C-3 result of flrsl . N/A N/A sample C-3 Inspect all tubes In All other this S. G., plug de- S. G.s aro None N/A N/A fective tubas and C-l Inspect 2S tubos In Some S. G.s Perform action tor eacli otli<<r S. G. N/A N/A C-2 but no C-2 result of second additional saniplo Pronipt notlllcatlon S. G. ara to NRC pursuant C-3 to sl>cclllcatlon Adilitional liispcct ell tubes In 6.0.l S. G. Is C-3 cadi S. G. and plug defectlvo tubes.
Pronipt notlllcatlon N/A N/A.
to NRC pursuant to speci flee tlon 6.0.l N~ V/hero N Is tho nund)er of'stcam gen<<rators ln tho Unit, and n ls tho number of steam gcncrators lnspcctcd 3
during en Inspcctlon
<D CD CD
I zs>. Provide a conservative demonstration for Pressurizer Manway Nuts (Number C-5364) and Pressurizer tlanway Studs {Number C-5365) that the material when tested .at 40"F or lower will meet or exceed 25 mils lateral expansion. Lower bound CVN curves for SA-193 Gl'. 8-7 and SA-540 Gr. B-24 materials are considered acceptable methods for extrapolating the CVN impact data from the test tem-perature to 40'F. In addition, demonstrate that the metallurgical
. condition of the materials used to'generate the lower bound curves for SA-193 Gr. B-7 and SA-540 Gr. B-24 materials are equivalent to
'he metallurgical condition of the SL-2 material. This can be ac-complished by providing the heat treatment informa'tion for the material used to generate the lower bound curves and for SL-2 Pressurizer Hanway Studs and Nuts.
Reply: A. CVN data for SA-193 Gr. B-7 are given in Table 251.g-l.
Since full curves are not required for this material, testing over a range of temperatures is not normally done. Results for. the pressurizer manway nuts, code no. C-5384, were:
~Tem 'F Ft-lbs I Shear oils Lat. Ex .
+10 53 80 33
+10
+10 'l 25 40 60 18 27
't 10'F, two specimens met the mils lateral expansion require-ment, 25 mils, while one. did not. Since two specimens exhibited over 50% shear, this is the center of the temperature range in which the toughness increases rapidly with temperature. By testing at-a temperature 30'F higher.- 40'F, C-E expects that all: specimens would exhibit 75-100% shear. From the data pre-sented in Table 251.8-1, C-E expects in excess of 25 mils lateral expansion at 75K shear.
Heat treatment for code no. 5364 is given below; heat treatment data for Table 251.g-l is given in Table 251.$ -2. C-E feels that each of these heat treatments produce similar metallurgical structures in this alloy.
Austeni tized 1550'F, oil quenched Tempered 1000 F Stress Relieved 7hs prowl~
~~d. k~ )~4 i 4, 5> g k~e ~l>>l<<~~
~~eg .~-(.t~~
~~4' l~~ ~ s~.i,. 4~. 4vifii l~ 7u'F.~~
~ '51.P The materials survei1'lance program uses six 'specimen capsules that should contain reactor vessel steel specimens of the limiting base material, weld metal and heat-affected-zone material. To demonstrate compliance with Appendix f{, 10 CFR Part 50, provide a table that in-cludes the following information for each specimen:
~~l. Actual surveillance material;~~
2. Origin of each surveillance specimen (base metal: heat number, plate identification number; weld metal: weld wire, heat of filler material, production welding conditions, and plate material used to make weld specimen);
~~3. Test specimen and type;~~
~~4. Chemical composition of each test specimen.~~
Provide the .location, lead factor and withdrawal time for each speci-men capsule calculated with respect to the vessel inner wall; I0 Reply: Table 251.$ -1 lis'ts the requested information. The weld and HAZ specimens are produced using the same weld procedure as is used to weld the vessel. The HAZ specimens are 1/2 weld metal, and. 1/2 limiting base metal,plat'e, H-605-1. The weld metal specimens are produced by welding plates M-605-2 and M-605-3 together.
1 CVl Si o4
'The surveillance capsule withdrawal schedule for St. Lucie Unit 2 was established in accordance with 10CFR50, Appendix H, paragraph II.C.3(b). The first capsu'le is scheduled for wittidrawal when the encapsulated base metal
'aterial is conservatively estimated to exhibit a reference temperature shift of 50'F. This is predicted to occur after approximately one effective full power year (EFPY) which corresponds i:o a neutron fluence of about 1.3 x 1018n/cm2 (E>ltleV). The second and third capsules are scheduled for withdrawal after 12 and 24 EFPY, respectively.
A significant advantage will result from withdrawal of the first sur-veillance capsule after 1 EFPY, because it will provide an early indication of the validity of the reactor vessel fluence and reference temperature shift predictions. used to set the vessel operating limits. Actual dosimetry and shift measurements will then be available for projecting radiation induced changes in the tougnness properties of the vessel beltline materials.
\
This withdrawal schedule is consistent with the objectives of ASTH E185-79 (Standard Practice f'r Conducting Surveil'lance Tests for Light-Water Cooled Nuclear Power Reactor Vessels) and 10CFR50, Appendix H: - ". . . to verify the
'nitial predictions of the surveil lance material'response to the actual radi-j
\
ation environment..." and to determine the conditions under which the vessel can be operated with adequate margins of safety against fracture .
0 COHPT RNZTORY . XTQK SL-2-81-700 Page PMQRKS 1 of Ouestion 435 Completion o6 ECCB Piping << EE/8E guestion 435 m previously car%'ed- s Z;sysrznetric Loading Analya& ECCS Pip&a@ Supports 6 Restraints 11/3E "Heeting Open Response" due to t1:e.fec~,
CKBHs lJ,/BE Chat &formation concerning ovality ttes Reacto Xnternols 12/81 Mllssing.on I/3]/83. en ovslity diagram an Fuel - >f82 the appropriate description was p ovided Co Hx'e V Nerses>>
~aestion f3fi - Ve"ification of tne functional capability of C1sss 2 6 3 austenitic pipe bend end elbows.
Bee revised response Co Question, f41.1(b) Response to Question NE.3.(b) has been additional infoaaatioa on revised to ref lee" the additional in-faulted allomble stresses fo~ation ~
for bolts.
~caution fii2 - Justification of sufficien" nsrgin against buckling failure for any case ~here ~e exceed 2/'3 of critical bucMXng, stress or vh re Ebasco's Xncrease Factor violates the conditions of the response to QueaUon 40>>l(a)(2) .
Question pi9 provide a response 9/3O/81
{cis part of lg'Q on 1stores'tion on periodic leak testing of prim~ry coolant pressure isolation valves.
((caution ASS " Cg to arrange e Peek. of 9/21/8E a{ecting, to discuss the status of sc Lucre Untc 2 with reapecc co che 8G fg.ed~ster ring evenc recently experienced ac ievent SONGS.
prnbabdldty of occurence for a small feedvacer line break should be revieved by the NRC Proba&i3,istic Revie~ Group <or acceptance. The HRC to respond Ro T.iceneee "NRC" to review responses to Reactor Systems branch Question 440.8E(Z) response is (tMs attached to Question 8553. '
outcome of that revue can affece itefn 833
Page Z oi COB" 1P RAZOR'S T'ZlMS T TQ NRC RZSPNiSE DATE REMI'KKS I
~ ~
Oo stion 956 XR Bullets 79 81'25/81 PLelhaiasry <<nba On deaf,'gp ctiteria Pxovide design cz'itexia an6 sarple givet to Boo Boaaek on? jpi jBL, CG1cl1LatiGEL, I I I4 l
+caption 841.L(c Compare Table VI vI I
with the l.eading taMes of '.9-5 I
Section, 3.8.3 aa4 identffy nay
~
areae where diapezity betvaen AXSC .
4 and ASK'. Oupport requfrerenta ate 'j I eigaif ic ant.
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Question 41.1 Justify the use of SRSS for combination of SSPl and SSFO in the flu) ted Canditiane b) Provide the faulted al3,ozablo stresses for halts.
Compare Table 3.9-5 with the loading tables of Sectian 3.8.3.
Define t: he materials for vhich alla~sbles are given in T'ables of Section 3.8.3.
Resoonse a) Where the fundamental frequency of the piping system is beyond the resonant retfon of the supportlnS structu-.e tha SSE will bc combined fn t'e folloufnS manner: SSE A'K'~+SSEh Mhere the piping fundamental frequency is not beyond the structural resonant region the SSE vill be combined in the fo11cn"bing manner:
SSE = lSSEXt + ISSSDl
>) Faulted allo~13.es for bolts ate established as 1.6 X AXSl:
allo>>wbles (noanal) .
Hatcrfcl A-925 AISC Allowable Tensile Stress 40 Ksi Allo@able tensile stress Por Faulted Condition 64 Ksi, g Of. Ult93JZjte 53K (gll 1 ll die }
61K (1 l(8 18 dias)
Requirements for component supports'axe addressed in Section 3.8.3.
Any areas vhere disparity betvcen AXSC and AS>$ support requirements is signiHcsnt vill be Msntified. This ~ill bs performed so tbat governing loading cases address or envelope the loading cases given in Table 3.9-5.
A11ovame stresses are based on Section 1.5 of AISC vhich in turn are based on ASTH material values. AISC factors of safety vary from 1.67 ta 2.0 on yield strength. i,~e development of factors of safety is documented in the Cmrmentary to the A'LSC Code;
sl 420e3 tLualification of Contro~lS stems IE Information Notice 79-22 Operating reactor licensees were informed by IE Information Notice 79-22, issued September 19, 1979, that certain non-safety grade or control equipment, if subjected to the adverse environment of. a
~
high energy line break, could impact the safety analyses and the adequacy of the protection functions performed by the safety grade equipment. In the attachment to this Enclosure there is a copy of IE Information Notice 79-22, and reprinted copies of an August 30, 1979 Westinghouse letter and a September 10, 1979 Public Service Electric and Gas Company letter which addresses this matter. Operating Reactor licensees conducted reviews to determine whether such problems could exist at operating facilities.
We are concerned'that a similar potential may exist at light water facilities now under construction. You are, therefore, requested to perform a review to determine what, if any, design changes or operator actions would be necessary to assure that high energy line breaks will. not cause control system failures to complicate the event beyond your FSAR analysis. Provide the results of your reviews including all identified problems and the manner in which you have resolved them to NRP by July 6, 1981.
The specific "scenarios" discussed in the above referenced Westinghouse letter are to be considered as examples of the kinds of interactions which might occur. Your review should include those scenarios, where applicable, but should not necessarily be limited to them.
Applicants with other LHR designs should consider analogous inter-actions as relevant to their designs.
Re~s ense:
A review of potential control system interactions during high energy pipe breaks has been conducted for St. Lucie Unit 2. The review is based on the Combustion Engineering (C-E) generic review effort.
The review considered both the specific systems listed in IE Informa-tion Notice 79-22 and other non-safety systems which could possibly interact with safety grade systems.
I, t.Ppciy. Unit 2 (Ihstrfment~atio nd ontrol Says~ krmnch+uestions)
Despite the low probability of a high energy line break a generic review has byline been performed of thirteen control systems involving'four accidents scenarios which encompass the spectrum of postulated high energy breaks. A matrix was established of the high energy line breaks and control functions (Attachment 1). In the time avai'lable, the matrix was reduced to include only those systems and events which requir'e further evaluation. A general description of the procedure used to reduce this matrix is listed below:
I. An initial review of each postulated Control Function failure for each pipe break was completed and served as the basis for consideration. Hhere a postulated failure could potentially increase the severity of a high energy pipe
, break, the following criteria were employed to resolve the concern:
Is the postulated Control Function failure mode credible7
~~2. Is the Control Function Equipment (Sensor, Cable, etc.)~~
~~qualified to operate properly in the postulated environ-ments~~
3. Mhere the postulated Control Function failure is credible, could its impact potentially affect the conclusions pre-sented in the SAR? Considerations such .as Maximum Control Function capabilities, and delayed, but proper operator action were employed in this effort.
In several cases, most notibly the PORV failure in the open position, no specific failure mechanism has been identified. The only manner for such a failure to occur would be for po~er to be inadvertently applied to the valve solenoid and not be removed. Partof the short term recomendations is to evaluate whether or not a failure mechanism of this type is credible.
The potential adverse impact of high energy pipe breaks on reactor coolant pumps was considered. Both the seized shaft and the simultanteous three or four pump 'loss of fIow were e1iminated from consTderat>on based on dudgement that these failures are not con-sidered credible within the time frame limited by operator action
'(30 minutes) due to environmental impact alone. The impact of other potential 'loss of flow events (e.g., one or two pump loss of flow) during. high energy pipe breaks was reviewed and it was judged that the resulting rapid reactor trip was sufficient to ensure that the conclusions of the SAR would not change.
0 ucig Unjt 2
(&54rGlne~~n Cont A hysChmWrw5&~estions) details specific event/interactions scenarios and defines specific short term recoranendations ~hich have been established, on .a generic basis, to minimize the probability and impact of the postulated events. This attachment also discusses potential long term alternatives which have been identified on a generic basis.
The results of a review of the C-E generic evaluation applied to the St. Lucie Unit 2 design are also provided in Attachment 2.
These results are discussed after the generic short and long term recoomendations for each postulated event addressed. 8ased on these results the items shown on the generic matrix (Attachment 1) have been eliminated. Therefore no design changes are necessary to assure that high energy line breaks do not cause control system failures to complicate events beyond the FSAR analysis for St. Lucie Unit 2.
CONTROL FUNCTIONS AND EVENTS Control Functions Considered Pressurizer Level Pressurizer Pressure Power Operated Relief Valves 8 Block Valves; Relief and Closure Reactor Coolant Flow (RCPs)
Rod Position (RRS, CEINCS)
Boron Concentration (Boron Control System)
Feedwater Flow (FHRS)
Steam Flow to Turbine (TGCS)
Steam By-Pass to Condenser (SBCS)
Steam Dumps to Atmosphere Upstream of HSIVs Steam Dumps to Atmosphere Downstream of HSIVs Steam Generator Blowdown (SGBS)
Safety Injection Tank Depressurization/Isolation The listed functions were evaluated in'conjunction with the following events:
Small Steamline Rupture Inside Containment Small Steamline Rupture Outside Containment Large Steamline Rupture Inside Containment Large Steamline Rupture Outside Containment Small Feedline Rupture Inside Containment Small Feedline Rupture Outside Containment Large Feedline Rupture Inside Containment Large Feedline Rupture Outside Containment'mall I
LOCA Inside Containment C Small LOCA Outside Containment Large LOCA Rod Ejection JUL 24 SN
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ATTACHMENT 2 DESCRIPTIONS OF REMAINING EVENTS AND CONTROL FUNCTIONS I. Assessment of Control System Failures on Steam Line Break Event gg~ ~ ~
A. Sequence of Events for Generic SAR Steam Line Break at Full Power inside or Outside Containment Double-ended steam line break occurs
~~2. Reactor trip on low steam generator pressure~~
~~3. HSIS initiates to isolate the steam generators~~
~~4. RCS temperature decreases due to excessive steam removal~~
~~5. Total reactivity increases due to moderator cooldown effect~~
~~6. HSIVs close~~
~~7. Pressurizer empties~~
~~8. Low pressurizer pressure initiates SIAS~~
~~9. MFIYs close~~
~~10. Safety injection boron reaches core~~
~~11. Affected steam generator empties, terminating cooldown effect, the transient reactivity reaches peak and decreases gradually~~
~~'due to boron injection 12.* Limited or no post-trip return-to-power~~
~~13. No fuel in DNB B. Steam Line Break With PORY Control S stem Failure~~
~~1. Significant Interaction Effects:~~
~~a. Increased Containment Pressure~~
~~b. A stuck open PORV in combination with a steam line break has not been analyzed.~~
~~2. Assumptions~~
~~a. Steam line break (large break inside containment for Item 1.A above, any size or location for Item 1.B above).~~
~~b. Inadvertently PORVs open and remain open~~
~~c. PORY Block valve also fails to close when required~~
~~d. Initial condition: full power~~
3. It must be emphasized that no mechanism has been identified for the PORV to inadvertently open and remain open since its signal to open comes from safety grade equipment and the Garrett valves and solenoids are qualified for an environment in excess of 400'F.
~~5:;f~~
~~4. Sequence of Events~~
~~a. Large steam line break occurs inside containment., gg~ ~ ~ $ 98i~~
~~b. Reactor trip occurs on steam generator low pressure within 5 seconds.~~
~~c. Should the adverse environment cause the PORV to'nadvertently open and then remain open, the following steps may also occur.~~
~~It should be noted that no meachnism has been identi'fied which wo'uld cause this to occur.~~
~~d. Steam from PORV fills quench tank and bursts rupture disk releasing steam to the containment and cuasing additional containment pressurization.~~
~~e. Mass removal via PORV causes additional void formation within the reactor coolant system.~~
~~5. Actions~~
~~a. Short term:~~
~~l. Utilities continue to investigate qualification levels and location of power cables to PORYs and PORY block valves to assess credibility of this failure mode..~~
~~2. Ensure oper'ators take action to shut PORV and PORV block valve if PORV fails open.~~
~~b. Long term:~~
~~1. Complete assessment of PORVs and block valves. Dependent on the results of that assessment~~
~~a. upgrade environmental qualification level of PORVs and block valves; or~~
~~b. perform detailed analysis of event if required.~~
~~6. Evaluation for St. Lucie Unit 2 C-E has not identified a failure mechanism relative to this concern.~~
Furthermore, this system provides input to the Reactor Protective System and, as such, is safety-grade and post-LOCA qualified. Me do not believethis item is applicable to St. Lucie Unit 2.
C. Steam Line Break Hith Feedwater Flow Control S stem Failure 1; Significant Interaction Effects
~~a. Steam generator filling - causing potential, piping structural problems~~
~~2. Assumptions~~
~~a. Small steam line break inside containment that does not cause an irwediate reactor trip~~
0
~~b. Feedwater flow exceeds steam flow due to failure of steam generator level instrument, indicating flow~~
~~c. SAR conservatism I~~
no operator action within 30 minutes
'. Sequence of Events
~~a. Small steam line break occurs which does: not cause an iomediate reactor trip 5g~~~
~~b. Steam generator level instrument fails, causing an increase of feedwater f'low in excess of steam flow~~
~~c. Steam generator begins Co content of steam fill causing increased moisture~~
~~d. If no operator action occurs undefined piping structural problems could result~~
. e. It should be emphasized that this event can be prevented by prompt operator action. Safety grade steam generator level instrumentation exists, enabling comparison with control grade level instruments of the feed system.
~~4. Action~~
~~a. Short term Ensure the operator is aware of this potential, interaction~~
~~,.so that he may take promptcorrective action shoud it occur~~
~~b. Long term Assess the need of upgrading steam generator 'level indi-cation to the feedwater'control system ii. Assess the need to insCall a safety grade high steam, generator level alarm~~
5. Evaluation for St. Lucie Unit 2 The concern in this area assumes a failure in a stea'm generator level instrumentcausing the FHRS to supply feedwater in excess of steam demand, thereby filling the affected steam generator potentially leading to excessive moisture carryover. The St. Lucie Unit 2 design incorporates a design feature Chat automatically closes the feedwater regulating valves at thehigh steam generator level and trips the turbine and main feedwater pumps at the high-high level. The instrumentation transmitting the signal is a four channel system with portions qualified to withstand the adverse environment.
Those portions not qualified will not be exposed to the adverse environment. Me therefore conclude that this concern is not applicable to St. Lucie Unit 2.
flan -a, D. Steam Line Break Hith Failure of Hain Steam Paths Downstream of MSIV's
~~l. Significant Interaction Effects~~
~~'I N~~
~~a. Increase post-trip return-to-power~~
~~2. Assumptions~~
~~a. Large steam line break inside containment~~
~~b. HSIV on unaffected steam generator fails to close. This sequence of events is pertinent only if this assumption is made.~~
~~c. Downstream of NSIV's main steam paths fail open~~
~~d. Initial condition: full power~~
~~e. SAR conservatisms end of cycle core ii. the most reactive CEA stuck out iii. steam blowdown through steam line break RL 2<$ 81 I~~
3. The number of failures which must occur during this event are significant. First there must be the large break. Then the HSIV on the opposite steam generator must fail to close. There is a stuck rod on reactor trip. Then steam paths downstream of the HSIV's must be affected. These include turbine control valves and steam dump and bypass valves. The probability of this event occurring is much less than 10-6 per reactor year.
~~4. Sequence of Events~~
~~a. Large steam line break inside containment~~
~~b. Reactor trip on low steam generator pressure trip signal~~
~~c. HSIV on unaffected steam generator fails to close on HSIS~~
~~d. Hain steam paths downstream of HSIV open or fail,to close due to control system malfunction caused by adverse environemnt following large steam line break.~~
e. Open main steam paths increase the steam blowdown and increase moderator cooldown effect which adds positive reactivity to core. A post-trip return-to-power is more severe under these conditions.
0
~~5. Actions~~
~~a. ,Short term~~
~0< 2< <g8) should a steam line break occur, ensure operator takes action to isolate all alternate steam flow paths ii. determine whether this event warrants further consideration, in light of low probability of all consequential failures which must occur for the event to be significant
~~b. Long term~~
~~i. utilities investigate environmental qualificatjonlevel of the systems involved ii. 'supgrade qualification level of affected equipment if this determined to be necessary~~
6. Evaluation for St. Lucie Unit 2 The systems which must fail in order to open the main steam path downstream of the MSIV are the turbine generator control system (TGCS) and steam bypass control system (SBCS). Review of the St. Lucie Unit 2 design shows that the TGCS and SBCS would not be exposed to the adverse environment. However, the Tave input to the SBCS .generated by the RRS could ge exposed to the accident environment. The Tave input though, is used only to block initiation of a quick opening signal and cannot cause the SBCS valves to open.. A quick opening signal would not be generated due to the low steam flow and pressure inputs to the SBCS so the'alves would remain closed. l<e therefore conclude that this is not applicable to St. Lucie Unit 2.
