ML17212B121

LER 81-041/03L-0:on 810813,plant Computer Failed,Rendering Incore Detector Monitoring Sys Inoperable.Caused by Analog/Digital Converter 1,failing to Read Ref Voltage Values Cycling in & Out of Normal Range.Converter Replaced

ML17212B121
Person / Time
Site:	Calvert Cliffs
Issue date:	09/11/1981
From:	Lagiewski J, Rizzo P BALTIMORE GAS & ELECTRIC CO.
To:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
Shared Package
ML17212B123	List: ML17212B121 ML20010G705
References
LER-81-041-03L, LER-81-41-3L, NUDOCS 8109220436
Download: ML17212B121 (149)

Text

S 'p teii be t 24 z 1981 L-81-420 Office of ll"clear Reactor Regulation Attention: iir. Darrell G. Eisenhut, Director Division of Licensing U. S. f nuclear Regulatory Co-;ission l ashington, 0. C. 20555

Dear fIr. Eisenhut:

Re: St. Lucie Uni t 2 Docket Ho. 50-389 F inal Safety Analysis Report Reoues ts For Addi ti ona1 In forma ti on A:tached are Florida Power & Light Company (FPL) responses to HRC staff requests for additional information which have not been formally submitted on the St. Lucie Unit 2 docket. These responses

ii 11 be incorporated into the St. Lucie Uni t 2 FSAR in a 'future

.-:" endment.

Very truly yours,

~~'+ ~-'-'-'[ C-Robert E. Uhrig Vice President Advanced Systems 8 Techno'logy REU/TCG/ah Attachments cc: J. P. O'Rei lly, Director, Region iI (w/o attachments)

Harold F. Reis, Esquire (w/o attachments)

Attach..ent to L 81 420 Septe .ber 24, 1981 Minutes to Power Systems Branch meeting held on September 25, 1981.

Appendix 15C.4 (Station Blackout Analysis).

Ninutes to fire protection meeting held on September 23, 1981.

Rev se response to Question ."430.64.

Revised P ess re 'solation valves submittal (Initially submitted on Seotember 9, 1981, L-81-394).

'inutes to E rgency Planning meeting held on Septa-..."e= 24, 1981 .

Response to Human Factor Engineering Control Room Design Review/Audit Report,. St. Lucie Unit 2.

~ DESIGNATED ORXGI Cerhiiied. Sy

APPENDIX 15C-4

<nQ~

STATION BLACKOUT ANALYSIS The stacion blackout event is outside or the design basis for Sc.

Lucie Unit 2. Nonetheless, an analysis was performed as requested by the NRC in response to the decision of ALAB-603. This analysis shows thar. Sc.

Lucie Unit 2 can successfully endure a complete loss of AC power for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. However, it is expected that AC power would be restored within 30 minutes to one hour as a resulc of either one of'the following corrective actions:

1. Offsite power is restored;

2. One or both of the St. Lucia Unit 2 diesel generators are started-intenance of natural circulation during this event is assured by operator action, starting 30 minutes after event initiation, to keep the coolant in the RCS piping at subcooled conditions.

The results of chis analysis have shown that:

1. Natural circulation and core cooling can be maintained;

2. The reactor core remains in a subcr't'cal condition;

3. There is no fuel failure;

4. The RCS coolant pressure remains wichin limits; and,

5. The resulting radiological doses are within limits.

Therefore, this analysis shows that St. Lucie Unit 2 can successfully endure scation, blackout event. Plorida Power and Light will implement operator training and emergency procedures to ensure that plant operarors would take appropriate acrions to assure maintenance of natural circulation.

RZSQQ~Qg) O~gIy~

~oNffieg ~

Jt 1

Total Loss of AC Power (Sta ion Blackout)

Identification of Event and Causes The Station Blackout event results from a loss of offsite power followed by failure of both standby diesel generators to start.

For Unit 2, tnis event results in a loss of all onsite AC power except that supplied by inverters from the two safehuards batteries.

This provides power to the 120 VAC (safeguar ds) instrument power and other required OC loads.

Sequence of Events and Systems Operation Table 15C.4-1 shows-a chronological list of the timing of systems actions from the initiation of a station blackout event to the time that offsite power is restored A description of the se-quence of events is given below for each safety function :

Reactivity Control: (9 kdclJ