~~E. Steam Line Break withAtmos heric Dum Valve Control S stem Failure~~
~~1. Significant Interaction r~~~
~~a. Post-accident controlled cool down h~~
~~2. Assumptions~~
~~a. Steam .line break outside containment and upstream of HSIV~~
b. Atmospheric dump valves on opposite steam line open and remain open*
~~c. SAR conservatism no operator action within 30 minutes~~
~~3. Sequence of Events~~
~~a. A steam line break outside of containment but upstream of the NSIV occurs~~
The failure mechanism identified fs a fa'i,lure of the input signals that would cause the valve to open if operating in the automatic mode. Although no for 30 minutes prompt operator action to shut the operator action is assumed open valve would mitigate any effects of this event.
~~b. Reactor trip on low steam generator pressure~~
~~c. Atmospheric dump valves upstream of HSIV's open and remain open due to control system failure~~
~~d. 'If no operator action takes place there would be, the potential for dry-out and depressurization of both steam generators~~
~~e. Failure to shut atmospheric dump valves could inhibit a controlled plant cooldown by limiting the ability of the auxil iary feed pumps to deliver to the steam 'generator(s)~~
~
Q
~~4. Actions p '2j~~
~~a. Short term operate atmospheric dump valves in manual de, or ensure operator shuts atmospheric dump valves on steam~~
~~'iine until control is assured JUL 2< ~98~~
~~b. Long term~~
~~i. Continue investigation . to determine if this failure mechanism is plausible I~~
~>>'<Appal> with-upgrade atmospheric dump valve control system to stand the adverse environment, if required 8
~
i'0 sp~&/ Aevi'~~~gy valuation for St. Lucie Unit he atmospheric 2
valves are located upstream of, the main
~~Ac,<j .p~~~~g dump steam isolation valves at St. Lucie Unit 2, and the postulated failure in this area would be a valid concern were the system to be in the automatic mode during power operations. However,
" *~ consistent with the anlayses in the FSAR, this system is maintained in the manual mode during normal operationsA Me believe this method of operation adequately addresses any'oncern in this area.
'I.
Assessment of Im act of Control S stem Failures on Feed Line Break Event and
~EA A. SAR Feed Line Break
~~1. Sequence of Events~~
a. f4in feed line break occurs downstream of reverse flow check valve, discharging main feed and steam generator fluid r b. RCS heatup due to loss of subcooled feed flow c; Reactor trip occurs on steam generator low water level or high pressurizer pressure. Turbine trip occurs on reactor tr ip.
'0
~~d. Rapid RCS heatup and pressurization due to loss of heat transfer as the ruptured steam generator empties I~~
~~e. Depressurization of the ruptured steam'enerator initiates HSIS and isolates the intact generator~~
~~f. RCS pressurization terminates with opening of pr'imary relief/~~
~~safety valves and decreasing core heat flux~~
~~g. RCS cooldown begins,'ontrolled by the main steam safety valves~~
~~h. Auxiliary feed is initiated automatically or by operator action~~
~~8. Feed Line Break With RCS Inventor Control Failure~~
~~1. Significant Interaction Effect~~
~~.a. Increased RCS pressurization due to liquid filled pressurizer~~
~~2. Assumptions~~
~~a. Small feed line break inside containment~~
~~b. Adverse environment, impacts pressurizer level instrument causing indication to fail low which causes the control system to increase inventory (and pressurizer level)~~
~~c. Initial conditions 102Ã power steam bypass control system in manual mode beginning-of-cycle core parameters~~
d. Analysis conserva'tisms no operator action for at 1east 30 minutes ii. no credit for steam generator low water level trip in ruptured unit until empty iii. heat transfer in ruptured steam generator instantaneously terminated on emptying iv. failure of the feed line reverse flow check valve, ifggp ~ 4 8~
the break occurs upstream of the valve Iq
s '$ ting
~
~~3. Sequence of Events~~
~~a. Feed line break in containment~~
~~b. Hain feed spills from break~~
~~c. Adverse containment environment causes pressurizer level~~
'indication to
(
fail low causing RCS inventory to increase
~~d. "Reactor trip occurs on steam generator low water level on high pressurizer pressure. Turbine trips on reactor trip~~
~~e. RCS heatup results from rapid decrease in,SG heat transfer due to loss of fluid from the ruptured steam generator~~
~~f. Pressurize relief and/or safety valves open~~
~~g. Potential for pressurizer to fill with liquid exists due to high level in pressurizer prior to heatup. Relief/~~
~~safety valve relief capacity reduced by liquid discharge~~
~~h. Extent of increased RCS pressurization is dependent on time of pressurizer filling relative to the rapid heatup~~
~~4. Actions a.. Short term operator to this potential~~
~~'lert failure mode, so that prompt corrective action can be taken~~
b. Long term Perform plant specific analyses to determine upper limit allowable for pressurizer level which is consistent with the maximum rate of level increase and the maximum RCS expansion during the potentially
~~. rapid heatup associated with feed line breaks upgrade pressurizer level instrumentation~~
5. Evaluation for St. Lucie Unit 2 The C-E concern postulates the failure of a pressurizer level instrument in the control system, which. in the absence of operator action, causes the pressurizer to fill, thereby allowing the reactor coolant system to go solid. As discussed in our response to IE Bulletin 79-01, the level instruments are post-LOCA qualified. We therefore do not believe there is a concern in this area.
C
'bl C. Feed Line Break lilith PORY Control Failure Significant Interaction Effects
~~a. A failed open PORII'in combination with a feed line break has not been analyzed~~
~~2. Assumptions~~
~~n. Feed line break in ide containment~~
~~b. PORV's .inadvertently open and remain open~~
~~c. PORV block valve also fails to close when required~~
~~d. Ro operator action until 20 minutes~~
~~3. PORY would not be expected to remain open due to actuation malfunction since Garrett valves and solenoids are qualified~~
~~'or temperatures. in excess of 400'F~~
~~4. Sequence of Events i~~
~~a. Feed line break occurs inside containment~~
~~b. Steam generator fluid and/or main feed spill from break c; RCS heatup and pressurization results from loss of feed flow~~
~~d. PORV opens on high pressure and fails to reclose due to adverse environment~~
~~e. Reactor trip occurs on high pressurize pressure.~~
~~Turbine trips on reactor trip~~
~~f. RCS depressurization occurs if PORY's fail to reclose~~
~~g. Hass removal via PORY causes void formation within RCS~~
~~h. Feed line break in combination with a failed open PORV has not been analyzed~~
~~5. Actions~~
a. Short term utilities investigate. qualification level and location of. power cables to PORV's and PORV block valves to assess credibility of this failure mode ensure operators take actions to shut PORV's and PORV block valves, should this failure occur
~~b. Long term Complete assessment of PORV's and block valves.~~
Dependent on results of that assessment .
A. upgrade environmental qualification level of PORV's and block valves, or B. perform detailed analysis of event, if required
6. Evaluation for St. Lucie Unit 2 C-E has not identified a failure mechanism relative to this concern. Furthermore, this system provides input to the Reactor Protective System and, as such, is safety-grade and post-LOCA qualified. We do not believe this item is applicable to St. Lucie Unit 2.
~~D. Feed Line Break With Feedwater Control Failure~~
~~1. Significant Interaction Effects~~
~~a. Overfilling of the steam generator(s) causing potential structural problems~~
~~2. 'Assumptions~~
~~a. Small feed line break inside containment~~
~~b. Feed control in automatic mode~~
~~c. Adverse environment causes steam generator level indica-tion to fail low which causes the feed control system to increase feed flow above the steam flow~~
~~d. No 'operator action for 30 minutes~~
~~3. Sequence of Events~~
~~a. A small feed line break occurs inside containment~~
~~b. 'ain feed spills from break~~
~~c. Steam generator level instrument fails indicating low and causes increased feed flow in excess of steam flow d; Steam generator begins to fill causing increased moisture content of steam~~
~~e. If no operator action occurs undefined structural problems could result~~
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~~f. It should be emphasized that this even n by prompt operator action. Safety grade level instru-mentation exists to compare'to control grade instruments.~~
~~The feed system can then be controlled manually~~
~~4. Actions ueL 24 Ig~~~
a. Short term ensure the operator is aware of the potential failure mode so the he may take prompt corrective action, should it occur assess the need to install safety grade high steam generator level alarm
~~5. Evaluation for St. Lucie Unit 2 h~~
The concern in this area assumes a failure in a steam generator level instrument causing the FWRS to supply feedwater in excess of steam demand, thereby fil'ling the affected steam generator potentially leading to excessive moisture carryover. The St. Lucie Unit 2 design incorporates a safety grade design feature that automatically closes the feedwater regulating valves at thehigh steam generator level and trips the turbine
'and main feedwater pumps at the high-high level. The instrumenta-tion transmitting the signal is a four channel system with portions qualified to withstand the adverse evnironment. Those portions not qualified will not be exposed to the adverse environment. He therefore conclude that this concern is not applicable to St.
Lucie Unit 2.
E. Feed lirie Break Hith Atmospheric Steam Dump Control Failure
~~1. Significant Interaction Effects~~
~~a. Controlled plant cooldown~~
~~2. Assumptions~~
~~a. Feed 'line break outside containment and downstream of reverse flow check valve~~
~~b. Adverse environment impacts the atmospheric steam dump control on unaffected steam generator causing an un-controlled steam release upstream of the HSIV's~~
c. No operator action until 30 minutes*
~~The failure mechanism identified is a failure of the input signals that would cause the valve to open if operating in the automatic~~
'ode. Although no operator action is assumed for 30 minutes, prompt operator action to shut the open valve would mitigate any effects of this event.
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~~3. Sequence of Events t~~
~~.a. Feed line break occurs outside containment downstream of check valve ~+ > <<ss<~~
~~b. Steam generator fluid and/or main feed spill: from break~~
~~c. Reactor trip occurs on steam generator low water level or high pressurizer pressure. Turbine trip occurs on reactor trip~~
~~d. Steam generator pressure increases following turbine trip~~
~~e. Environment could cause atmospheric dump valves upstream of NSIV in unaffected steam generator to open and remain open~~
~~f. If no operator action takes place there would be a potential for dry out and depressruization of both steam generators~~
~~9. Depressurization of both steam generators may limit the ability of the auxilairy feed pumps ta deliver to the steam generator(s)~~
~~4. Actions t~~
~~a. Short term operate atmospheric steam dump valves in the manual mode.'or ensure that the operator is aware of this potential~~
~~'interaction so that prompt corrective action can be taken~~
b. Long term continue investigation to de'termine if this failure mechanism is plausible upgrade atmospheric dump valve control s stem envir mental qualification if required:, . '~>~~ c"l~
~~5. Evaluation for St. Lucie Unit 2 ~P'."+.4 "<~" '~r /'~~
The atmospheric dump valves are located jYsS;rehN othe main.
steam isolation valves at St. Lucie Unit 2, and the postulate failure in this area would be a valid concern were the system to be in the automatic mode during power operations. However, consistent with the analyses in the FSAR, this system is maintained in the manual mode during normal operations. We believe this-method of operation adequately addresses an concern in this area.
I!I
~
~ P ttFff Break Events t fR R ~lt S t~0i Hih~E Pi es A. CEA position malfunctions due to.steam and feedline breaks and CEA ejection JOt. 2) @8)
~~1. Significant interaction effect:~~
~~a. Potentially higher reactor power levels prior to reactor trip than presently analyzed~~
~~2. Assumptions~~
~~a. Small high energy pipe break inside containment~~
~~b. Reactor regulating system in automatic mode~~
~~c. Adverse environment results in a low indicated power level from the ex-core sensor input to the Reactor Regulating System causing CEAs to be withdrawn~~
~~3. Sequence of events~~
~~a. High energy pipe break inside containment of a small jap enough size where inwiediate reactor trip does not occur~~
~~b. Control grade ex-core sensor indication fails 'low due to adverse environmental .impact~~
~~c. Reactor regulating system causes CEAs to be withdrawn~~
~~d. Reactor power exceeds the power previously assumed during the transient~~
~~e. Reactor trip occurs due to high energy pipe break at conditions not considered in present analyses~~
~~4. Actions~~
a. Short term place the control element drive system in manual ii. Modify emergency procedures to state that the operator should not take any control action based upon reactor power as measured by the control grade ex-core detectors during high energy pipe breaks
~~b. Long term~~
f. -evaluate the consequences oF small high energy pipe breaks in containment with CEA withdrawl, if required if required, of the control upgrade the environmental qualification level grade excore detector system
~~9dg~~
6. Evaluation for St. Lucie Unit 2 The C-E concern regardi ng control rod withdrawal with the Reactor Regulating System (RRS) in automatic control is considered valid. However, consistent with the analyses in the FSAR, tAs-syst~~~nta.ized-in-the-manual-mode during-normalmperaiions. Ne believe this method of opera-tion adequately addresses any concern in this area.
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~~8. Small Break LOCA Mith CEA Control System Halfunctio~~
~~1. Significarit interaction effects >PL,""4y (98]~~
~~a. Potential exists for increasing power. This would cause pressure to remain above low pressurizer pressure trip for a longer'period than previously assumed~~
~~2. Assumptions~~
~~a. Small break LOCA inside containment~~
~~b. CEA control system in automatic mode~~
~~c. Adverse environment impacts CEA control system or related sensors resulting in consequential failure~~
~~. d. Control system causes CEA to withdraw~~
~~e. Standard LOCA licensing assumptions~~
~~3. Sequence of events~~
~~a. Small break LOCA occurs inside containment~~
~~b. CEA control system in automatic mode~~
~~c. Adverse environment caused by. rupture potentially causes excore power indication to indicate low power level~~
d. Sliould CEAs begin to withdraw, the magnitude of the over-power excursion prior to scram would be increased. This could produce a higher primary system pressure which could then delay reactor trip and SIAS and result in higher
~~-peak clad temperature~~
~~4. Action,,~~
a. Short term Place the control element drive system in manual Modify emergency procedures to state that the operator should not take any control action based upon reactor power as measured by the control grade excore detectors during a LOCA.
~~b. Long term Evaluate the consequences of a small break LOCA with CEA withdrawal, and if required level of upgrade the environmental qualification the control grade excore instrumentation~~
~~ts s~~
~~5. Evaluation for St. Lucie Unit 2 The C-E concern regarding control rod withdrawal with the~~
/PI~ 8 4 Q0~
Reactor Regulating System (RRS) in automatic control is considered valid. However, consistent with the analyses in the FSAR, thH-system-is-mHntainedN~~anuaMed~uring ..
normal-,operations. He believe this method of operation adequate1y addresses any concern in this area.', ~~c. we/ ~>d<<
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Small Break LOCA with SIT Isolation Yialfunction
~~1. Significant interaction effects W~~~
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~~a. Potential exists for injection of non-condensible the RCS. This could cause problems with natural gas'nto circulation and heat transfer in the steam generators -'zz7 F44<~~
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should the gas collect there. p, d.N I Q d 'edges
~~2. Assumptions~~
~~a. Small break LOCA inside containment~~
~~b. Adverse environment impacts safety injection tank(s) isolation resulting in consequential failure.~~
~~c. Operator cannot isolate the safety injection tank(s)~~
~~d. Standard LOCA licensing assumptions~~
~~3. Sequence of events~~
~~a. Small break LOCA occurs inside containment~~
~~b. Adverse environment caused by rupture disables SIT isolation mechanism~~
~~c. Operator is unable to isolate the SIT(s) and non-condensible gas (nitrogen cover gas) enters the RCS.~~
A
~~d. Possibility exists for degraded natural circulation flow and/or buildup of gases in the steam generators causing heatup of RCS.~~
'4. Action .
a., Short term Instruct operator that the possibility of gas formation existsif SITs are not isolated.
Identify drain lines that could be used to drain the SITs and their qualification levels
~~b. Long term Evaluate options for providing another means of ise1ating the SITs and revise the design as necessargPL P 4 I@~~
~~5. Evaluation for St. Lucie 2 The valves and instrumentation and control systems are environmentally qualified to withstand the adverse environment. Backup means 'are also available to de-~~
. pressurize the SITs and thereby prevent non-condensible gases from entering the RCS.
420.4 Control System Faflur s The analyses rapor;ad'fn Chapter 15 of the FSAR ar fntended tc demons. rate the aca uacy G sa aiy systems in mi igating an"ici."ated Operational occurrences and accicents. Bosh Congress and ACRS nave raised aa issue fn his area. Ccmmissicner Ahear.".e has rasgoncad to Congress regard ng this issue (~=er tc attacho~nt tc this enclosure) and part of his response referred to control sys-;am revieus :o be peri'armed in connections eith OL licensing.
irised on the conserjative assumptions made in dei'icing these Chapter 16 desfgn-basis events and the detailed review of the analyses by the staff, ft is likely that they adequately bound the consequences of
'Sfngle control system failures.
'Ye provide assuranco that the design basfs ~ant analyses adequately--
bound other more fundarrental credible failures you ara requested to pMYfde the. following information:
(1) Identify those control systems whose failure or malfunction could seriously impact plant safe~.
(2} Indfcat which, ff any, of (1) lacefve pouer from
~
common control systems fdenstiffed fn power sourc s. The power source s.
considered should fnc'.uca all pouer sources unosa failur or malfunction could lea'd o failure or malfurc.icn of;ore than one control system and shculd extend to "he ef acts of cascading power losses due tc the failure of higher level
',dfstrfbution panels and load c nters.~
3). Tndfcata which, ff any, of the control sys. a ms identified Tne sensors fn. 0)-receive;.input signals from coamon sensors.
considered should include, but should not ne ss rily be limited to, cca-.,cn nydraulic headers cr impul.sa lines feeding pressure, tamper@tora, level or other signals to two or more
. control syst ms.
-(4) Provide fust'ffcatfcn that any simultaneous mal,unctions of the control systems unid ntified in (2) and (3) resulting from failures or 7al.unc.fons of the applicable ccr;...on pcwer source or sensor are "oundaa by he analyses in Chaptar l~ and
>Auld not require ac-ion or r sponsa beycnd .he capability of operators or safety sys. ms,
~Res onse:
.(1) The control systems whose failure or mal function may impact plant, safety 'are shown below:
FEElNATER REGULATIHG SYSTEM TURBINE-GENERATOR CONTROL SYSTEM STEAM BYPASS CONTROL SYSTEM ADV CONTROL SYSTEf1 BORON CONTROL SYSTEM
'I REACTOR REGULATING SYSTEf1 CONTROL ELEMENT DRIVE MECHAHISf4 CONTROL PRESSURIZER PRESSURE CONTROL SYSTEM PRESSURIZER LEVEL CONTROL SYSTEM REACTOR COOLANT PUMPS POWER OPERATED RELIEF VALVES STEAM GENERATOR BLOMDOHN SYSTEM (2) E (4) The control systems identified in (1) that, receive power from common power sources are identified below. The effect of losing the power sources and an evaluation of plant response are also provided. The results of this evaluation provide justification
~
that any simultaneous malfunctions of control systems identified herein, resulting from cowmen power supply malfunctions are bounded by the analysis of Chapter 15 and would not require action or response beyond the capability of operators or safety systems.
420.4 (2)II(4) Im act of Loss of Cornnon Power Sources Loss of 120 VAC from Power Panel 220 I,
This power loss will impact the pressurizer:level control system (PLCS), the pressurizer pressure control system (PPCS), the reactor regulating system (RRS), the boron control system (BC6),
and the steam bypass control system (SBCS). Specifically, the PLCS will lose control power, assuming tPe selector switch is on that channel (it will be unaffected if on the other channel).
The letdown control valve will go to its fail closed position arid the chargiog pumps will remain powered, and available for manual control. The PPCS will lose control power, assuming the selector switch is on that channel. The pressurizer spray valve will go to its fail closed position and the pressurizer heaters will remain powered and available for manual control. Addition-,
ally the low-low level automatic cut-off of the pressurizer heaters will lose control power. The RRS will lose power assuming the selector switch is on that channel (it .will.
be unaffected if on the other channel). The control element assemblies will remain in their position prior to the power loss. The BCS.will not completely be lost. The reactor makeup water flow controller )sill lose power with the boric acid flow controller unaffected. The letdown line will be affected with the temperature elements for the regenerative and letdown heat exchangers losing power,. however the letdown line will be iso-lated by the letdown control valves mentioned previously. The SBCS will not receive a Ty.ve input from the RRS which may cause the turbine bypass valves to remain closed. Secondary pressure relief and RCS heat removal control can be accomplished through the main steam safety valves and atmospheric dump valves.
Evaluation of Plant Response:
The loss of the PLCS, PPCS, RRS, BCS, and SBCS due to loss of from power panel 220'will not seriously impact plant '20VAC safety. The reactor could function for a time without operator action before a reactor trip would result (most likely on high pressurizer pressure). The operator can choose to select the
N other channel for correct operation of the PLCS, PPCS, and RRS.
However mnual control of the charging pumps, pressurizer heaters, auxiliary sprays, and turbine bypass valves is available. The operator will still have control of the boric acid flow to the charging pumps and he can choose to align the refueling water tank to charging if necessary.
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Loss of 120VAC from Power Panel 221 This power loss will impact the pre~wurizer level control system (PLCS).
the pressurizer pressure control system,(PPCS) and the reactor regulating system (RRS)', the boron control system (BCS), and the stean bypass control system (SBCS). Specifically, the same impact as with the loss of 120VAC from power panel 220 will occur with the following exceptions:
The reactor makeup water flow control will remain powered, however the boric acid flow controller will lose power. Additionally the temperature element on the letdown heat exchanger controlling the component cooling water control valve will lose power. The volume control tank level inputs to the BCS will lose power. Also the station alarms (annunciators) will transfer to 125YDC power.
Evaluation'of Plant Response There will be no serious impact to plant safety for the event presented above. In the absence 'of operator action the reactor would eventually trip (on high pressurizer pressure). However., the Operator would be alerted to such an event due to incorrect pressurizer pressure level indications in the control room. He may choose to switch the redundant channel for correct operation of the PLCS, PPCS and RRS.
However, manual control of the charging pumps, pressurizer heaters, and auxiliary sprays is available., The operator can also bypass the boric acid flow controller and provide borated water directly to the chargin pumps or a ign e refueling water tank. 7" t ~Ad 4<l4<<
~sf o lP> lS~ t.own oeo /~an~( 8~@ ~pl j +.3/i>- ge4gqrQ, Loss of 480V ]CC 2A6 non-essential ortion The impact of losing this motor control center (MCC) is similar to the loss of 120VAC from power panel 220, since power panel 220 receives power from this HCC.
Evaluation of Plant Response:
The plant response for loss of power panel.220 (120VAC) applies.
Loss of 480Y tiCC 286 non-essential ortion The impact of losing this HCC is similar to the loss of 120YAC from power panel 221, since power panel 221 receives its power from this HCC.
Cvaluation of Plant Response:
plant response for loss of power panel applies.
'he 221 (12CVAC)
Loss of 120VAC VITAL PANEL 2A 1his loss of power will impact the feedwater regul<lting system (FHRS),
steam bypass control system (SBCS) and the turbine generator control system (TGCS). Specifically, in the FWRS control power to one regulating valve and bypass valve will be lost. Additionally, main steam flow input to the SBCS from the FMRS is not transmitted from one channel. The turbine runback mechanism will be without power.
Evaluation of Plant Response:
The feedwater regulating system will still control one regulating 'nd bypass valve. The loss of the turbine runback function is backed vp by instr~mentation on120VAC vital Panel 2B which will runback the turbine inrespo'nse to the decreased feedwater flow. Should the runback not operate properly, a reactor trip may result on low steam generator pressure. Manual operation of the atmospheric dump valves and auxiliary feedwater is available. Should the SBCS operate properly or reactor trip not occur the plant would stabilize at a decreased power condition.
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120VAC Vital Panel 2B This loss of power will impact the feedwater regulating system (FHRS),
steam bypass control system (SBCS), and the turbine generator control system (TGCS). 'pecifically, in the FNRS control power to one regulating valve and one bypass valve will be lost. Additionally, control of the SBCS would be lost. The TGCS would remain functional, but would suffer a loss of the backup to the turbine runback function.
Evaluation of Plant Response: 4
~
The FMRS .will still control one regulating and one bypass ass valve. The SBCS will be without control powet and the turbine would runback in I~
it
~W response to decreased feedwater flow. Should not runback a reactor trip may result on low steam generator pressure. re. The auxiliary feedwater and atmospheric dump valves are available for RCS heat removal. Should a reactor trip not be generated a new ste ad y state at a decreased power level would occur. 7~ eoac.l c 4 ~>'c ~- i&t 4+Ps p sC /~ v/f4 (cth.~ 4( P c/
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Loss of 120VAC Vital Panels 2A and 28 This power loss will impact the RIRS, SBCS, and TGCS.. S p ecifically, feedwater and steam bypass control would be lost and the turbine runback mechanism would lose power.
Evaluation of Plant Response:
F'4
, A reactor trip on 'low steam generator level will result. Automatic actuation of auxiliary feedwater and opening of the main steam safety valves will rel:ieve secondary system pressure. The atm p heric dump h atmos valves and'auxi18ary feedwater will be used to control RCS heat removal.
Loss of 125VOC. Bus 2AB ll t This power loss will impac ~ hee RRS, the PPCS and the TGCS. Specifically, control of the RRS and PPCS, both channels, would be disabled. The turbine trip solenoids and generator underfrequen cy lockout relays would be disabled. The turbine trip solenoids and generator underfrequency lockout relays would be without power {failed {f closed) ~
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I Evaluation of Plant Response:
The CEAs would remain in the position they were- in before the power loss and could be controlled through the CEDHCS by the operator. l(ithout the PPCS, pressure control would be maintained by manual control of the charging pumps and letdown and aU.xiliary spray. Should a reactor trip result, the turbine would not trip electrically but would be tripped automatically on a mechanical overspeed trip. If required the main steam isolation valves would close isolating the turbine and maintaining RCS heat removal functions.
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. 8 4. Im act of Failure in Comnon Sensors The control systems identified in (1) that receive input signals from common sensors are identified below. Oescriptions of,the effect of the ~ 11, malfunctions on the control systems and an evaluation of plant response and backup system availability are also provided. Prudent engineering judgment based on knowledge of system design and transient analysis was used to develop 'these descriptions. The results of this evaluation provide justification that any simultaneous malfunctions of control systems identified herein; resulting from common sensor malfunctions are bounded by the analyses of Chapter 15 and would not require action or response beyond the capability of operators or safety systems.
ftalfunction of Pressurizer Pressure Si nal fails low to the RRS and PPCS If. malfunction causes a low pressurizer pressur signal to be, trans-
@])
mitted, the pressurizer heaters would turn on~ he pressurizer sprays would shutoff+an4-0 h Evaluation of Plang response:
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The reactor uouid]tnP on high pressurizer pressure/
tt 1 td d - dt tt 1 manually and control pressure with the charging and letdown systems
. and auxiliary sprays. Should the reactor not trip, because the appropriate trip setpoints were not reached by the affected parameters
~
(pressure and power), a new steady state would be reached. Operator
, action could maintain power operation until the sensor could be r epair ed q
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,t' Malfunction of Pressurizer Pressure Si nal fails hi h to the RRS q
and PPCS If the malfunction causes a high pressurizer signal to be transmitted,
~ Q tl the pressurizer sprays would come on and the pressurizer heaters would be de-energized. The RRS would adjust the rods in response to the high pressure signal thereby decreasing reactor power.
.f Evaluation of Plant Response: +~@,~<4"g+ 6'1st The reactor would trip onAlou pressurizer pressure, and a SIAS may result.
The operator could close the spray valves and use the charging and letdown systems and auxiliary spray to control pressure. Should the reactor not trip due to affected parameters not reaching the trip setpoints, a new steady state would be reached. Operator action could maintain power operation until the sensor could be repaved.
Malfunction of Pressurizer Level Si nal fails low to the PLCS and PPCS If malfunction causes a low pressurizer level signal to be transmitted, the charging flow would increase and letdown flow would decrease. The
~0 pressurizer heaters would be de-energized if a low enough signal was transmitted.'valuation of Plant Response:
Increasing pra suriz r level would be identified by the operator on Cf. ~C @ff level iud~cetic Cn )alarm in the control room. Iianuai control of the charging and letdown systems could prevent the overfilling of the pressurizer ad preclude a reactor trip on high pressurizer pressure. y~'g z~~>+ >~ boun )ed Qq P~eP'em/ 4lorylhy eve~ le gyp /r'ri2 gi Malfunction of Pressurizer Level Si nal fails hi h to the PLCS and PPCS I'f malfunction causes a high pressurizer level signal to be transmitted, the charging flow would decrease and letdown increase.
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~~- - Evaluation of Plant Response:~~
A decreasing pressurizer level may lead to a possible reactor trip if II on low pressure and SIAS the operator .does not intervene. The SIAS would isolate letdown and charging would be available to restore pressurizer level. Operator could avert'a reactor trip and SIAS through .manual control of charging and letdown based on level indication 'n control room. Malfunction of First Sta e Turbine Pressure Si nal fails low to the RRS If the malfunction causes a low pressure signal to be transmitted the RRS willinsert the CEAs to produce a Tave commensurate with the low pressure signal. This Tave output signal is transmitted to the SBCS affecting its operation. Evaluation"of Plant Response: The reduced heat output from the RCS~ due to the inserting of the regulating CEAs reduces the steam flow to the turbine.. The SBCS receives a low Tave signal from the RRS so the valves will not open. A reactor. trip would occur on low steam generator pressure with a possible MSIS. The main steam safety valves and atmospheric dump valves are available for controlling RCS heat removal. Malfunction of First Sta e Turbine Pressure Si nal fa'ils hi h to the
~~'I'~~~
RRS If the alfunctian causes a high pressure signal to be transmitted~the RRSPm withdraw regulating CEAs to produce a Tave commensurate with the high pressure signal. 4865 QO(Cc WOE PF 7~$ Ol g 4~ 7
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yg ~~>~,>>~< /u J ~y'A~t~~~i/'~cd~w p/sI 5(+st// Jtrs Pe~/eJ S' )gay Ai'S eVe~d W<~/+nod DC( <
~~~AStar S e ~C4an 6 4 ~+a / A 6,C+k~H('/I jV 2 CZ,~A/ Cvl// dam dan@'C/Cy 5'H. Wci'e 4C<r't )4Qp p san Evaluation of Plant Response:~~
The i creased ~eat o put f om the RCS du to withdraw g the egul ting CEAs increa s the team ow to ~he tu ine. he S S rece ves hi Tave signal om t RRS. A mis tch b ween,, ave a pre sure i the eam he er as measur d by e SBC open /the t rbin ypa s valve . The ening of the e val v s sen an
/
tomat'c wi ~draw pro ibit to he co rol. el ment rive chani con ol s ste stopp'ng C withdr al. e ope ator n man lly ower ne ro s or swit to the other RRS channel t resu a stable ndition. Malfunction of Main Steam Flow Si nal fails low to the FMRS and SBCS If the malfunction causes a low steam flow signal to be transmitted, the m FHRS will reduce feedwater flow and the SBCS 'mer open the turbine bypass valves. Evaluation of Plant Response: The mismatch between feedwater flow and turbine demand would produce a reactor trip on low steam generator level. The auxiliary feedwater system and manual control of the SBCS or atmospheric dump valves is available to achieve a stabilized plant condition. T4 Zsa/~Ab~ d ~ /taipei i. 5'4047 IA ~8C jrOn /S. 4 a'. 8 ~dtaadS 4i s S'<tmggs /dna< aS yH O'Sst/ yh seamer Sr((re cc'nasl/s ~y olde Qngl'on& /ir<'pr Q /casa. + /rap Dm 4) 4 /s recur <, p was/ass g ~ Malfunction of Main Steam Flow Si nal fails hi h to the FIIRS and SBCS If the svp malfunction causes a high steam flow signal to be transmitted, a-,s~ Evaluation of Plant Response: e ~~ the RNS will increase feedwater flow and the SBCS may<open the turbine a -w~ p~. w'(Il.mt g " "p d ~l~"N~ The steam generator level. wi'11 increase and thee-may-be-a steam trill )Ml~ct.~. operator could manually control the FURS and SBCS based on steam generator p 71 level and pressure indications in the control room. Should the operator not take action a high steam generator level signal would close the feedwater regulating valves and trip the turbine. A reactor trip
on turbine trip would follow with actuation of auxiliary feedwater on steam generator low level signal. Auxiliary feedwater and manual operatton of the SBCS or atmospheric dump valves provide a mechanism for; RCS heai; removal to stabilize the plant. r ncrcchQp gn FC+plccJ44'*t P4~ cue<~ is-.1 ~ t gg~ ~'5 ~~~~, ~. fh <<~/ySIs in I> f. 3. I QSS WACS ~ maxi'a ~~ >ncrC~e pq Q+Mc ea,s.
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Coo+on Lines/Sensors 13172-310-110 Rev. 10 Ins. P,T,L,F P Process/Sachet S 3/4-RC-127 PDT-1121 C S PDT-1124 'Z Indication On1y PDT-1124 Y Indication On1y 1-RC-104 PT-1104 S PT-1102 (C) S 1-RC>>?05 PT-1103 S PT-1108 Indication Only PT-1102 (A) S PT-1100 (X) P LT-1105 Indication Only LT-1110 X PKS 1-RC-130 'T-1110 V'T-1100 Y PT-1102 (B) S PT-1107 Indication On)y PT-1105 S 1-RC-107 PT-1106 PT-1102 (0) S 2998-6-074 Sh'. 1 SG281 1-1"-l51-108 LT-9023 A S LT-9021 P indicates
Co@non Ta Ens. P T.L F P Pl"ocess/Sachet' ,2998-6-079 Sh. 1 SG2AI I-1" t51-100 LT-9013 A
~~. LT-9011 E-I" lSI-101 PT-8013 A S LT-9013 A LT-9011 I-I" MSI-102 PT-8013 B S LT-9013 B S.~~
I-1" f4SI-103 LT-9013 B E-1" l61-104 'T-8013 C S PT-8113 S indication D-9013 C S E-I" NSI-104 LT-9013 L S I-I" t61-106 PT-8013 D S LT-9005 P LT-9013 D S LT-9113 S indicate LT-9012 P I-1" HSI-116 LT-9012 LY-9013 I-1" f51-107 LT-9005 P LT-9013 D S
Ins. P T L F P Process/Safet S LT-9021 P indicates, LT-9023 A S PT-8023 A S PT-8023 B S'. LT-9023 B S LT-9023 B S PT-8023 L S PT>>8123 S indication LT-9023 C S LT-9023 C PT-8023 0 S LT-9006 P indicates LT 9023 $t LT-9022 . P LT-9123 P indicates LT-9123 , P indicates LT-9022 P indicates. LT-9023 S LT-9006 P indicates
Im act of Failure of Conmon Instrument Line or Ta The attached Table identifies the Comon Line/Tap for protection channel and control channels (or multiple control channels) that are serving multiple -- channels. This table has been reviewed and those lines or taps which were determined to be limiting in their effect on plant response're identified below. The effect of losing protection channels due to a single failure on a commn instrument line or tap, as identified in the response to question 420.06 does not defeat required protection system redundancy. Therefore the effect of losing pnotection channels is not addressed here. Descriptions of the effect of the malfunctions on the control systems and an evaluation of plant response and backup system alailabi'lity are also provided. Prudent engineering judgement .. based on knowledge of system designdand transient analysis was used to develop these descriptions. The results of this evaluation provide justification that any simultaneous malfunctions of- control systems identified herein, resulting from cordon instrument line or tap malfunctions are bounded by the analysis
~~~ ~ ~~~
~~of Chapter 15 and would not require action or response beyond the capability of~~
~~~ ~~~
operators or safety systems. ~ Pressurizer Pressure Si nal PT-1100X and Pressurizer Level Si nal LT-1110'TI-RC.III Systems affected are I'P8; PPCS, PLCS, and SBCS Evaluation of Pressur e Si nal and Level Si nal Failin Low due to Instrument 74 Oama e on P'lant Res onse: d'f malfunction causes a low pressure and level signal to be transmitted, .the pressurizer heaters would turn on~, he pressurizer sprays would decrease flow. T4e-R~e~~4yM~ 4he~~emes~eg~e 1 T.
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d increase charging. Due to the increase in charging> and pressurizer heating the reactor may trip on high pressurizer pressure,~ I'OIRIIRP~ ~kipdd TR p I; I I Cy I d
m ntation from which to evaluate event progress; Manual control of charging, atttaspheric dump valves and auxiliary sprays, without the use of PLCS, PPCS, and SBCS will bring the plant to a stable condition. I4 . P e//W<<ncr 'er
~~+~>>~~
tf) geafi'e/e IASl94 3sueg6 g/5 gc/ frid nS // rer//flr~6'nrl>'r Evaluation of Pressure Si nal and Level Si nal Failin Hi h due to Instrument Ta Dama e on Plant Res onse.:: If malfunction caused a high pressure and level signal to be transmitted, the pressurizer heaters, would de-energize, the sprays would increase flow. The RRS would adjust rods in response to the high pressure signal thereby decreas-ing reactor power. The SBCS would receive a lower Tave input due to the decrease in reactor power and not open the TBVs. The PLCS would ircrease let-and decrease charging. A low pressurizer pressure situation would occur
'own leading to a possible reactor trip and SIAS on low pressure or a new steady state at lower power and pressure. The operator has safety grade instrumentations from which to evaluate event progress. Isolation of letdown on SIAS or by the operator and manual control of charging with pressurizer spray i<~>solation will bring the plant to a stable condition without using the PLCS, PPCS, and SBCS.
Evaluation of Pressure" Si nal '.Failin Hi h and Level Si nal Failin Low due to Instrument Ta Dama e an Plant Res onse: The plant response is similar for the PPCS, RRS, and SBCS as discussed above ( for the pressure signal failing high. The PLCS, however would increase charging 'f and decrease letdown., The increase in charging and pressurizer spray flow with no pressurizer heaters may lead to a law pressure condition or a steadily ! I increasing pressurizer level. The operator has, safety grade instrumentation from which to evaluate event progress. thnual control of charging and turning off. pressurizer sprays will bring the plant to a stable condition. '7$ c, ~n Ms ki< 4oe" Qe- j/cssfer e'eig~a/f eqmcfg~vcl gpfm/ @/li/pfPi~L wj/Q/l P /P/9 gd@h+P/0+
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I I I I'P IFI I dl 1di~IFili 818 due to Instrument Ta Dama~ e on Res onse: IA~~~~I As discussed in the evaluation for both signals failing low the PPCS~~~and is similar. increase letdown and decrease SBCS chargihg. response
- ~. The PLCS, however would ~. r ,888 FF I surizerr w~muve. The operator can manually control 'charging to increase pres-level and isolate letdown flow. The, plant can be brought to a stable condition through operator action and manual control of the PPCS, PLCS, and S8CS. ~
I Pressurizer Pressure Si nal PT-1100Y and Pressur izer Level Si nal LT-1110Y ~Ta I-RC-130. P The systems affected and the evaluation of plant response are the same as those described above for pressurizer pressure signal (PT-llOOX) and pres-surizer level signa'i (LT-1110X)-- Steam Generator Level Si nal. LT-9021 and LT-9011 Ta I-1" NSI-108. System affected is the RlRS Evaluation of Level Si nals Failin Low due to Instrument Ta Dama e on ~Pl II If the malfunction causes a low steam generator level signal to be sent from both transmitters then the flo'w control valve would open ta increase level for both steam generators. As feedwater flow increased the B(RS would note a mismatch between main, steam and feedwater flow. This would close the flow control valve to match feedwater and steam flow. An oscillation of the flow control valve with inc&easing steam generator level results leading to a high steam generator level signal being sent from the reactor protection system to close the control valves and trip the turbine. Should the control valves not close and turbine not trip the operator could take manual action to close the valves or stop the feedwater pumps. Finally a high-high steam generator level signal would close the fe'edwater pump discharge valves should the above actions not occ r.~~luwyc4 fMMa- f/>c'y ~Ur+ /4 &+Iw)f r/rf<) k>II'/IS 5@< ., gnac-pn~oodnnn rIIo nIdopi'lvknr /jIo'.IooFMIn f/ooo a'uo /a n fox/ul~ nI pc do.oQg Evaluation of Level Si nals Failin Hi h due to Instrument Ta Dama e on
~P If the malfunction caused a high steam generator level signal to be sent from both transmitters then the flow control valve would close to decrease level for both steam generators. As feedwater flow decreased the FHRS would note a
e t,
mismatch between'main steam and feedwater flow. This would open the flow 1 control valve to match feedwater and steam flow. An oscillation of the flow
~~'control valve with decreasing steam generator level results, leading to'a reactor trip on low steam generator level. Auxiliary feedwater would be automatically eedwa er flow. i~~ ~'>~~
1
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~~>'van due to Instrument Ta Dama e on Plant Res onse:~~
One steam generator wo'uld experience a decreasing level due to closing of the control valve on receipt of the failed high level signal. The other steam generator would experience an increasing level due to opening of the control valve on receipt of the failed low level signal. The result would be either a reactor trip on low steam generator level or a closure of the control. valve on high p steam generator level with a turbine trip. Additionally, the operator can take appropriate action (manual reactbr trip with auxiliary feedwater actuation) based on safety grade steam generator level instrumentation. Qi'yjdfgsiSS m ~b'av~ ~eepapja'dj u g)y ~a ~~)s
'LT-9005 and LT-9012 Ta l-l "-NSI-106 Steam Generator Level Si nal s System affected is the FWRS Evaluation of Level Si nals Failin Low due to Instrument Ta Dama e on Plant ~Res onse:
~~Hide range steam generator level will indicate a low level condition on one steam generator. The operator will still have safety grade steam generator~~
. level indications to r ely on (one safety channel of the four safety charm'els will also be lost .foi that steam generator). Additionally, on the same steam generato Ytfijgfnst'cementation and control of.the feedwater bypass valve sends a signal to open the valve and actuates a low level alarm in the control t room. However since, a turbine trip, signal is not present it will not open the valve. ,For conservati,sm it is assumed to open increasing flow to the steam generator. The intact portion of the FWRS on that steam generator will see the increased level and close the regulating valve enough to main'tain level.
Should this regulating valve control work improperly~a high steam generator'evel will cause closure of the feedwater regulating valves and turbine trip. The operator can use. the auxiliary feedwater system to maintain adequate inventory in the affected steam generator and may choose to manually trip the plant based on safety grade instrumentation readings conflicting with process instrumentation and control actions. -] $ d. dld4sfiqvjy j5 jmoupsdscE pci +i1d +n mlma5~+ I F~~v>~ f/~~ dmvmffff- P~ 55c+i'mn. l~~/u fubj"E~ mi55uw& 'Pi~ @"~<1,
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Evaluation of evel Si nals Pailin Hi h due to Instrumentation Ta~Daaa e on Plant Res onse: Hide range steam generator level Iill i'ndicate a high level condition on one steam generator. The operator wi11 still have safety grade steam generator level indications to rely on (one safety channel of the four safety channels ivill also be lost for that steam generator). The control and instrumentation for the bypassyl valve >vill see the high level signal and actuate a high level a'larm in the control room. The operator based on safety grade instrumentation will see normal level because the FHRS valves are not acting improperly. However, due to erronous level signals he may take manual control of the RJRS and eventually trip the reaCtor using auxiliary feedwater to control steam generator inventdry. Evaluation of One Level Si nal Failin Hi h and One Level Si nal Failin Lou<One to Instrusent Ta Oama e on Plant Res ense: ~ Hide range steam generator level indication does not control a system and the
~~~ ~ ~ ~~~
~~operator will compare~~
~
it
~~~ ~ ~~~
~~to safety related instrumentation to ascertain the true reading. Failure of the instrumentation and control of the feedwater~~
~~~ ~ ~ ~~~
bypass valve is ~~+br+ discussed previously. Steam Generator Level Si nals LT-9006 and LT-9022 Ta l-l" MSI-114 The systems affected and evaluation of plant response are the same as for steam generator level signals LT-9005 and LT-9012 for instrument tap 1-1 "tlSI-106.
Condenser Stora e Tank Level Si nal.s LT-12-llA and LT.-12-11B The other control channel transmitters shaving a common tap not identified in the table are'the Condensate Storage Tank level transmitter LT-12-11A and 118. Individual root valves and excess flow check valves are added to ensure that instrument line rupture in one channel does not affect the other channel. The only, failure .affecting both channels is the break of the tap. For diversity, bn safety related level switches provide low level alarms on the safety annunciators. Since the function of LT-12-11A and 118 is only indication and alarm and since alarm backup is provided a tap failure. would not cause system . actions, required to be analyzed by Chapter 15 of the FSAR. t
0803M-4 420.14 The reactor protection system (RPS) includes two trip inputs (7. 2) (turbine trip and loss of component cooling water trip) which are classified as not being required for reactor protection. It is the staff's position (BTP XCSB 26) that all reactor trip inputs to the RPS are required to meet the design requirements of IEEE 279 without exceptions This includes the entire trip function from the sensor to the final actuated devices'SAR Chapter 15 shows that the accident analysis tak s credit for reactor trip on turbine trip. FSAR Subsection 7.2.2.2.11 states that the turbine trip is taken from non-Class XE hydraulic oil pressure switches. The use of non-Class IE switches is not acceptable. Also, it is not clear that the component cooling water trip meets the requirements of XEEE-279. Therefore, provide a description of these and other such RPS inputs with respect to their conformance to BTP ICSB 26. This design description should be supported with electrical schematics, logic diagrams, piping and instrument drawings, test procedures and technical specifications. sponoe The Chapter 15 accident analysis does not take credit for reactor trip on turbine trip to mitigate the results of any event. This is so stated in note 7 to Table 15.0-7. The sequence of events analyses presented in Chapter 15 recognize that such a trip exists and may occur. For the Increased Feedwater Flow (with failure to achieve a fast transfer at a 4.16 kV bus) event presented in Subsection 15.1..2 turbine trip.
', it was more adverse to trip the reactor on This was done to increase the cooldown for this increased heat removal event. This event is discussed in the response to Question 420.11, ~ /,I M hougg thapvoa:reps at/not raq~sMa~wgr~azeqyg g q>cQp is~ Cia, XEc4-t acco a c wipt~&ERg2V9. ~+&oint. on, e:vic6~
~~Ad, $ ~ir ine ~tr. ~ptits-to~Efie-RPS -accordance-wi~~
~~~gu3.a tp Cy '6Qp~li:U gf .:9 420. 14-1~~
a- Loss of CCW Trip Four (4) flow transmitters FT-14-15A,B,C a D are located on the CCN common return header to monitor CCW flow from the RCP's. These four (4) transmitters are powered from redundant Class lE power supplies (MA, MB, MC 6 MD) and are physically and electrically separated in accordance with the RG 1.75. CCW flow out of the RCP's are continuously monitored and displayed on RTG Board 206 in the control room. Upon detection of loss of CCW from the RCP's an alarm in the control room will alert the operator about the low flow condition so that a proper corrective action can be taken immediately. Xf flow is not reestablished in 10 minutes the RPS is actuated to trip the reactor. The test switches are also provided on the RTG Board 206 to enable testing the indicator-bistable. Please refer to the CWD sheet 206 (2998-B-327) for the complete circuit. he component cooling water trip meets the requirements of IEEE-279-71 as described in the FSAR Chapter 7.2.
Isolation devices (rated 2000V) are provided for the turbine trip inputs to the RPS in accordance with RG 1.75 and are routed as described below such that there are no credible events that can compromise the function of the RPS. General The turbine trip input cables are terminated at TB 'A'ocated at the north end of the Turbine Generator Building pedestal and are routed to EL 43.00 of the Reactor Auxiliary Building (directly under the Reactor Protection System Cabinet). Each of the four cables are routed in its own dedicated conduit the entire length and is uniquely identified NMA, NMB, NMC, NMD. No other cable is permitted to be routed with these cables. 1 The cables concerned a~identified as follows: Channel NMA 20710 U (NMA) Channel NMB 20710 V (NMB) Channel NMC 20710 W (NMC) Channel NMD'0710 X (NMD) ~S ecific Cable Routin TB 'A's located at the north end of the Turbine pedestal at EL.62.00. Each cable is routed in its own embedded conduit in the pedestal and down the pedestal leg. The conduits exit the pedestal leg and run embedded to an electrical manholes as follows: MH 256 For Cables 20710 U (NMA) and 20710 W (NMC) MH 257 For Cables 20710 V (NMB) and 20710 X (NMD) Inside manhole 256, cables 20710 U and 20710 W are routed in their own flexible conduit on opposite sides of the manhole from the west to the east walls. High voltage cables, 6.9kV and 4.16kV are routed in this manhole, however the flexible condui.ts are routed in such a manner so as to maintain a minimum separation of 18 inches from all high voltage cables. This separation is reduced to 12 inches at the west face for a distance of 6 inches, as the flexible conduit converts to an embedded conduit. Inside manhole 257, cables 20710 V and 20710 K are routed in their own flexible conduit on opposite sides of the manhole from the west to the north walls. Again as was the case from manhole 256, high'oltage cables of the 4.16 kV and 6.9 kV class are routed within the manhole. However, the flexible conduits are routed in such a manner so as to maintain a minimum separation of 24 inches from all high voltage cables.
Each manhole although non safety related and therefore categorized as non seismic category I, is designed similar to, ie. rebar etc a seismic manhole such that during a seismic event, MH256 or MH257 will behave similar to a seismically designed manhole and will not fail. It must be noted that the 4.16kV and 6.9kV cables are designed with metallic lead sheaths and all cable is class IE qualified, meeting the requirements of IEEE 383. The cables exit the manholes in their own embedded conduits and are routed into the Reactor Auxiliary Building basement where they enter pullboxes. , From each pullbox, the cables are routed in their own separate and indepen-dent conduits up the west Reactor Auxiliary Building wall to the isolation boxes mounted under EL 62.00 gust below the RPS cabinet. From the isolation boxes, the class IE cables 20710H-(MA) 20710J MB) 20710K (MC) and 20710C (MD) are routed in their own conduits and enter their respective sections of the RPS Cabinet. On the basis of the special treatment of these cables, beyond the requirements of RG 1.75, as described above, we can see no credible event where cables of high voltage (6.9kV and 4.16kV) can come in contact with the turbine trip
~~'cables to the RPS.~~
Turbine trip inputs to the RPS are properly isolated through con- separate-mounted isolation relay box. The relay-box is a NEMA 4 type struction, with adequate mounting and physical separation design that meet IEEE-344-1975 and RG 1.75 requirement. pry,c qualified fd'he isolation relay is Agastat EGP type which ha been control report, to XEEE-323-l974.. As described in the attached system
~~@he 'Mw9.eel='a~x~~4bz~'he EGP type relay ~side.~~
at least 2000 volt, RMS isolation from the coil side to the contact
0 On October 30, 1980, Systems Control conducted.43al:eel.r~ tests on two Agastat EGP relays which are IEEE-323 prequalified type relays, The first relay, described hereafter as "Test Vehicle Nl," was a type EPG1001, serial number 80411508, and with a 120 VAC, 60 HZ coil. The second relay, described hereafter as "Test Vehicle 12<" was a type EPGD001, serial number 80411510, and with a 125 VDC coil. The test was divided into two parts. "In part one>> both relays were subjected to upwards of 5,000 VDC and the leakage current measured. A Hipotronics series 300 Hipot and Megohmeter, last calibrated on March 18, 1980, was used to supply the voltage and measure the leakage current. Each test vehicle was attached to a type CR0095 socket and properly seated in place with type CR0155 locking straps. (See the attached data sheet on Agastat sockets and straps). The relays and sockets were then mounted on a 2 x 6 wood board. The test was effected by attachi.ng the hot lead from the Hipot and Megohmeter to one side of the relay coil while the ground lead was connected to one ot the contact connections. The voltage was then increased from zero to either 5,000 volts or until the Hipot and Megohmeter automatically. shut itself down when the leakage current exceeded 5.5 milliamperes. The voltage was then reduced to zero and the ground lead attached to another contact connection and the test repeated. Nhen all the contact connections had thusly to been the other tested, the Hipot and Megohmeter hot lead was connected side of the coil and the whole series of tests repeated. During automatic shutdown, the highest attainable voltage was recorded. Attached please find the data results from the above described tests. P ~ In view of the above, we must conclude the Agastat GP type relay will qualify to the specified 2,000 volts RMS isolation. In addition, the manufacturer guarantees a 2,000 volt RMS isolation for the Agastat relay.
Test Vehicle P2 EGPDOOI Relay S/N 80411510 125 VDC Coil Connections Voltage Current Between Terminals AC (RMS) DC AC DC 84 to 82 5,000 5,000 100ua .IOua ~ 84 to T2 5,000 5,000 1000a .IOua 84 to M2 4,200 5)000 .095ua 84 to R2 4)300 5,000 .095ua 84 to R4 4,000 5,000 .120ua 84 to M4 3,900 5,000 .115ua 84 to T4 4, 200 5)000 .IIOua 84 to 83 5,000 5)000 eoua .090ua 84 to T3 5) 000 5,000 100ua .IiOua 84 to M3 4, 200 5,000 .115ua 84 to R3 3,900 5)000 .105va 84 to Rl 3) 600 5,000 .120ua 84 to Ml 3,600 5,000 .120ua 84 to Tl 4,400 5,000 ..115ua 84 to Bl not +~ not"~ tested tested Bl to Tl 4, 400 5, 000 .I30ua Bl to Ml 3) 500 5,000 .125ua Bl to Rl 3, 500 5,000 .120ua Bl to R3 3,900 5,000 .IIOua BI to M3 3,900 5,000 .105ua Bl to T3 5,000 5,000 120ua .100ua Bl to 83 5,000 5,000 100ua .095ua Bl to T4 4,200 5)000 .105ua Bl to M4 4,000 5,000 .120ua BI to R4 4, 200 5,000 .125ua Bl to R2 4,500 5,000 .095ua Bl to M2 4,300 ',000
~ 095ua Bl to T2 5,000 5,000 120ua .IOOua Bl to 82 ,5)000 5)000 110ua .IIOua Bi to 84 not "" not ~~
~~tested testod~~
~
~~current exceeded 5.5 milllamporos~~
~~'ndicates 84 to Sl refg re~+~~
0 ~ ~ Test Vehicle /ll FGPIOOI Relay S/N 804ll508 l20 VAC/60 H;. Coli Connections Voltage . Current Between Terminals AC (RMS) DC Ac DC 84 to 82 5,000 5,000 120ua .055ua 84 to T4 5,000 5,000 l20ua .065ua 84 to M2 4,300 5>000 .065ua 84 to R2 4,300 5,000 .060ua 84 to R4 4,200 5>000 .070ua 84 to M4 4,300 5,000 .075ua 84 to T4 4,300 5>000 .065ua 84 to 83 5,000 5,000 l20ua .050ua 84 to T3 5,000 5>000 l20ua .060ua 84 to M3 4,000 5,000 .050ua 84 to R3 3,900 5>000 .050ua 84 to Rl 3,800 5,000 .065ua 84 to Ml 3,800 5,000 .065ua 84 to Tl 4,500 5,000 .070ua 84 to Bl noW> not"~ tested tested Bl to Tl 4,400 5,000 .060ua C Bl BI to Ml to Rl 3,800 5,000 .065ua 3>800 5,000 .060ua Bl to R3 4,IOO 5,000 .050ua Bl to M3 4,000 5,000 .055ua Bl to T3 5,000 5,000 I20ua .060ua Bl to 83 5,000 5,000 l20ua .045ua Bl to T4 4,500 5,000 .055ua Bl to M4 3>900 5,000 .075ua Bl to R4 4,000 5,000 .070ua Bl to R2 4,200 5,000 .060ua Bl to M2 4,000 5,000 / .060ua Bl to T2 5,000 5,000 $ 20ua .065ua Bl to 82 5,000 5,000 l20ua .055ua Bl to 84 not+4 not W<
~~,tested tested h h ~ +~~
I Indicated current exceeded 5.5 millfamperes p< 4. 8 I re L~y coQ h 1~ ~
uestion No. 0.54 FSAR Subsection 7.6.3 describes additional systems re-quired for safety. Overall, the FSAR information supplied to date does not sufficiently describe the instrumentation and controls associated with most of these systems. There-fore, please provide the following information:
~~a. Identify and describe the instrumentation and 'controls associated with each system listed below:~~
~~Fuel pool cooling and purification .system Process and effluent radiological monitoring and sampling system Containment vacuum relief system Shield building ventilation system~~
~~b. For each instrument and control identified in (a)~~
~
~~above, designate whether the equipment is Class~~
~~,1E or non-Class 1E.~~
c. For each system listed in (a) above, discuss the qualification criteria applied to its associated instrumentation and controls. As a minimum, you are requested to include for each system, a dis-cussion of how the instrumentation and controls for that system conforms to the requirements of IEEE 279-1971, IEEE 308-1974, IEEE 323-1974, and IEEE 344-1975.
~~~Ree onsa~~
~~8) I) FUEL POOL COOLING AND PURIFICATION SYSTEM The fuel pool instrumentation .system is described in" Section 9.1.3.2.4. A tabulation of the instrument channels xs included xn Table 9.1 7.~~
~~~ ~~~
II) PROCESS AND EFFLUENT RADIOLOGICAL MONITORING AND SAMPLING SYSTEM The radiation 'monitoring system is composed of three process, seven effluent, forty one area, and four inplant airborne monitors. Tabulations of these monitors are given in Tables 11.5-1, 12.3-2, and 12.3-3. III) CONTAINMENT VACUUM RELIEF SYSTEM The instrumentation provided for this system is in accordance with the revised Figure 3.8-8 and contains the following equipment:
- PDT-25-1A (lB) with its electronic PDIS-25-lA (lB) is interlocked with pCV-25-7(8) by energizing SE-25-10(ll) to open FCV-25-7(8) when the differential pressure between the containment and annulus reaches -9 '5",H20 + 0.25" H20 PDIS-25-1A(lB) also pro-
~~vides indication on the HVCB for gP range of~~
--25" H20 to + 25 H20. - PDT-25-'13A(13B) with its electronic PDS-25-13A{13B) is interlocked with FCV-25-7(8) by deenergizing SE-25-10(ll) to close FCV-25-7(8) when the dif- .'-'ferential pressure reaches -7.75" H20. - PDIS-25-llA(11B) provides local full range indication and a high alarm on the HVCB at 11.5" H20.
~~PDT-25-15A(15B) with its PDI-25-15A(15B) provides~~
~~. full range {-25" H20 to 25" H20) indication on the HVCB.~~
IV) SHIELD BUILDING VENTILATION SYSTEM The Shield Building Ventilation System is R,A E5F System and is listed in Section 7.3 of the FSAR. The SBVS switchcve< from Fuel Handling Building is the only portion of this system listed in Section 7. 6. Qg@ 5PQQ is described in Section 6.2.3.2 of the FSAR. The instrumentation requirements are provided in Section 6.2.3.5 and Table 6.2-51 of the FSAR. b) I- Tc (le g f-7 ('g<Qi'p'Gs egg gQ 1'YliM~i~~~~'o ~'" '" ~~ & P~ Soli'~ aV gri'$h 4e~ 5ys/~ ~ II - Tstack,
~
e ass u nt monitors are the plant as described in subsection 11.5.2.2.8, and the ECCS exhaust monitors, as described in subsection 11.5.2.2.10. The Class lE area monitors include the fours]QS and 6 spent fuel pool monitors, as well as two post-accident monitors. All these monitors are described in subsection 12.3.4.1.4. The Class lE in-plant monitors include the containment at mosphere monitors, as described in subsection 12.3.4.2.3.1, the control room air intake monitors, described in subsection 12.3.4.2.3.2, and the ECCS exhaust, monitors, as described inr subsection 12.3.4.2.3.3. III 'All PDT's; in item PDIS's; PDS's and. PDI's discussed a) above are Class 1E. IV - Instrumentation and controls discussed above for SBVS system are Class lE. Alarms are ahnoun<ta~on non-safety annunciation windowS through proper isolation devices. v>
c) XHEE Xr XXX-323-19'/4 I - jig Q~j'<AIE'/nSQ~ ib Tubal< All XEEE Class a) above are T'4~ IEEE 279-1971 Keuh Q~/e AND IHEE 344-1975 J-Wm idc,~<'b~ lo 7ECt" 9z3-'79 a+ 9<<o H7>
~~~ i<~l~"~~
1E inonitors are cjualifi.ed to 323-1974 and IEEE 344-1975. All pressure transmitters listeQ in 'l item qualified to IEEE 34'4-,1975 and XEEE 323-1974 in the environment in which they operate. The remote mounted indicators and bistables are mounted on the seismically qualxfied HVCB in the control room. IV All controls and instrumentations for SBVS is qualified to IEEE 32 -1974 apd XEEE p4g-l)7$
~~~o ~i+~~
~~eN t wdi~+0<S ~~~
~~e. EdigM<ca(Lf P.c IO[>S~4 l+~~~
~~[>Pi+ ~ 'pg~~
~~/n T<~~
The four containment areas radiation monitors which input into the&$ 5 MEAe 55IS XEEE 279-1971 similarly with the ESPAS as described in S cti .3.1.2 of the FSAR. C~ The re@ i,amen mWefy'~e. f IEEE 79-1971 for'gA ectffieds I/5 fE'~N'E y'egiue4Q <<sf r~plefsfg apF7itabldke C~.u Sd this instrumentation is not part of a protection system. However, the intent of the design criteria contained therein has been applied in the design of these systems to the following extent: 4.1 General Functional Requirements The safety related instrumentation for the above systems is designeQ to provide monitoring and actuation as applicable during normal or accident conditions. The instrument performance characteristics, response times and accuracy are selected for compatibility for the particular function. 4.2 - Single Failure Criterion. This is functionally identiCZ~to that described in Subsection 7.4.2.2. 4.3 Quality Control of Components and Nodules See Chapter 17 4.4 Equipment Qualification The instrumentation and controls for these systems meet the equipment qualification requirements. discussed in Sections 3.10 and 3.11. s I SUL 3 4 ')98) s/i
4.5 Channel Xntegrity The "Channel Integrity" is functionally identical to that discribed in Subsection 7.3.2.1.2. 4.6 - Channel Xndependence The channel independence is functionally~'denti~ to that described in Subsection 7.3.2.1.2. 4.7 .- "Control and Protection System Interaction" No portion of these systems is used for both control and protection. 4.8 "Derivation of System Xnputs" The monitoring signals for the above systems are a direct measurement of the desired variables. 4.9 "Capability for Sensor Checks" The monitoring sensors are checked by comparing the monitored variables of redundant channels or by ob-serving the effects of introducing and varying a sub-stitute input to the sensor similar to the measured variable. 4.10 "Capability for Test and Calibration" XEEE 338-1971 and Regulatory Guide 1.22, "Periodic Testing of Protection System Actuation Functions" 2/72 (RO) provides guidance for the development of procedures, equipment and documentation of periodic testing. The measurement signals required for the above systems have the capability of being tested and calibrated under the design requirements of the system. 4-11 "Channel Bypass or Removal from Operation" Any one of the channels may be tested, calibrated, or repaired without detrimental effects on the other channels. 4.12 -,, "Operating Bypasses" There are no "Operating Bypasses" for these systems. 4.13 "Indication of Bypasses" A discussion of bypass and inoperable status indication in-is provided in Subsection 7.5.1 and a listing inofTable operable or bypassed components is contained 7 3-10 4.14 "Access to Ileans for Bypassing" This section is not applicable. 'i, v O< a<ms<
I 4.15 "Multiple Setpoints" This section is not applicable. 4.16 - "Completion of Protective Action Initiated" Once it is This section is not applicable. 4;.17 - "Manual Initiation" Manual initiation of the components in these systems is avai.'lable, 4.18 "Access to Setpoint Adjustments, Calibration, and Test, Points" This section is not, applicable. 4.19 - "Xdentification of Protective Actions" This section is not applicable. 4.20 "Xnformation Readouts" The monitoring and control channel fqr~ese systems Q J (oo~ are indicated in the control room +'%~+it~' ~"&~ ly QyLk s~'QJl Gn. Is ~* 4.21 - "System Repair" Replacement or repair of components can be accomplished p,( ~~c~ve aW in reasonable time when the systems are not actuated.. (%vcr AY~~ Outage of system components for replacement or repair Q nhlA 6 + + ~ are limited by the Technical Specifications. goo 4.22 - "Identification" li Safety equipment anQ cables associated with these systems are uniquely identified. XEEE 308-1971 The St Lucie Unit 2 FSAR is committed to Regulatory Guide,1.32 Rev. 0 which addresses IEEE 308-1971. For a further discussion of XEEE 308-1971 refer to FSAR Section 8.3.1.2. All class lE electrical components are electrically and physically separated in accordance with Regulatory Guide 1.75 as discussed in FSAR Section 8.3.1.2. Electrically redundant, and physically com-.independent, power supplies to the above systems, electrical
~
ponents, and to the safety related power panels that provide power to control and instrumentation devices are provided. C
I All Class lE electrical system components are uniquely identified in accordance with FSAR Section 8.3.1.3. The fuel*pool purification pump is a non-safety pump and as such is physically independent and electrically separated from Class 1E components.
SL2-FSAR
~~~ ~~~
h) Piping and Valves All the piping in the Fuel Pool System is stainless steel with mostly welded connections throughout.. All the valves in the Fuel Pool System are stainless steeel, at least 150 pound class. 9.1.3.2.4 Instrumentation Requirements A tabulation of ins rument channels is included in Table 9.1"7 9.1.3.2.4.1 Temperature Instrumentation a) Fuel pool temperature indications are provided locally and high temperature alarms are actuated in the control room to warn the operator of a system malfunction. Two separate instrument channels are used due to the importance of preventing the fuel pool water from boiling resulting in a loss of fuel pool water. Fuel Pool Heat Exchanger Inlet Temperature: Local indication of the fuel pool heat exchanger inlet temperature (tube side) is provided. This indication, in conjunction with the heat exchanger outlet tem-perature and component cooling water temperature, serves as a measure of fuel pool heat exchanger performance. .) Fuel Pool Heat Exchanger Outlet Temperature: Local indication of the fuel pool heat exchanger outlet temperature (tube side) is pro-vided. 9.1.3.2.4.2 Pressure Instrumentation a) Fuel Pool Pump Discharge Pressure: The discharge pressure of each fuel pool pump is indicated locally. Fuel Pool'Pumps Discharge Header Pressure discharge header pressure switch for the fuel pool pumps serves to A activate a low pressure alarm in the control room to warn the opera-tor of system malfunction. c) Fuel Pool Purification Pump Suction Pressure Suction pressure to the fuel pool purification pump is indicatpd locally. This indication," in conjunction with the fuel pool purifi-cation pump discharge pressure gage serves as a measure of fuel pool purification pump performance. Fuel Pool Purification Pump Discharge Pressure Discharge pressure of the fuel pool purification pump is indicated locally.
~~JU< s<~~~
~~SL2-FSAR e) Fuel Pool Purification~~
~~~ ~ ~~~
~~Filter~~
~
~~and Fuel Pool ion Exchanger Di Cferen-tial Pressure~~
~
Differential pres ure of the fuel pool purification filter and the fuel pool ion exchanger are indicated locally. Periodic readings of these instruments indicate any progressive loading of the units. 9.1.3.2.4.3 Level Instruments a) Fuel 1'ool Water Level The fuel pool water, level is monitored by two redundant level switches. These switches actuate high or low alarms in the control room to warn the operator of system malfunction. Two separate level" channels are used due to the importance of maintaining 'nstrument fuel pool water level. 9.1.3.3 ~Egret Evalua".lua With one-third of a core batch, which is assumed to have undergone finite irradiation of three years, placed in the spent fuel pool seven days after 'sreactor shutdown and 12.48 x 10 six previous annual refueling batches, the heat load BTU/hr. Under these conditions, with one fuel pool pump operating and the fuel pool heat exchanger in service, the spent fuel pool temperature does not exceed 125 F. During a full core unloading, it is assumed that one full core is placed in the fuel pool seven days after reactor shutdown. One-third of a core from a previous refueling is assumed'to have been stored in the spent fuel pool for 90 days with six previous annual batches. The resultant. )eat load from one full coze and seven annual refueling batches is 2.99 x 10 BTU/hr, the maximum heat load in the fuel pool. Under these conditions, both the fuel pool pumps are in service to limit the maximum fuel pool water temperature to 150 F. With one fuel pool pump inoperable, the fuel pool equilibrium temperature is 160 F. All connections to the fuel pool are made so as to preclude the possibility of siphon draining of the fuel pool. Any leakage from the fuel pool cool-ing system is detected by reduction in the fuel pool inventory. Makeup to the fuel pool is from the refueling water tank. Makeup inventory to the fuel pool is provided in Subsection 9.1.3.3.1 ~ During accident conditions, the Fuel Pool Cooling System is isolated from the Component Cooling Water System. lfowever, multiple sources (seismic, and non-seismic) of makeup water exist ns discussed in Subsection 9.1.3.3.1. The purification loop normally runs continuously during fuel pool operation Co maintain the fuel pool water puri.ty and clarity. lt is possible to operate the purification system with either the fuel pool ion exchanger or fuel pool filter bypassed. Local sample points are provided to permit ana-lysis of fuel pool ion exchanger and fuel pool filter efficiencies. 9.1-13
2-FSAR TABLE 9.1-7 FUEL POOL SYSTEH INSTRUMENTATIOH Ins truant Systcn Par~ter Indication hlara Inatruisent Homal Instrune Identification 6 Control Control Operating
Ãuaber Location Local itssls less I Roon ~RCC C ~Rcs C ~RCC'J CC TI"4420 Fuel Pool Temperature Hi 0-200 F 120-150 P TI-4421 Fuel Pool Temperature Hi 0-200 F 120-150 F +4F ASSI TI-4404 Fuel Pool Heat 0-200 F 120-150 F +4P N~ IE Exchanger Inlet Teslp TI-4405 fuel Pool Heat 0-200 F 108"128 F EXChanger Out let Terip.
LS-4420 Fuel Pool Mater Level Hi 6 Lo + 1" Cla5S IC LS-4421 fuel Pool Mater Level Hi 6 Lo + 199 CpnbSI~ Pl-4402 'Fuel Pool Puap ZB 0-60 psig 40-50 psig + 1.2 psi Ncmlf Discharge PI-Ii401 Fuel Pool Punp 2A 0-60 psig 40-50 psig + 1.2 psi Iilrbl+ Discharge Pressure Pl-4411 Fuel Pool Purification 0-25 psig 5-10 psig + .5 psi Id Pvilip Suction Pressuri ~ PS-49403 Fu>>l Pool Piup Discliargc ll,ad>>r I'ressur>> 40-50 psig + 1 psig {(~IF P 1-4412 Fuel Vcipl. Purification 0-100 psig 95-90 psii s 2 psii Cis 2+'I Pu:.2)! .'C..scharg>> Pres..ure PDI-4415 Fi'i'l Ps)22 ~ Pu'r Lf 'Lest iisn 0-30 psid 5-30 paid + .6 psi Fill.cr ')ifI>>r>>ntial Pressure PDI-4416 Fuel ol ion 9" in'a Exr'.Rn:9:.er 0-30 psid 7-10 psid + .6 psid life IE Di I! iir 'I Pr" 2.222 I:
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SL2-FSAR valve is opened automatically when the annulus differential pressure reaches one in. wg negative. The check valve in the cooling line- is designed to have a pressure drop of not more than 2.5 in. wg and to o"..n at 1.4 in. wg negative to provide vacuum control in the system and to allow outside air to cool the filters. The SBVS is also interconnected to the spent fuel pool area exhaust duct. Upon receipt of a high-high radiation signal in the fuel pool area, the exhaust air is directed to the SBVS filtration units. The c'"tor operated butterfly valves I-FCV-25-30 and 31 open and the exhaust fans start automatically. The motor operated valves I-FCV-25-32 and 33 clos. tn isolate the, annulus=; Although a fuel. handling accident insid th concurrent with a LOCA is not considered a design b "is event, a Ci.'~S overrides the Fuel Handling Building high-high radiation signal a initiates the depressurization of the Shield Building annul . The Fu.l Handling Building Ventilation System is further discussed in Sub" etio.~
~~.4.2.~~
Each of the SBVS intake trains is also connected to the Continuous Con-tainment/Hydrogen Purge System. This connection, manually in'.tiated from the control rocm, provides hydrogen purge capability while mini.:.iz-ing offsite radiological consequences. The Continuous Containment/Hydrogen Purge System. description is provided in Subsection 9.4.8.8. Both SBVS subsystems are automatically started by a CIAS or high-high radiation signal fran the Fuel Handling'uilding. One can be manually shut down and placed in the standby mode. The standby subsystem auto-matically restarts if the operating subsystem should fail. Th cross con-nection valve is opened from the control room to assure air flow throu:h the failed system. Detectors in the charcoal beds annunciate temp r"..""".-.: exceeding 200 F. 6.2.3.3 Desi n Evaluation 6.2.3.3.1 Performance Requirements and Capabilities Each of the two full c-pacity Ean-filter trai..s of the Shield System, along with the Shield Building, are designed to Bu'entilation fulfill the perfonnance requir'ements stated in the design bases in Subsection 6.2.3,1. The analysis of the Eunc'tional capability of t'.;" S3VS to i:,:)re."s " . and maintain a uni form negative pre."2 ." within th" Sh =!":. annulus is performed Eor the 9.02 E- double cnd d su:tion 1 s3:: break LOCA usin~ tho liATFHPT computer co'e d=s i 1';1 in The description oE the development of the pipe break mass and release rate and the containm nt initia1 conditions are contain:..l in " section 6.2.1. Any additional initial conditions or changes Ere~ t':.o.=. listed in Subsection 6.2.1 are contai>>cd in T-~ 6.2-49. T)i s:. transfer coe Eicients are applied whether the surface temperature cxc cds the annulus atmosphere or the annulus atmo""her" t..:i aratu:.u "x. '"!s t!::: surface temperature. JUL py gg 6 '-47 A
SL2-FSAR 6.2.4 COllTAIhMCtlT ISOLATIO" ,SYSTEM The containment ieolation system provides the means of isolating fluid sys-tems th-.t pass through cont=~"..-...cnt pcnctrations such that any radioactivity the.1. r -y be released into the ccntainment atmosphere following a postulated design basis accident (DEA') is confined. There is no o~e particular rv;."':"; co:..1."etc conl asl>>ne ifolation, but isolation design is provided a1'plyin-:: -".ce cr-'teri co;..-.;;on to penetrations in many different fl<<id systems. 6.2.4.1 Design L'c es Tne design bases go;crning the containment isolation system are discussed below. Thc contsinl-ent isolation valves are designated seismic Category I and de>> signed to AS[K Code, Sect on III and equality Group 8 requirements. tainmcnt isolation valves are designed to ensure leak-tightncss and Con-rc.liability of operat on. Containment isolation globe, check and gate valves meet the requirements of manufacturers sta:ldards MSS-SP-61>
"Hydrostatic Testing of Steel Valves" and containment isolation butterfly valves I,.iiAct the renuxxeme~,l.s of manufaa A tu.c.s standard s 'SS-SP-67 ~ "Bu1. t er f 1 y Valves".
c I 6.2.4.1.1 Conditions Requiring Containment Isolation Automatic initiation of a containment isolation actuation signal (CIAS) occurs when a high containment pressure of 5 pcig or, a high containment radiation level gf 10R/hr is detected. This provides diversity of parameters sensed for. the initiation of containment isolation. b) The CIAS closes fluid line penetration isolation valves not required for operation of the Engineered Safety Features. c) The containment isolation system is designed such that no single ac-. tive failure (in conjunction with loss of offsite power) could result in offsite doses or doses to operators in the control room in excess of 10CFR100 and GDC 19, respectively. d) The main steam and fcedwater valves close on MSIS and the valves for
~~'he component cooling water for the reactor coolant pump motors close on SIAS (see Section 7.3 and Subsection 6.2.4.3.2).~~
6.2.4.1.2 Criteria for Isolation of Fluid System Penetrating the Containment I a) The containmcnt isolation provis'ons for the fluid system pcnetrations (excluding the ESF systems) are designed in accordance with General Design Criteria 54; 55,.56 and, 57 (refer to Table 6.2-52). Excep-tions to GDC provisions are discussed in Subsection 6.2.4.3.
~~6. 2-52 1 goal 1'.~~
.?
SL2-FSAR I TABLE 6 2-51 SHIELD BUILDING VENTILATION SYSTEN INSTRUHENTATION APPLICATION Indirarinn Al ared Cna< rnl Cnnrrnl Cnntrnl Rnna hutnnctir Instrument S stem Parameter & Lnratinn Lnral R e II ~Rdr rdin Cnntrnl Funrt inn Rcnce hrrurcry
'nstrument hnaulus/atansphere pressure Hi -Ln Eaergices fan -ln tn +30 -1 tn -3 in. +1.0X diffcrenrial d<crhargc damper in,- ll20 H20 cRnrnr and repu-lares flnv rn preddct value and eaergi=e nutside rnnliag air valve 2~ Fuel pnnl area/atchsphere Hi -Ln Energizes Ean -10 rn +30 -1 tn -3 ia. +1.0X prcssure diEferential dicrhargc damper in. H20 H20 mnrnr and regu-lares flnv rn preset value and eacrgiae air valve nurside'nnling
, 3~ hir flnv remperct'ure dnvn 0 250 F 40-111 F +2.0 X streas nf demiater Inlet temperature Upstream
~~0-250 F 40 177 F +2.0X nf filter train~~
5. Demi st cr & Elertrir Hearers difEerential pressure 6d hir flnv temperature dnvn- 0 250 F 40-177 F +2.0X strccm nf 30 Kv hearing cnil 7 Prc-HEPA filter di Efereatial Hi 0-10 ia 1 tn 3 ia. +1.0X prcssure H20 H20

8. After-HEPA Ei lter different'ial 0-10 ia. 1 tn3 in +1.0X presddure H20 H20

9. hir Elnv cRniature dnvasrrcam Hi 0-100X 50-10X o2.0X nf HEPA filter 10 Chcrrncl cdsnrbcr differential 0-lO ia, 1 tn 1.15 in. +1.0X pressure indiratnr H20 H20 ll Charrnal cdRRnrbcr rwper~rure Hi 0-250 F 40-'I77 F +2.0X l2, hir flnv temperature dnvn>> 0-250 F 40-117 F +2 OX stream nE rharrnal adcnrbcra
~~Sl.2-FSAR TA51E 6.2-51 (Cnnt'd) Indic urinn Alarm Hnrma1~~
. CRRnrrnl CRRnr m) Cnnrrnl RncRa Autnmarir Inarrument Operating Inatru-ent S nrem paramerer 6 Lclrnrinn R ral R*, II**. ~aar* ala CcRnrrnl Fvnc r inn ~RR "E ~aa r ~arr ar hir flnv dnvnatruam ni fan Knergiaea idle 0-10,000. c fee 6000 cfa ~ ~
nr fan tn RRrarr hir flnM nf filter train at lcRv flnv and alarma Pilter train differential 0 15 in. 4 tn 8 ia. ~ . +1.0X presaure H20 H 0 Crnaa-rnnnec't flnu enntrnl valve pnairinn Outaide nnling air flnu c tnntrnl valve pnritinn Sbield building aurtinn valve pnaitinn Fuel handling building auctinn valve pnsitinn Purge di acharge valve pnaitinn
~
s
~~~ ~ "'20.56 ~~~
Position Ce8 of Regulatory Guide 1.45 states that "leakage detection systems should be equipped with provisions to readily permit testing for operability and calibration during plant operation". Discuss how each of the systems described in
.Subsections 5.2.5.1.1 thru 5.2.5.11 comply with the above position. ~Res esse As recommended by Position C.8'f Regulatory Guide '1.45, the three separate unidentified leakage detection methods utilized on St. Lucie - Unit 2 are (1) sump level and flow monitoring, (2) airborne particulate radioactivity monitoring, (3) airborne gaseous radioactivity monitoring.
The Containment Atmosphere Radiation Monitoring System wnich includes the airborne particulate and gaseous radioactivity measurements have radioactive check sources for the determination of the operability of each of the radiation channels during full power operation. Calibration can also be performed during power operation in the Reactor Auxiliary Building at 19.5 ft elevation. ('g The instrumentation for the third method of leak detection, sump level and flow monitoring, cannot be tested and calibrated during plant operation due to the location of the equipment (inside Containment Building) ~ However, a comparison with the readings of the other two methods described above provides the operator with sufficient information to determine channel inoperability or malfunction. / Tie ~i Gal+ kl/(X k ~ '~g dMPl fl//bs
'I,'/// /e/best bsd' eb'K <1+e Me~+sA~ ~<>
~~I p(~ <ef J'g n~ JtJL gg~ I b~~
~~,1 's'4 "(~~
420. 56-1
PRE-SERVICE INSPECTION Re: PSI Meeting between FPL and NRC 8/ll/81 Pursuant to tne above referenced meeting Flordia Power 5 Light has agreed to the following:
l. 'oA meeting between FPL and NRC to address Regulatory Guide 1.150 be held on, or before, 10/I/81,

2. A narrative description of what will be done for Reactor vessel inspection by 9/I/81,

3. A procedure, for information only, For Reactor vessel inspection by week of 11/I/81, 4.'he ul tra sonic xamination procedure will be changed by 8/15/81 to include the following:
"Examiners will record all crack-like indications regardless of amplitude" "P. 1 p ld 1 h P -7 1 ~di on the estimated number of welds to be inspected using Section ~P+
~~XI, 1977 edition, Summer 78 Agenda, ASME Code selected criteria for class 2 piping on or before 8/31/81,~~
~~6. To provide a summary of all welds at locations where tne stresses under the loadings resulting from normal.and upset plant condi-7.~~
~~tions Ph as 1 ~i~ calculated by the which exceed 0.8 (1.2Sh~~
~~-7 mented ISI requirements justify of sum + Sa) on SRP exceptions taken by FPL, of equations 711 9 and 10 or before 9/31/81, pl sections 3.6.1 and 1 1 in h~~
~~3.6.2 NC-3652 or 7-~~
8. To use, as guidance, the weld relief request procedures outlined in B and C of the attachment,

9. By 8/31/81 provide an estimate of PSI areas that may require relief requests,

10. Provide a copy of the Pre-Service Ins~ection ~Sosnmr to NRC's B.J. Crowley (Region I~I.
~r 121.13 The ASHE Code, Section Y!. 1977 Edition wi:h Addend~ through the Summer 1978 Addenda specifies use of Appendix III of Sect~on ):I for ferri .ic piping welds. If this:r ".Jirement is not applicable (for example, for austenitic piping welds), ultrasonic examination is required to be conducted in accordance with the 2 pl icable'equi rements of Article 5 of Section "., as amended by I~'A-22 2. Discuss your criteria for apolying Ar.icle 5 of'ection V, as amended by '.LA-2232. Provide a technical justifi-cation for any alterna ives used su h as Section XI, Appendix III, Supplement 7 for auszenitlc piping welds anc "icusss the following: All .. difications per.-;.itted'y Supplement 7.
b. Ye h""s of assu. in" adequate examination sensitivity'ver the required exar,'ination volume.

c. hethccs of qualifving the procedure for examination through the weld (if co.-.delete examination is to be considered for examinations conducted wi+l. only one sid access).
When us'-" ~poendix III of Section X'. for inservice examination of either fer.-.=ic :- aus=eni.ic oipine weld= -he following should be incorporated:
~~d. A. v -. = f:- r >I =" in "1 ca ior., " -~~
careen: o DAC or greater, discovered examination of oipine welles or adjacent base metal materials snou.- be recorde 'nd inves:ig -.ed by a Level II of Level III examiner xo t-..= extent necessary to ce-.-e..-..ine the shape, identify, and location o= t'< re.lector. Tne ';. should evaluat= .h take, correc.ive action for the dispo-I a ~ v ~ of any indication rv sti".ated and found to be other than geo-
~~.-..e=r'."al or metall ur"'cal in nature.~~
The PS: r" gra- .'oui d include the following information: A) For ASHE Code Class 1 and 2 co-.,ponents, provide a .able similar to IMB-2600 and IWC-2600 confinnino that either th~ entire Section XI preservice exa;..ination was perfor,.ed on tne cor.:""n n or relief is requested with a technica'1 justification suppor='."..c your conclusion. ~ B) Where relief is requested f". pressure retainin" welds in the reactor vessel, identify the speci ic welds that did not re eive a 100+ pre-service ultrasonic examira:-'cr. ar" estimate the >:=ant cf the examinatior. that was per;-"r.-.:ed.
. C) hhere relief is'requested for piping system weld=- (=xamination Cateoory B-~, C-F, and C-G), "rovide a list of th= specific welds that did not receive a complete Section XI- preservice xamination including a diawing or iscretric iden.i-.ication number, sy=-'.=;,'eld number, and phvsical con iguration, .g., pipe to nozzle;:eld, etc. Estimate the extent o-. the preserv'.ce =xa.-.,ina ion that wa:-."~rformed. When tho r
volumetric ex=-.,-.nation was ".erfor;-..ed from one si-= of the weld, discuss whe"her the en-.-'re welc v-'u-. and the he a:=e"=="'"n= (HfZi and base hietal or. -.'".e far side o-, the weld were exa....'.:ed. S:=-te the primary reason .hat a s=="ific exa-.ira.ion is i;..oractical, e.g., support or cc...p,"- nent restric-s ac=ess, . it ing prevents adequate ultrasonic coupling on one side, cc-...""n n to co-...".onent w id prevents v:-. =-sonic examination, etc. Indica'= ="..'l terna-.i;= or supp; -.,e".ital exa-..irations performed and methods(s: ." . abrica ion oxamination.
I On page 2 of your program description, regarding Class II examinations, you'have failed to include the requirement from Table IHC-2500-1 of the 77 Code, S-78 Addenda to- include in- the welds selected for examination "all welds at locations where the stresses under the loadings, resulting
~~" from normal and Upset plant conditions as. calculated by the sum of, E qs.~~
~~{1=-.2'pa)." 9 and 10 in NC-3652 exceed 0.8 Explain the above and submit a request for not followed. relief if all S-78 Addenda requirements are~~
2) Provide sample results of PSI UT. examination including results of inevestigating causes of'ltrasonic rejectives and repair results.

3) To complete our review, automated examinations.
it would be helpful to have your procedures In particular, submit your, plans, schedule, for and procedure for imp'lementing Regulatory Guide 1.150 for reactor vessel weld PSI. Discuss your plans for compliance with augmented ISI of Standard Review Plans 6.6, 3.6.1 and 3.6.2. In Paragraph 4.1.2 of your general NUT procedure you indicate a minimum .,(~j of on Level II in a crew of Level I's or Level I Trainee's. Your example examination results are signed both 'by a Level II and Level I. Since your procedures involved evaluation of indications as to geometric or non-geometric, it would be good practice to have at least one Level II directly performing or observing each examination. Please explain your actual practices.
~~5) In Exhibit 1 of your program description, you have a 30" to 12" utilizes a 12" calibration blocks. Provide justification for not joint'hich also using a 30" block.~~
~~FLORDIA POWER & LIGHT COMPANY'S POSITION ON FEEDWATER 1MSIER TESTING~~
~~1. St. Lucie 81 & 82 Feedwater piping is not only similar, it is essen-tially identical. Isometrics -~~
of both units were compared and the horizon-differences are measurable in fractions. For example, the tal sections of piping entering the stream generator, which are the sections 'of piping most likely to experience water hammer are all equal in length (2 feed), with on section on Unit f/1 being 3/8" shorter than on Unit //2. St. Lucie 1 performed feedwater hammer testing by draining the feed-ring for up to 2 hours and then manually initiating auxiliary feed-. water. This draining of the feedring is considered the worst case to transient and, since it has been performed on an identical unit, will not be repeated here.
~~2. Three (3) tests will verify that the Auxiliary Feedwater System will perform its design function.~~
~~a ~ Aux. Feed Pump Initial Run. This test is a recirculation from/ to the Condensate Storage Tank to initially run .in the equipment.~~
~~b. Auxiliary Feedwater Function and Endurance Test. This test will be performed prior to and during Hot Functional Testing to check out system operation, to verify the manufacturers endurance run.~~
~~C ~ Auxiliary Feedwater Automatic Initiation. C. 1. Ob ec j tive.'. To verify auxf eed au'to initiation~~
~~b. To verify the absence of water hammers to the feedwa ter piping during auto initiation.~~
~~C-2 Initial Conditions~~
~~'a ~ Reactor Coolant System at normal, no-load operating temperature and pressure.~~
~~b. Steam Generator Secondary Side at normal no-load operating temperature and pressure.~~
~~c ~ Maintaining Steam Generator levels with manual aux. feedwater control. C-3 Test Outline a~ Station an operator in containment to listen for any symptoms of water hammer.~~
~~b. Stop feeding Steam Generators cs Return Auxiliary Feedwater to a "Normal Standby" lineup.~~
~~C. 3 (con t. )~~
d. Allow Steam Generators to drain. When the Aux.,Feed-water Actuation Signal occurs, observe proper operations of Automatic Aux. Feedwater initiation (ie. pumps start, valves open, steam generator levels rise)-

e. Feed Steam Generators to desired levels Resume Manual Aux. Feed to Steam Generators Visually'examine piping external to the Steam Genera-tors for effects of water hammer.
The addition of the automatic activation feature ensures that the steam generators will not be subjected to a long period of steaming down, such as happened at TMI and was tested fox on St. Lucie //1. Xnstead, the system will activate at the actual time it would in the event of an accident. This is consistent with the test being pex-formed at the San Onofre 2 & 3 units after theix feeding modification.
~~3. Pi'ping vibration will be monitored during thevaxious phases of start-up. Xn accordance with the FPL approved vibration monitoring program.~~
4.. Because of the following reasons: a) The Piping arrangement for both units is almost identical, E b) Extensive Feedwatex Hammer testing was performed on St. Lucie fIl (5 separate tests at various steam-down internals up to 2 hours) and no resultant Feedwater Hammer, c) The St. Lucie I2 Pxeoperational Test Procedure will verify auto-matic injection, which will be the worst condition for Unit /I2, d) An operator will be stationed to specifically monitor for Feed-water Hammer:
,Floxdia Power 6 Light feels that oux present proposed program adequately demonstrates that St. Lucie //2 will.not encounter any Feedwater Hammer problems and hopes this satisfys the NRC Branch position.
Regarding questions raised by Walter Pasedag (Radiological Analysis Branch, Section Accident Evaluation Branch) on the hydrazine additive syst: em and TSP located inside con-tainment, the applicant, will revise the FSAR, as necessary, via amendment to,document the following: 1 - A minimum of,2 hours of hydrazine will be stored for continuous injection at a rate that will insure a minimum concentration of 50 ppm is available at the spray nozzles. 2 As long as doses are acceptable in the applicable por-tions of the Reactor Auxiliary Building, there is the capability to permit, the refilling the hydrazine, tank. 3 A quantity of TSP will be 10acated inside containment such that the water post accident will have a minimum pH of 7.0. P
~~4. The TSP basket design will be such that an inadvertant containment spray will not dissolve the TSP.~~
5 The TSP baskets will be located in the vicinity of the ECCS sump and designed such that a flow of water will dissolve the TSP within the baskets.
t 6. 5. 2 The Containment tinns of removing heat ment atmosphere. in Subsection 6.2.2. I Sprsy System (CSS) The and SL2-FSAR COH'fAINlEN'f SPRAY SYS'fEH/IODINE RE"lOVAL SYS'fl;H (CSS/IRS) is provided to perfnrm the drral frrnc-fission prodrrcts from a post-accident contain-heat rein> val capability of the CSS is di scussed The fission product removal frrnction ir. carried nrrt by the Iodine Removal System (IRS), nperating in conjunction with tire Con-tainment Spray System. The IRS remnves radio-indines from the cnntainrnent atmosphere fnllowing a loss-of-coolant accident by adding controlled amn'unts of hydrazine to containment spray water. 6.5.2.] ~Deci n BhCeh The design bases for the CSS/IRS as a fission product removal system are as fo1 l.ows: a) Tn provide capability fnr the fission product rcrubbing of the containment atmc sphere fol.lowing a DBA-LOCA such that nffsite dnses, and dnses to nperators in the cnntrol ronm, are within the guide-lines of 10CFR100 and GDC 19 respectively. The radioactive material release assumptions of Regulatory Guide 1.4 "Assumptions Used fnr Evaluating the Pntential Radiological Consequences of a Lnss of Cnnlant Accident for PMRS", 6/74 {R2) are used in determining system capability. The radioiodine and noble gas activity inventory in the cnntainment atmnsphere following a DBA-LOCA is given in Section 15.6. b) Tn maintain a minimum hyd razine cnncentratinn of 50-65 ppm at the cc;ntainment spray nnzz les based nn a storage cnncentration of . percent by weight in demi neralized water. 7 ~ To achieve a containment sump pit between 7.0 and 7.5 after all t e rpray chemical mixes with the available water inventory.
~~'irst d) Tn remove elemental and particulate indines with the fnl lowing mini-mum fi ~~) order remc val. cnefficients (in accordance with HUREG/~~
~~CR-009~~
/h
~ h h Iodine Form Order Removal Crefficient Elemental 10 hnurs -1 h h t Particulate ,'-~" "-' h
~~'~, ~ 0.45 hnurs "~~~
Tn meet iodine remnval requirements based on an effective spray coverage nf 85 percent of the containment free volume. 0 ~ h h h Tn perform its function following a LOCA> assuming a single active component failure coincident with lnss of nffsite power. 4. Be designed tn seismic Category I, Quality Group B standards as applicable. 6.5-6
e 0
Sl.2-FSAR To perform its function under the post accident environmental conditions specified in Section 3. 11. To provide system materials which are compatible with fluid che;ni st ry. The Containment Spray/Iodine Rem< val Systems are designed to Quality Group p'4 B and seismic Category I requirements in accordance with the recommendations of Regulatory Guide 1.26, "Quality Group Classifications and Standards for Water Stean and Radioactive Waste Containing Components of Nuclear Power Plants", 2/76 (R3) and Regulatory Guide 1.29, "Seismic Design Cl.assifi-cation", (R2), respectively. F, F
~~6. 5.2. 2.1 Design Description Both the CSS/IRS conrist of two independent and redundant loops. Each CSS loop is made up of a spray pump, shutdown cooling heat exchanger, piping,~~
~ F val.ves, headers, and nozzles. Connected to each CSS loop is an independent train of the Iodine Reraoval Systea consisting nf a constant volume metering pump, so Lennid-operated iso lation valve, IRS tank and associated piping and vaLves. The flow diagrams for the CSS and IRS appear as Figure 6.2-41. The design data for IRS components is shown in Table 6.5-2. Similar data for the CVSS is given in Table 6.2-38. The design of the IRS is based on the addition of hydrazine to the con-tainment spray water at a rate that ensures a minimum hydrazine concentra-tion of 50 ppm at the spray nozzlesa Based on the offsite dose limits as
,4 I r defined in 10CFR100, and a spray coverage of 85 percent oE the total 4 containment net free volume, hydrazine addition proceeds for a period of appraxiipstaty g'rpiautas.
A
~~/8<~~
constant vo n~ iydrazine addition pump is selected for system simpli-fication and ease of operation. Over the entire range of spray flow rates F the concentration of hydrazine ir no less than 50 ppra and no greater
~~.4 ~~~
than 65 ppm. Upon receipt of a containment spray actuation signal (CSAS) the .solenoid-operated isolation valves open and the hydrazine pumps start. Hydrazine i. xnj c ed into the suction side of each containment spray pump at a rate o - ' gallons per minute (gpra) until a low level switch in the 4 hydrazine st a e tank siraultaneously stops the pumps and closes the 4 C solenoid valves. The systen is designed to be fully autnraatic yet is capable nf Local-manual control. 4s Io.g its A< ~~/l v'I'~ 8 't4: p, 9<~e. 4~~
.On initiation ~ * ~ p 4 I ip p ' ~ r eW'~l' ~ Ly>sy '~ 6 k.
~~~~nf the CSAS, the containraent spray pumps trike suction from~~~~
~~~~~ ~~~~~
~~~~the refueling water tank (RMT) and spray borated water directly into the F containment atmosphere~~~~
~~~~\ I ~~~~~
A low leveL in the RWT is reached in approxiraately 20 minutes (see Subsection 6.2.2). A low level switch initiates the recirculation actuation signal (RAS) transEerring containment spray suction to the containment sump. Spray water in the sump is buffered with trisodium phosphate dodecahydrate (TSP)
~~~~6. 5-7~~~~
SJ.2" YSAR modes <<nd effects an<<Lysis has been rpade on there <<11 active components of the Ir dine Rernov<<l System to sin'w that as a minimum is <<v<<il<<ble one 100 percent hydrazine spray additive subsystem after any single active failure. For a failure modes and ef fects <<n<<lysis of the Contain!nent Spray Systen see 6.2-41 Theory of Iodine Removal by Containment Spray
'.5.2.3.1 The spray removal con~tant ~, Eor iodine is evaluated using the models described in NUREG/CR-009 ~ The model assumes a bal.ance between iodine entering and leaving the containment atmosphere with first order removal produced by the spray. The resu Lting equation, as given in NUREG/CR-009, for the remov<<L rate is:
A~ LEH V where' iodine removal rate~ hr spray flow rate, Et /hr ac absorption efficiency H equilibrium partition coefficient3 V net free volume of containment, ft The absorption efficiency, E, is evaluated by using the stagnant EiLm model. Further guidance on the determination of this parameter is given by Parsiy and has been followed in this evaluation. The parameters used in the calcu-lation are given in Table 6.5>>5. For elemental. iodine, a removal co-efficient of 37 hr has been calculated. However, in order to account for re-evolution of iodine, credit is taken for spray rernovaL until. the initial iodine concentration has been reduced by a factor of 100. Further, in the evaluation of the post-LOCA offsite doses, the asssumption is made that 50 percent of the initial airborne iodine instantaneously plates out. Consequentl y, the removal. rates for elemenfaL and particulate iodine used in the LOCA dose calculations are 10 hr and'0.45 hr, respective l.y. 6.5.2.3.2'pray and Sump Mater pH History The pH oE Liquid solutions that are recirculated within the containment foiiowing a design basis ~ccident is stabilized at approximately 7.0 to 7.5 The pH is maintained with the use of trisodium phosphate dodecah drste YtC.>IN = (TSP) which is stored in nine open baskets Located in th8contarnment ..ump. 0 "C Each barket is approximateLy three ft. by three ft. by one ft. The are constructed of stainless steel with mesh screen sides>and-ope~py Borate d water from the containment spray dissolves the TSP and thus raise the p Mixing is achieved as the solution is continuousLy recirculated from the sump to the spray nozzles. The spray water dissolves'the TSP within three hours following CSAS. Approximately one-third of the TSP dissolves during the injectic n made ~ For details of flow paths to the sump, see Subsection 6.2,2.
'An- ++P ID(ls 4+I) Jn.s!Qr>> ~ il br) s~c (>> ~I>>tl+ %w rrlaJyQe'ta)lt calztohl~~~<$ ~>>II aa't d>>ss~lve. 44l ~sp
~~~~6. 5-9~~~~
SL2"FSAR TABLE 6.5"2 IODINE REMOVAL SYSTEM COMPONENTS tlydrazine St~ora e Tank r' Volume, gallons "Mi'nimum: Liquid Volume, gallons 80 ~ h Design Temperature, F 8) . Design Pressure, psig 20 Operating Temperature, F 100 Operating Pressure, psig Fluid 7.% f 10 by weight hydrazine solution with nitrogen (N ) cover gas Matrrial 31%4 SS Code ASME XII, Code Class 2 B- H drazine Pum s Quantity 2 Type Positive Dis acgr ant, Metering Capacity, gpm 3s Discharge Pressure, psig 0 maximum Design Temperature, F 120 Operating Temperature, F 100 NPSHn, ft of water 30 Flu ict Material QX ly weight hydrazine solution 304 SS Code ASME III, Code Class 2 Rating 480V AC 0
~~~~~- ~ ~~~~~
Solenoid Valves r ~ re Quantity .2 Size, inche"s . 1/2 r Ty pe Globe rr Design Pressure, ps15 Design Temperature, F 120 s ~J ANSI Class 600 ~ rr wwd End Connection SW Pipe Schedule 80s Material 304 SS Su Fluid )Z y weight hydrazine solution
~
~~~~Operator 125V dc~~~~
solenoid Code ASME IXI0 Code Class 2

125V, DC 6.5-19 Amendment No. 0, (12/80)
SL2" l'SAR TABLE 6.5-3 CONTAIN!1ENT SPRAY AND SPRAY AOI)ITIVE I'LOP RATES The flov rates for the containment spray and spray additive flov rates are given for the following three cases: Case 1: Hinimum safeguard flow, minimum injection (i.e., one containment spray pump + one HPSI pump + one LPSI pump) with loss of offsite power and one die" el generator failure. Case 2: Maximum safeguard flov (i.e., two HPSI pump + two LPSI pumps) and single failure of one containment spray pump, (i.e., only one containment spray pump operating) with offsite power available. Case 3: Maximum safeguard flov, maximum injection (i.e., two containment spray pumps + two HPSI pumps + two LPSI pumps) vith offsite power i ava lab le. Total Total. Total> r Safeguard System Containment Spray Additive Hydrazine Addition Case ~Oeral.ion Rode S re ttlou ( m) ttlou (~m) Time(minutes) Injection 2800 3.58 0 0 2 Long Term Recirculation Recirculation Injection Long Term 3560 2800 3560 3.58 3.58 3.58 I 3 3 Inject ion 5600 7. 16 20 Long Term 7120 7 16 ggQ Recirculation
*Based on RAT at minimum Tech Spec level and runout flows for HPSI, LPSI and CS pumps. The containment spray flov of 2800 gpm includes a minimum recirculation flov of 150 gpm required during the injection phase.
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s 1 s 4 6,5-21 Amendment No, 3~ (6/81)
FLORIDA POMER 6 LICHT COMPANY ST LUCIE UNIT 2 DOCKET 50-389 ENVIRONMENTAL DATA FOR UNDER ROUND CABLE EXPOSED TO MET/DRY NNVINNrNNNTU I. ~Tee of Cables Us.d In Under round Ducts
~c(s l44 wo cable vendors supply cables for us> in underground ducts. They are the Okonite Company.and She Kerite Company~ ,Okonite supplies 5KV & .15KV power cabled Karite supplies 600V power, control and instruaeetation cable~ .('. R L.rs]: ~PP) s'~ C~~~d g CC.'&- ~
The 5KV and 15KV power cables are insulated with unfilled, cross linked polyethylene, wrapped with an extruded layer of semiconducCing insulation shield material compatible with the insulation, and covered with a lead sheath and a heavy duty overall neoprene jacket. The 600V power cables are'nsulated with a high temperature Kerite insulation (HTK) and covered with black heavy duty flame resistant (FR) jacket. The 600V control cables are insulated with Kerite flame resistant (FRII) insulation and covered with heavy flame resistant (FR) jackets.
'he 600V instrumentation cables consists of twisted pair'ed shielded and unshielded cables. 'Unshielded cables consist of twisted pairs with Kerite flame resistant (FRII) insulation covered with an extruded polymer layer and having an overall flame resistant (FR) jacket. Shielded cables in addition'o the above have a drain wire with each pair in direct contact with alumimum mylar tape. Each shielded pair is separated by glass mylar Cape.
Coaxial cables are constructed with a Rockbestos Firewall III Polymer LD first insulation, radiation cross linked cellular modified polyolefin or ( radiation cross linked modified polyolefin second insulation,'overed with a tin coated copper shield and a radiation cross linked, non corrosive, I flame retardant modified polyolefin overall jacket ~ These cables are rated for continuous service up to 110 C. I
XI. Test Data Vendor data (Kerite end>0konite regarding the environmental qualification of their cables exposed to a wet/dry environment are attached for your use. In addition to the above, a procedure was developed on St Lucie Unit- 1 to test certain underground cables to'onfirm their functionability. The fol'lowing is a brief synopsis of this Unit 1 procedure. At least -once per 18 months, during shutdown, by selecting on a rotating basis at least three (3) cables, one from switchgear to intake cooling water motor, one from switchgear to component cooling water motor and one from switchgear to diesel generator are tested with a 2500VDC megger. Control cables that are associated with each of the above motors and diesel generptors are tested with 1000VDC megger. The three spare cables are DC pro%<tested at 25,000 volts and measured for leakage current at 30 seconds intervals for 10 minutes. All readings must meet technical specification 4.8.1.1.3, If any installed spare cable fails the Hit Pot test, the NRC will be notified and corrective action take per technical specification 4.8.1.1.3. Attached are copies of actual test data taken at St Lucie Unit 1
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s a ~ (t Ifff 383 0 Peference Parag~ra h 2.3.3.2 Saoiples A through E ivere theiioally, aged in a circulating air oven for 168 hours at 150"C to simulate 40 year installed life at 75'C. III. gsference IEEE 383 ParaELraph 2.3.3.3 Samples A through E ifIere subsequently'subjected in air to gamma
~~~~~ I l~~~~
radiation from a cobalt-60 source at a rate of 0.5 x 10 rads per hour 8 to a cumulative dosage of 2 x 10 rads. IV. Reference IEEE 38~3para ~ra h 2.4 (Testing for Operation During Design Basss fvent In order to demonstrate serviceability of Fire>rail III coaxial constructions during and after a LOCA, the aged and irradiated samples I Mere subjected to the LOCA profile'for combined PWR/BWR as specified in IEEE 323, Fig. Al. Ouring'this entire profile the samples had a 600 volt rms voltage applied between the inner and outer conductors, the disconnected to provide for insula-
~~~~.'ion only exception being 'when leads viere resistance measurements. ' '..- ": .-:.'-';...*;~~~~
~~~~V. Reference IEEE 383 Para~ra h 2.3.3.4 After completion of LOCA Uie fo11oiving vvas accomplished: = ~~~~~
~~~~~ 1 g A h~~~~
~~~~l.. Insulation Resistance~~~~
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~~~~Was oieasured after the 'autoclave. Mls s opened and temperature returned to ambient..~~~~
~~~~~ .. 2. Samples were removed from autoclave and wrapped on a 40X mandrel (10 inch dia.).~~~~
~~~~a 3. While still wrapped o>> the BOX mandrel, a dielectric test Was~~~~
~~~~- performed Where a 60 cycle rois voltage gas applied betiveen the..inner ~~~~~~
~~~~and outer conductors of the co1xial constructions for one minute. The~~~~
'est voltage was 2000 vol ts for the solid dielectrics, the cellular di-electrics and the spliced sample (Saoiples A through E). ~ t ~ ~ \, ~ ~ ~
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4. The insulation resistairce was measured while tire samples were still wrapped on the mandrel.

5. The'entire mandrel with the cables still wrapped thereon'as then immersed in water and the voltage withstand test was again applied.

6. After the immersion and voltage tests of the preceding para-graph, samples "A" through "E" inclusive were'made into 40X coils and put into a 200'F 100>> relative humidity environment. Since this en'-
vironment was. not provided by the autoclave, the test voltage was not applied during tjris test period. After one year in the described environment, 4 all samples were subjected to an insulation resistance test and then immersed in water. A dielectric test was then performed where a 60 cycle rms vol tage was applied between the inner and outer conductors of the coaxial con-structions for one minute. The test voltage was 2000 volts for the solid dielectrics, the cellular dielectrics and the spliced sample (Samples A through E). All samples passed this test. Performance of the previously described tests, indicates that both the cellular and solid dielectric coaxial constructions will be service-able for their intended purpose both during and after a LOCA which
~~~~~ ~~~~~
~~~~may happen "any time during tire 40 year life of the, generating station.~~~~
~-
Reference lFEE Pa~ra ~ra h P..5 (Flame Tests)- Although passage of the vertical cable tray test of 1FEE 383 is /' not a requirement for coaxial,triaxial arid special instrumentation cable, Aockbestos, nevertheless, subjected tire ASS 6-102 cable to and successfully passed this test. Note: Rockbestos believes that most cables in its adverse service coaxial cable product line will pass this vertical cable tr~y test, but as of tlris date other. cables have not been subjected to this test.
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~g Pg. 4 Qg CFATIFIED CONCLUSION Firewall III coaxial constructions utilizing either solid or -cellular dielectric materials have successfully wi thstood the tests .and conditions in the preceding pages. Therefore, we certify that they will function for at least 40 years in their nodal intended applications. in a nuc1ear generating plant, including conditions of LOCA testing and 200 megarads .of cumulative radiation dosage occurring during the expected 40 year life of the plant.
~~~~~ Xilgv Geoyge S. Buettner Technical Oirector~~~~
~~~~':,', .Kenneth J. Gi ~z~~~~~
~~~~nnotti:~~~~
~~~~~~ .. ' ~~~~~
~~~~Test Engineer'~~~~
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~~~~s I STATE OF CONNECTICUT; COUNTY OF NEW HAVEN. Subscribed and sworn to before me this j~Q~ day of ~~~~1979.' .~~~~
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t'UC[EAP, ElfVl ROlill NTAL SCRVICE CYCLE REPORT (r;ESCR) Report Prepared for Ebasco Serv,ices Inc. l9 Rector St. t(e>v York, N. Y. l0006 Re: Florida Power 5 Light Co. Ebasco Spec 2ll-73 St. Lucie Plant Unit P2 Hutchingson Island, Fla. - . q r 1
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~~~~1 Report Prepared ~b :~~~~
~~~~"-.': 4-::"":"=::.:-:-'":-." ~-':~ .::.'."~-..,"- ..";;r~~;",;: The Aockbestos Co. "., " '~~~~
~~~~New lfzven, Ct. 06504 V~~~~
~~~~Hay l5, 1980 Rev. III~~~~
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~ ~ ae ' e Accc 1ur s tea Mater Absorpt ion Tes t ( lnsul Ref: Para. G. Rockbcstos I. l.d has performed it ion) long (erm vlater absorption testing on RSS 6-102 core which uses a solid, cross-linked polyolcfin dielectric. Mater Teuperature 90'C Continuous Energized Vol tape - 600 VAC 60 Hz Durati'on of Test - 26 weeks Results - Reported in Appendix "D" Accelerated Mater Absorption Test (Jacket) Ref: Para. 6.l.l.e Tests were conducted on the jacket materials used on the Rockbestos coaxial constructions according to ICOSA S-19-81 Para. 6.9.3. The re-
~~~~- suits were Os58 milligrams per square inch quired 20.0 mil igram requirement.~~~~
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~~~~and are well within the re-Hoisture Resistance~~~~
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~~~~t I ~ ~ Ref: Para. 6.l.l.f n The Rockbestos Company has performed accelerated moisture resistance i~~~~
~ s tests .for continuously wet and alternately wet and dry conditions with .'r s /, 's good results on its Firewall 1.11 instrument cables. These tests normally I
la~ r s utilize air ovens and a steain autoclave. Since it is necessary to "pot" r the penetration of the autoclave, it'is not feasible to use this method of testing for coaxial constructions., 's ~ lt should bc noted herc that s the'. Firewal 1 ll 1 instrunlentation cables tested'utilize flame retarded cross" 1inl'ed. polyolefin compound, as do thc jackets of our coaxial constructions.
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0 7. r~ ~ ~ unit. Qi Coaxial cable functions as an integral The jacket is used to keep the nioistuie frown tlie inteiior of the cable. While long term moisture tests on core insulation will serve to show the cable will maintain voltage and IR characteristics, it must be renieinbered that coaxial cables are designed to be basically dry. Therefore, the outer jacket is very iniportant. To prove the jacket integrity .over and above the requirements of ref. para. 6.1.l.b and 6.1.1.e Rockbestos put a sample of jacketed cable in 75"C water and measured IR from inner conductor to first shield. After six inonths the sample shows an insulation resistance of 720 gigohms for 20 ft. 'he sample tested was Rockbestos RSS 6-208C with the outer jacket and aluininum sheath removed. The moisture resistance of the construction, including wet and dry, is further demonstrated by the air oven aging, autoclave spray conditions and humidity environment, as docuinented in the qualification report (Appendix 8). Also attached as Appendix "F" is data previously reported by Rockbestos on its Firewall II I cross-linked polyolefin as fur ther support i no data. ' I Electrical Characteristics .'. .:".',: ":: f
~~~~'" ~ " ~~~~~
~~~~'~it ' I'L Ref: Para. 6.l.l.g~~~~
~~~~~ '4 Ttie electrical cfiaracteristics shown on our RSS drawings for ~ ~ I ~ ~~~~~
cables to be supplied on this order were derived using test methods of MIL-C-170. it js a Since that time tlIL-C-17E has been issued; and while more 5 ~ ~ ~ ~,' ~ complex and in many cases unworkable, testing is still accomplished' according to HJL-C-170. E, J *= Since the cables. used for nuclear generating stations are .60 IQz
~~~~~ ~~~~~
or less, testing to either the "0" or "f" revision should not con-stitute any Iirob1enis.
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~~~~CJ""BT(O V "IB}'". 8c Ch.'E$ T..E CO. ROCKBI':S I'OS'ltOI)UC'I'S n rvIs I Ir rr <I r Cl.'.ILBO COIII'OIIATION 0ll0 cnosSI'ICS r*AK CAIVE SVI1E ?22~~~~
'ABATIS ?roncnoss. econ w 900? I ~ I404) 449 I96II I800I ?< I CA5 October 14, 1975 ioASCO Services, inc.
~~~~21 Mcst Street Room 1310 thew York, tlY 10006 Attn: Ir. Dennis Cronin-clo Phil gobi le RECEDED E Rq: Firewall ill - FloridaPower~~~~
~~~~--<-..ST-,-LuC1C-2 --:-6 Light ' ~~~~~
~~~~Qt;T 2-':CTS inquiry FLO-211I8 .Cerro Proposal 20-3113 inquiry FLO-2lII9 Cerro Proposal 20-3II4~~~~
~~~~~ ~~~~~
~~~~r 4 Gentlemen, ~ Further to our letters of August 18, 1975 and September 26, 1975, wc are Furnishing~~~~
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~~~~additional information on the tests we have performed and noting changes in our~~~~
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~~~~original~~~~
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~~~~proposed program. The purpose of the test was to measure the effects of different environments on the~~~~
':Firewall Ill cable offered in our proposal." llighly accelerated test procedures were used to obtain meaningful'esults ln a reasonably short period of time. ~
~~~~l' Samples were subjected to the following: ' r. Sample l. - Continuously Dry: Sample was 'placed ln an air oven 1~~~~
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for 360 hours and measured at regular intervals for changes'n IA,'SlC, and Po~er Factor., Sample 2. - Continuously Met.: Sample was placed in a stcam autoclave at'II2 and
~~~~'l C~~~~
40 PSIG. The test on thi's sample was terminated after, 260 hours becau=e o'lectricai failure, Thc same electrical measurements werc performed. Sample 3 lernatcly Met 6 Dr y Sample was placed 'in a steaIA au'toe lave at 1 I2 C and ~IO PSIG for 16 hours, 1 hour at room temperature, 6 hours in an air oven at 121 C, 1 hour at room temperature and then'the cycle repeated. Thc test was continued for 360 hours with the same measurements being made at regular intervals. The results of these tests are sho'wn on the attached chart. Samples.l 0 3 were electrically sound after completion oF the test program.
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(I Jp$ ' vv l J V CE~ lJPJ CV 0 I V 5 0 < H 0 f CEBRO COBPOBA'I ION CGHzlHlll~~ A Lilt(4 iQ EBASCO Services ~ l nc, oAl cn Oc tobe r 14 ~ 1975 rAoc, 2 C Upon conpletion of the program, an additional test was performed on sample 0'3, to de;erinine if, any change v~ould occur on the sample if it were placed in a continuously dry environment. The sample was placed in an oven at 121 C for 115 hours and the resul ts are as Fol lows: lR 45000 Megohms Sic H3 3 Power Factor .80 You will note, this accelerated drying cycle'caused the sample to return to its approximate origina) value. Fran this test program, i t can be concluded that a continuously wet environment is the most severe, the alternately wet and dry is the next most severe and the
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~~~~continuously 'dry'is thc least s'evere. This supports years of actual experience~~~~
~~~~~ ~~~~~
~~~~on many types oF insulation used in actual field installations.~~~~
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~~~~t should be remembered, that each of the tests described;'ar exceed condi tions~~~~
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1 which would be experienced in normal operation and were conducted specifically to measure differences in severity, of environmental exposurers.. ln 'our letter oF 9/2ol/5, we furnished test results on our Firewall ill cables that have been immersed in water at both 75o C and 90 C For, long periods of time. A comparison can be easi'ly drawn to the perfonnance of. Butyl and other earlier vintage insulations that have demonstrated an ability to perform for forty (40) years In actual service. These test results clearly show, the. vastly superior
. performance of Firewall ill, permitting a conclusion to be reached, that the end life of this insulation should far surpass experiences obtained on cables that 'have had"actual 40 year service life.
~~~~Rockbestos Products~~~~
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npv~ reft '" rv44%a v4~~VNv vnvr, '. ',:. )r ..- " . '7 ') ': ')a ")'l) I) 4'vt' ") I. ~ t. <<i' SL2-FSAR Emergency Core'ooling Sy" tern piping I e) control rod drive mechanisms fuel assemblies and spacer-grids reactor internals reactor cavity shield valls secondary shield valls I 1.9.4 . LOW TEMPERATURE OVERPRESSURE PROTECTION (LTOP) Low temperature overpressure protection will be b rovided via the installa-tion of power-operate d x'e e 'va li f'ves p ve {PORVs) qualified for both saturated steam and liquid li soci~ted The d re e f serv rvice. ce. PORVs will sized to be accommo d atee the pressure t transient assoc . a e with a Controlled Rod Withdraws wa1 d 1 { t t1 low pressure setpoint) to mitigate the pressure transient resulting from either a spurious initiation of safety inng ection, 1 t rt with an excessive temperature difference between the RCS and the steam gener'atox'. The fi'nal design s is descr described e in Subsection 5.2-6. Corresponding transients analyses will be provided in Section 15.8 early in 1981. 1.9.5 1HDROLOGICAL DATA As discussed i in Section .. ec ion 2.4. aadditional information for Putchinsen Xsland being evaluated on the separate sub)ects of urt er e a 0 possible potable well locations. An amendment to Sectkoon 2 4 will be 1 e d ~ fi on or about March 1981 incorporating the relevant information. 1.9.6 UNDERGROUND CABLE REVIEW Kerite insu 1 a ted e poser powe and control cables have b'een revieved al))~approved b tle by the NRC for underground vet/dry environmental qualificat on jp xovv4)nwl)o aaderdroand tneer44en a 4)v amandmen n-ot~bov" Feb".ca~98& .~ Atlc~5%8~$ ~ 3,tl. 4, 1.9.7 ENVIRONMENTAL AND SEXSHIC QUALXFICATION 0 CLASS lE EQUIPMENT 0
-1978 the NRC issued a letter (10) requesting additional i o al information on Class lE equipment qualification. Sections ns 3.10 and 3.11 have been organized to provide the requeste<< d information fo on seismic and environmenta qualification test results. 11ovever, at the date of tendering t ie ualification test summax'ies and reports of results are still s
~~~~to Sections 3.10 and 3.11 vill~~~~
~~~~'eceived.~~~~
being, genex'ated and have not yet been rece ve ~ Therefore, be filed periodically in order to provi e e amendments the necessary information and also to provide resu s oof relevant e analyses 'ults when available ~ Per a memorandum and order issued on May 23 23,'91980,, the NRC has 0 ordered applicants for operating licenses to mmb.et f
~
t the re q uirements of 1
SL2-FSAR integrated radiation exposure combining 40 years normal. operation and the required 'term of funct ionality during the post design basis accident (DBA) period (up to 1 year). Tables 3.11-1 present the design parameters for radiation for each specified environmental condition ~ The normal operations exposure dose for equipment is either derived more explicity fran the design source terms presented in Chapter ll taking account of equipment arrangement and shielding configuration, nr based on the maximum dose rate anticipated for the radiation zone in which the equipment is generally located. See Section 12.3 and the zonal dose maps on Figures 12.3% through 12.3-12. For equipment in lower radiat ion zones (I & IE) the cumulative 40 year exposur e is conservatively taken as 10 Rads. For Zona V equipment with a few exceptions, (the CVCS ion exchanger, spent resin tank, spent fuel transfer tube and volume cc ntrol tank) ~ the dose rate is 100 R/hr.'or tl>e aforementioned except iona, the design dose 'rate is higher than 100 R/hr.
~
The DBA exposure dose affecting ESF systems and associated safety related cenponents is dependent on equipment location. The DBA considered for the containment, Reactor Auxi li ary, Turbine, and Diesel Generator ouilaings is the p~~)ulation of a LOCA in accordance with the recommendations nf TID-3 14B44 and Regulatory Guide 1.4, "Assumptions Used for Evaluating the Potential Radiological, Consequences of a Loss of Coolant Accident for Pressurized Pater Reactors", June 1974 (R2). The DBA affecting equipment in the Fuel Handling Building is based on the postulation of a fuel Iiandling acciden'to The few organic, materials that exi st within the containment are discussed in Subsection 6,1.2. The radjatinn exposure dose rates given in Table 3.11"1 i s based on gamma radiation exposure. Et is recognized that the beta energy release from noble gases is as much as 2.5 tip'~ greater than the gamma energy release within 30 days post accident. However a representative cable geometry inside containment has protective cover sheathing the insulation layer and an overall cover of fire protective Flamemastic or equivalent., Therefore the integrated beta radiation dose for a one year post accident period is less than 10 percent of the integrated gamma radiation dose over the same period. This comparison includes the conservative assumption of conpari ng effective 2. 2 Nev be tas wi th e f feet' ve 2, 2 ~fev gammas and assumes a spherical cloud, radius 40 ft, of airborne nuclides. Other cnnponents inside containment are considered sufficiently shielded from beta rad iation since it is effectively attenuated by only a few mills thickness of metal. Therefore based on the aforementioned discussion beta radiation i s not considered an environmental quali ficatinn problem. 3.11.6 SUBMERGED CABLES ~~/ pc>fog Q~ P~
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~~~~related cables located outdoors that coul be submerged in water~~~~
~~~~'afety are qualified for operability under submerged c nditions.. P~: ~ <~v;r~~~~~
~~~~j <'0: 0i~ P ok;4.C p~y)~ Ke >'4.C p~y m(4. ~<~4+~ ~4~r.~4 w~t<~t~ 'k~s i~~ '<</~"~+ ~~~~~~~
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~ << 'r SI 2-FSAR SECTION F 11: N FERENCES (1 ) D 6 Vassalo,(HRC) letter to Dr ., R E Uhrig (FPL), "Environmental and Seismic (/uali fication nf Class IE Equipment" dated July- 28, 1978.
(2) Dry R E Uhrrig (FPL) letter L-78-334 to D B Vassalo (NRC) dated October 16, 1978. (3) J J Di Nunnn,"P D Anderson, R E Baker and R L K~terfield, "Calculation of Distance Factors for Power and Test Reactor
~~~~'Sites," TED-14844, USAEC, March 23, 1962.~~~~
I (4) 1976 ANS Paper: "In-containment Radiation Environments following the Nypothet ical. LOCA (LMR)." Cr) y, Kr- v4j(>->'<<3 >W<<>. <-'5-3Vg 4 DF'<<<<'~<~Ct>d~) ~W 8-~~+i/,m f . (d) p gg d; 0 t>>)-l<<A 4-Rt- 6 '0 b >~I'A gk>>-c.) 4+M
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II . F 11-6 P
FLORIDA POWER AND LIGHT COMPANY ST LUCIE UNIT NO. 1 DESIGN CRITERIA RE-EVALUATION OF CONCRETE MASONRY WALLS
~~~~&re ared B Reviewed B A roved B Date Original R1 <2/ 7/8G~~~~
~~TABLE OF CONTENTS Item ~Pa e INTRODUCTION 1.0'.0 APPLICABLE CODE 3.0 MATERIAL$ - 4.0 LOADS AND LOAD COMBINATIONS 5.0 ANALYSIS AND DESIGN 5, 1" GENERAL~~
5. 2 DYNAMIC ANALYSIS 5.3 STATIC ANALYSIS 15 6.0 ALLOWABLE STRESSES l7'7 7.0 ANALYTICAL PROCEDURE F 1 UNREINFORCED WALLS-RE EVALUATED BY COMPUTER 17 7.2 REINFORCED WALLS-RE-EVALUATED BY C(NPUTER 23 No. Tables IOAD COMBINATION TABLE FOR CATEGORY I MASONRY WALL 6 ALLOWABLE STRESS IN UNREINFORCED MASONRY ALLOWABLE STRESS IN REINFORCED MASONRY MASONRY WALLS SECTION PROPERTIES 19
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0 IFI'RODUCTION The design criteria contained herein is applicable to safety-related con-crete masonry walls as well as non-safety related concrete masonry walls whose failure could adversely affect the safety related systems and com-ponents in their proximity in a Nuclear Power Plant facility and establishes the design requirements for evaluation of the structural adeauacy of existing concrete masonry walls. The scope of this criteria covers all masonry walls in proximity to or having attachments from safety-related piping or equipment I such that wall failure could affect a safety-related system. Safety related equipment or subsystems to be considered as attach-ments or in proximity to the walls shall include, but are not limited to, pumps, valves, motors, heat exchangers, cable trays, cable/conduit, HVAC ductwork, electrical cabinets, instruments and controls. 2eo APPLICABLE CODES AND GUIDELINES 2.1 The following codes shall be used for the re-evaluation of masonry walls, subject to clarifications contained in the criteria. Code Title ACI 531-79 American Concrete Institute "Building Code Requirements for Concrete masonry Structures" AISC American Institute of Steel Construction "Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings" ACI 318-77 American Concrete Institute "Building Code Requirements for Reinforced Concrete"
2.'2 Guidelines Recommended Guidelines for the Reassessment of Safety Related Concrete Masonry Walls, Prepared by Owners and Engineering Firms Informal Group on Concrete Masonry Walls, October 6, 1980.
~~~~'l 3 ' MATERIALS The materials which have bein specified in the project specifications and drawings shall be used.~~~~
4,0 LOADS AND LOAD COMBINATIONS 4.1 Loads Descri Cion The loads are grouped into the following categories: (a) normal loads (b) severe environmental loads (c) extreme environmental loads (d) abnormal loads The detailed description of these loads is as follows: (a) Normal loads Normal loads are those loads that are in effect during normal plant operation and shutdown conditions. For the walls, they include the following: (1) Dead Load (D) Dead load includes the weight of the wall, and any structures or equipment supported by the wall. (2) Live Load (L) Live loads include all temporary loadings that act on the wall, both in the plane and out of the plane of the wali'
s A s r 4.1 Loads (Cont 'd) {3) Thermal Load (T0 ) These are thermal effects loadings on the wall during
'- - norma) operating or shutdown conditions, and shall be b ased on .the most critical transient or steady state .. condition.
~~~~(4) . Pipe Reaction Load (R )~~~~
, Tjiis,is. the . 'eaction of pipes supported by the ~ -'~-'wall during informal mperating or shutdown condition, ,~v,-='a'n8 shall'-beibased=:on th'e'most critical transient --':sg--,',or'f6ady etate tco'ndit'ice;<i ... {b) .%ever'e Environmental 'Loads ',~ .;-'. \
~~~~Qev'ere environmental 1oads .axe those loads that could infre-~~~~
~~~~- guen'eely-Se-"encos4ntered durin~ tlie plant s~~~~
~~~~life. Included in r f~~~~
==-. -41);;-fr~ind &ad: .{8) ---:.: '. g:-;..~= ,:.-'-'~"-'... Tlirt "hs Ite~~gsfjjn:Qesgs.:"shod jpejifiedfor ,the.'-site of ~;;.":= ';~,the..plant= =-:-.Xt is-applicable only'to 'those walls for 2=.: ",.~"; .R~".~;;.+-.." ~ +.~wh ich ~gFdes3. oql:-"iN,'spec i'f iepp': ~~-'~~';.'-:. ~= ' -': ..- ":(2) <<.Sei smxc 'Load',-'P-."".=):..'.~~"-.'.. ' *'"-", ..-",.Q= ;::"';=.~(if-For".,jiasonr'yf wal 1 s ga g'uilhings fox which 'dynamic .'. -: = ', ~ -'"":=",'~-".;";4n'alvsess.are performe8:-':" '.'--: --.,-:Tt'i's's th'e"load g'ednegated by the operating .basis ='~.'- -: ~',~~'-..=-:,~: ';:=.;:,~;;jYrthqiiqke'COBB).'s'pe'cfXi'ed,;fear tfie site .of the'lant, .".-:-~-~x '4'>> ".~p~s::;-s"" =.-"'.-'and'ge'velopEZ:.for.':t4'0>'~ill. ~Is -th) dynamics"-'Analyses .'. -"..',-'"-".-.'..-,-,,~.-'m .-',,'-'-- pe tformq'd 'or'-%lie:bgi4cf5 ng.;;-.-'Zn-pl aiie . and'ut>>o f-plane =:--"::r. K;=,':.':,g~".,;:.;..'~:6:..">.>>=4-',.'=-,::..=..ljadfngs '".-'and .4>4.ef Cdirt's of: I)terai:.Bisplacements of jj'a.gl"ends rerla7'iye "t'o-'each "oth~ areWonsideied.
~~~~v, . ~~,tr ', mw e ~~~~~
~~~~~ s, , i, ~,'d,s~ ~ .~ ..~~~~
Loads Doso~ri tion (Cont'd). (ii) For masonry walls in buildings for which earthquake loadings are developed from empirical equations: Unless noted otherwise, this is the load due to earthquake calculated to act on the wall according to the provisions of the applicable building code or standard, (c) Extreme Environmental Loads Estreme environmental loads are those loads which are credible but highly improbable. They include: (1) Seismic Load (F ) eqs For seismic Category 1 buildings, and those non-seismic Category 1 buildings for which the load is specified, this is the load generated by the safe shutdown earthquake (SSE) specified for the site of the plant, and developed as described for seismic load (F ego )
~
(2) Tornado Load (W ) If a tornado event, or similar high-intensity wind pheno-menon is specified for the site'f the plant, this is the load generated by the event., It includes loads due to wind pressure, barometric pressure drops between the exterior and interior sides of the wall, and impact loadings due to wind generated missiles. These loads are applicable only to those walls for which this load is specified. (RL
Abnormal Loads I Abnormal loads are loads such as those generated by the failure of high energy piping, or equipment failure which generates missiles. This category of loads includes the following: (1) Pressure Load (P ) This is the pressure equivalent static load within the masonr'y wall compartment caused by failure of high energy piping or equipment. The load includes an appropriate dynamic load factor determined by analysis, or based on empirical data. IRi (2) Thermal Load (T ) This is the thermal load under thermal conditions generated by the abnormal event, and includes T effects. 0 -(3) Reaction Force (R ) a This is the pipe reaction under thermal conditions generated by the postulated pipe break, and includes R 0 effects. The load shall take into account any change to R due to redistribution of pipe reactions caused by discontinuities in the pipe due to the break. (4) Pipe Load (Y ) This is the equivalent static load on the wall generated by the reaction of the escaping fluid on the broken high-energy pipe during the postulated pipe break, and includes an appropriate dynamic load factor to account for the dynamic nature of the load. (5) Jet Impingement (Y ) This is t'e )et impingement equivalent static load on the wall generated by the postulated pipe break, and includes an appropriate dynamic load factor to account for the dynamic nature of the load.
0 (d) Abnoarul Loads (Cont'd) (6) Missile Load (Y ) This load is the missile impact equivalent static load on the wall generated by equipmcnt or pipe failure, and includes an appropriate dynamic load factor to account for the dynamic nature of the load, 4.2 Load Combinations Seismic Category I or other affected masonry walls shall be re-evaluated for the loads as given in Table 1. TABLE 1 LOAD COMBINATION TABLE FOR CATEGORY I CONCRETE MASONRY WALL YrB Value Feqs Y]t T for Allowable Load Category D L T R W P a W t Feqo R a Ym a Stresses (Note 1 0 Q Normal X X X X Severe Environmental (1) X X X X X Severe Environmental (2) X X X X X Extreme Environmental (1) X X X X X 'U Extreme Environ" mental (2) X X X X Abnormal X X X X U Abnormal/Severe Environmental U Abnormal/Extreme Environmental X X X X X X U Note 1 Values for S and U are specified in Table 2 and 3 for unreinforced and reinforced masonry, respectively..
Table 2; Allowable Stresses in Unreinforced tlasonry Al 1 owabl e Y1axinum Al 1 owa bl e t'oaximum Description (psi) (p>> ) (psi) (ps'i) Compressive A ial(1) '4"m Flexural 0.22f'.33f'.25f'. 1200 ""m 3000 Bearing On full area 900 0. 62f 2250 On one-third area or less 375f 1200 3000 95f'~7m Shear '.1 Flexural members Jf 50 75 Shear walls Tension 1 0.9P'.6 34 1.35
~~~~/f'000 51 Normal to bed joints Hollow units 2.6P,'000 Jm, 25 0.83 m 62.~~~~
Solid or grouted 1.0 Jm 40 1. 67P 67 Parallel to bed joints (4) Hollow units 1. 0Jm 50 1. 67/m 84 Solid or grouted 1 . 6/m 80 2.6 Jm, 134 Grout Core 4.2 Collar joints Shear 12 Tension 12
0 40tes to Table 2: (l) These values should be multiplied by (l -'4>h 3
~~~~) ) if the wa.l ras a significant vertical load.~~~~
(2) Use net beooec area with these stresses. (3) For stacked bond -construction use tw. -thirds of the values specifieC. (4) For stacked bond construction use two-thirds of the values sp ci=ie"'or tension nonral to the beC joints in the head joints of. stacked bond construction.
Table 3: Allowable Stresses in Peinforced Masonry Al 1 owa bl e t1ax imum Al 1 owa bl e Ma x imum Description (psi) (psi) (psi) (psi) Compressive Axial 0. 0.44f
~~~~'000 22f'.~~~~
~~~~Fl exura 1 33f 1200~~~~
~~~~'.85f 2400 Bearing '.~~~~
95f'000 On full area 25f 900 '.62f'. 1800 On one-third area 375f 1200 2400 or less Shear Flexural Shear members Halls( ~ ) 1.1 Jf' 50 1 7 f'5 Masonry Takes Shear M/Vd+1 9J'm '6 M/Yd ~ 0 2O Jfm 74 123 Reinforcement Takes Shear M/Vd)> 1 75 125 M/Vd O 120 180 Reinforcement Bond Plain Bars 60 80
~
~~~~Deformed Bars 140 186 Tension~~~~
~ 6 Grade 40 20,000 0-9F y 'Grade 60 24,000 0. 9F Joint Mire .5F ,30,000 0. 9F Compression 0. 4F 0. 9F
~~~~ot to Table 3: s (1) These values should be riultiplied by (1~~~~
~~~~- ( ) ) i'he wall has a sign', icarit vertical load.~~~~
(2) This s ress should be evaluated using the e'fective area shown ir, figure below except as noted in Par. 7.2.1 (a). 6l Oi w'so r Spacing f f whichever il lr'SS l pr tvnnrnlf bonrf I ~v/r~yrr:r r~': r'.
~
~~~~ri. rr~Arrrlr'i~~~~
~ ~ ~ ~ ~ ~ ~ a ~ ~ ~ ~
Ares assvmesf effecsive in flea vral compression, force normal lo face (3) Net bedded area shall be used with these stresses For Yi/Vd values between 0 and 1 interpolate between the values (4) oiven for 0 and l. 0 ANAI.YSIS AN) DESIGN, General 5.1.1 Concrete masonry walls shall be re-evaluated according to working stress design principles. 5.1.2 The Response Spectrum Method shall be used for establishment of seismic effects on masonry Ib"""" wali'.2 5.2.1 Fre uenc Anal sis - Section Crackin Consideration Frequency analysis shall be performed using either computer or hand calculation in order to determine the out-of-plane frequencies of masonry walls. The uncracked behavior and capacities o'f the walls shall be considered for unreinforced J walls. For reinforced walls, both cracked and uncracked be-havior and capacities of the walls shall be considered. 5.2.2 Uncracked Section For the uncracked section of the unreinforced masonry wall, the equivalent moment of inertia shall be obtained from a transformed section consisting of the block, mortar, cell grout and where present, core concrete. For the uncracked reinforced wall, the reinforcement area shall also be trans-formed in calculating the moment of inertia.
5.2.3.
~~~~~ ~ Cracked Section Xf the applied moment (Ma) exceeds the uncracked moment capacity (Hcr), the wall shall be considered to be cracked.~~~~
The equivalent moment of inertia (Ie) of the reinforced cracked walls shall be computed as follows: where, I Mcr Uncracked moment capacity = Mcr = fr ( ), Ma ~ Applied maximum moment on the wall It ~ Moment of inertia of the transformed section as described in Par. 5.2.2. Icr Moment of inertia of the cracked section Modulus of rupture Tensile stress defined in Table 2 for mortar or grout if the masonry Joint is assumed to be cracked. Distance of neutral plane from tension face 5.2.4 Method of Fre uenc Anal sis For the masonry wall, which is subJect to seismic load only and has no large openings, the standard expressions for single degree of freedom systems can be used for computing the natural frequency of the wall. For other types of walls subJected to different types of loads, a finite element model shall be used. One-way behavior can be assumed if the aspect ratio, h/1 (height to length) is less than 0.5; otherwise two-way behavior should be assumed for the wall with four-side support.
~~~~5. 2 ~ 5 Damp~in The critical damping values to be used shall be as fo11ows:~~~~
~~A. For reinforced and unreinforced uncracked walls use 2% for OBE and SSE. B. For reinforced cracked walls use 4% for OBE, 7% for SSE. 5,2.6 Bounda Conditions~~
,Boundary conditions for concrete masonry walls shall be selected with regard to the relative stiffness of the masonry walls to their \
suppo'rts and also to the structural details which provide the inter-face between the wall and supports. The guidelines for the selection and qualification of boundary conditions are: A, Si le Su ort - A simple support condition may be assumed at the top or sides of a masonry wall if shear transfer across the joint can be demonstrated under all loading condi.tions; however,no moment transfer is expected. The shear transfer may be accomplished by either mechanical methods (embedments, dowels, masonry ties, support angles, etc.), or by wedging action of the masonry wall with its supports. A plain mortar joint on the bottom support (bed joint) may provide the necessary shear transfer if the shear friction concept can be justified as follows: V ~ NQ where: V ~ shear resistance of mortar joint N ~ force normal to the bed joint (net downward load)
~~~~~ ~~~~~
u ~, coefficient of friction, 1.0 for concrete, 0.8 for mortar Rl placed against hardened concrete, and 0.7 for con-crete against structural steel. A plain vertical mortar joint at sides of the wall is not quali-, fied as a simple support. 0 B. Fixed~Su port -I Fixed support conditions may be assumed pro-vided the )oint can transfer the flexural stresses to the support. 5.2.7 Poisson's Ratio Poisson's ratio equal to 0.2 is appropriate for both reinforced and non-reinforced concrete masonry 5~2~8 . walls'eismic acceleration shall be selected from either the floor response \ spectrum at the bottom of the wall, or the floor response spectrum at the higher elevation, whichever yields the maximum response with the frequency determined in Par. 5.2.4. 5.2.9 Modal Partici ation For hand calculation, seismic acceleration should be, increased by a factor equal to 1.05 to account for the participation of higher modes for out-of-plane flexural calculations. When the lowest fundamental frequency determined in Par. 5.2.4 is greater than 33 hertz, the factor is unity. 5,2.10 Interstorv Drift Effects In-plane or out-of-plane interstory displacements shall be obtained from the original building structure dynamic analysis. The maximum diiferential displacement due to out-of-plane drift shall be applied at the top support of the wall in static analysis.
'\
Sta~tic Anal sis and Serosa Evaluation 5.3.1 Stress Combination Stresses due to in-plane loads and out-of-plane loads shall be combined using the square root of the sum of the squares method (SRSS). 5.3.2 Multi- the Walls Individu'al wythes of a multiple wythe wall shall be, assumed to act independently under the action of seismic loads unless bonded by reinforcement, bolting or other devices that trans-fer shear at the wythe interface. 5.3.3 Attachment Inertial Loads Stresses due to attachment loads shall be combined with wall inertial loads using the absolute sum method. Block pull out shall be checked locally. 5.3s4 In-Plane Strain Due to Interstor Drift In-plane effects may be imposed on masonry walls by the relative displacement between floors during seismic events as described in Par. 5;2.10. However, the walls do not in-tend to carry a significant part of the buildings story shear. The strain acceptance criteria shall be used for in-plane story drift while a reasonable margin remains for out of plane loading.
~~~~<<15-~~~~
The gross shear strain is defined to be: Y- +{ where g = strain relative displacement between top and bottom of wall H height of wall. The permissible in-plane shearing strains are: u
= 0.0001 for unconfined walls Yc = 0.001 for confined walls The above. values shall be used for normal and severe en-vironmental load combinations. For other load combinations, the strains shall be multiplied by 1.67.
An unconfined wall is attached on one vertical boundary and its base. A confined wall is attached in one of the following ways: (a) on all four sides; (b) on the top and bottom of the wall (c) on the top, bottom and one vertical side of the wall (d) on the bottom and two vertical sides of the wall. Allowable Stresses 6.1 General The values given in Table 2 shall be the stress allowable for unreinforced masonry. The, values given in Table 3 shall be the stress allowable for reinforced masonry. The values of S given in both tables shall be used for Normal and Severe Environmental load combinations, whereas the values of U shall be used for. other load combinations, as indicated in Table 1, Where the bending due to out-of-plane inertial loading
-causes flexural stresses in the wall to exceed the design allowables, the wall can be evaluated by the 'Arching Analysis'or the unreinforced cracked walls and by the 'Yield-Line Theory'r 'Energy Balance Technique'or the reinforced cracked walls.
7.0 ANALYTICALPROCEDURE 7.1 Unreinforced Walls - Re-evaluated b Com uter 7.1.1 Finite Element Model for Fre uenc Anal sis (a) Divide the wall into quadrilateral, rectangular or tri-angular plate elements. A minimum mesh size of 4 x 1 is required for one way behavior and 4 x 4 is required for two way behavior. The number of elements should be increased where openings and high stress concentrations are present. The capacities of the elements should include 17"
7.1.1 Finite Element 1fodel for Fr~euenc~ An~el sis (Cont'd) (a) both out-of-plane bending and in-plane shear. ANSYS pro-gram STIF 43 or STIF 63 will satisfy these requirements. The aspect ratio of the element (long side to short side) shall not exceed 3. F
~~~~]7 ~~ P~g ZC I r zz d~~~~
~~~~8 //I~~~~
/ / ~g.r~g r )c I C>> burgh St!F c (b) The weights of attachments (W. and W2) 1 shall be considered as masses uniformly distributed over the areas where the at-tachments are located. The inputs of the masses at the nodal points (9, 10, 14, 13) may use generalized mass elements (STIF 21 in ANSYS Program).
(c) Define each element and nodal point location. Input material properties Ex, Ey, +xy, P(x, P(y, f as explained in the ANSYS manual. An equivalent thickness of the plate element (t ) shall be e obtained for hollow block walls such that the same moment of inertia can be kept. See Table 4 for t . The equivalent density of the element (fz) shall'lso be obtained dhch that the total weight remains the same.
~~~~"18-~~~~
TABLE 4 - lNSONRY WALLS SECTION PROPERTIES 3'M' I. ir" BLOCK WALL DIMENSIONS E UIVALENT THICKNESS Unreinforced Nominal Design ts w 1 2 b t T=8 7-5/8 1-1/4 1 7-1/2 3 ~ 81 5.31 439. 93 6. 896 10 9-5/8 1-3/8 1-1/8 7-1/2 4.81 7.06 876.81 8.677 12 11-5/8 1-1/2 1-1/8 7-1/2 5.81 8.81 1503.45 10.384 For block walls filled with mortar, the actual thickness of the walls may be used for the element. (d) Two dynamic degreesof freedom (UZ and ROTX) should be assigned to each nodal point except at the -boundary=where the number of dynamic degree of freedom will be reduced to one (ROTX), if it is simply supported or 0 if it is fixed.
~~~~'(e) Input other necessary data to perform Mode-Frequency analysis for the uncracked wall.~~~~
(f) Select seismic acceleration either from the floor response spectrum at the bottom of the wall or the floor response spectrum at the higher elevation, whichever yields the maximum response with the fre-quency determined from the above. A 251 of the frequency range shall be considered due to variations of masonry material and other factors.
~~~~-19"~~~~
7.1,2 Static Anal~sis (a) Prepare input loadings, i.e. dead, live, seismic, equipment loads, etc. and apply to the same model. Concentrated loads shall be applied to the nodal points, (b) The dead weight of the wall can be generated automatically in. the computer if tha density (f ) has been input r in the data. (c) Seismic loads can be applied statically by using a pressure load which is equal to the product of dead weight and the acceleration coefficient selected from Par. 7;1.1 (f). (d) 'he out of p-lan-e interstory drift of the wall due to ~ R! differential displacements'etween the two floors of the building dynamic analysis will also be input as part of the seismic loads in the model by defining new displace>> ment at the top boundary. (e) Loads will be combined in the Static Analysis according to
~~~~'he load cpmbinations specified in Par. 4.2. The maximum bending moment of the element (Ma) shall b'e compared with the moment capacity of the uncracked section (Mcr).~~~~
(f) If Ma ( Mcr, i.e. section uncracked, all other allowables shall be checked. If Ma > Mcr, the section is cracked. An Arching Analysis shall be performed.
7, 1,3 Archin~Anal~sis (a) The behavior of the cracked wall may be considered as that of a three hinged arch with hinges formed at midspan, top and bottom supports. If a gap exists at the top of the wall, a gapped arching action should be assumed, otherwise, a rigid arching is assumed for analysis as'llustrated in Fig. l. (b) The reacti'ons of the three-hinged wall can be solved by considering a rigid body in equilibrium as shown in Fig. 2. (c) The compressive stress of the block shall be assumed as a equal to 't s 'f rectangular stress distribution over the block wall. a depth Its 'a'ssumed magnitude shall be less than 0.85 f'm. (d) The deflection of the midspan can be determined by the method of virtual work assuming that arch members are analogous to compression members in a truss. The cal-culated deflection should not be more than 0.3t, where
~~~~'t's the thickness of the wall.~~~~
(e) Check friction shear, local stresses and compare with the allowables as stated in the design criteria.
~ ~ ~
~
~~~~lDDlJICO'Ll/ACE(LLC~~~~
~
~~~~1 Irg 1~~~~
~
I 1 1 t,OAD)MC gal VVTiVTlT CAIICD IIIOII<< I~IN lAOII >C Gapped krchl<. ln lotion Setrccn klyld and Flgt '1 ~ Stetch 111ustretl~ the Differences 5~>> fl aH Clrltg IIYIIIMC RlCID klCNIMC Diagram Shmlny Forces ln k15ld and Copped Archly. fly. 2, free Soda
~~~~<<22>>~~~~
7.2 Reinforced 4'alls - Re-evaluated b~C~om uter (a) The effective width of wall, as determined by Sec. 9.4.6.1 of ACI 531 can be used as the width of the element in "he horizontal direction. If DUR-0-VAL reinforcement is provided for stack bond walls, the effective width of the reinforced units can be increased to the same amount as that used for running bond walls. (b) Same as unreinforced. (c) Same as unreinforced except as noted below: The equivalent thickness of the element for a rein-forced wall filled with mortars can be obtained as follows: i) Find transformed section area by multiplying the reinforcing bar area (A ) 8 by (n-l), where n is the modular ratio equal to E s
~~~~/Em .~~~~
ii) Find the moment of inertia of the cross section about its centroid (usually at center), Im+s. iii) Equate Ie (= 1 12 b te 3 ) to Im~i s~ Solve for t e. (d) to (f) Same as unreinforced. 7 ',2 Static Anal sis (a) to (e) Same as unreinforced. (f) Same as unreinforced except If Ma > Mcr, the section is cracked. A cracked section iteration procedure shall be followed, as described in Par. 7.2.3.
~~~~"23"~~~~
t 7.2.3 Cracked Section Iteration Find the equivalent moment of inertia (I ) as stated" in Par, 5.2.3 of the design criteria. The moment of inertia of the cracked section (Icr ) shall be obtained from the transformed section consisting of the reinforcement area in the tension side and compressive area of the concrete block and any filled-in material (i.e.'mortar or cell grout), (b) Find the equivalent thickness of the element by equating 1 bt 3e =' I . Solve for. t e 12 (c) Rerun the frequency and static analysis using the same input data except equivalent density and thickness of the element, and shear area (tension area should be deducted). (d) The moment capacity of the cracked section, Mcap (~fs A s) d) should be compared with the applied moment (Ma). If Ma < Mcap, check compressive stress of the masonry and all other allowables and verify the crack size. (e) If Ma 0 Mcap, the wall can be evaluated by the 'Yield-Line Theory'ased on mechanisms of collapse which is analogous to the plastic design method for steel frames. 7.2.4 Anal sis b Yield-Line Theo
~~
The description of the evaluation of a wall by the 'Yield-Line Theory'an be found in the textbook, 'Design of Concrete Structures'y George Minter. 0 0
7.2.4 Aeel~~sis b Yield-Line The~os (Csee'd.) If the'eflection exceeds three times the yield deflection, i.e. ductility ratio > 3, the resulting displacement shall be multiplied by a factor of 2 and a determination made as to whether such factored displacements would adversely impact the function of safety-related systems attached and/or adjacent to the wali'he evaluation and justification of the walls in this category will be performed on a wall-by-wall basis.
~~~~"25-~~~~
SL2-1'SAR uestion No. 430.49 Provide a discussion of the inservice inspection program for throttle-stop, control, reheat stop and interceptor steam valves and the capability for testing essential components during tur-bine generator system operation. (SPR 10.2, Part III, Items 5 and 6.) ~Res onse The turbine throttle/stop, reheat stop and interceptor will be tested on a weekly basis. These valves constitute all valves required to prevent overspeed in the unlikely event of a MSIV failure to close. 490.49-1
i~ '\ 0
~~~~~ 4}}~~~~

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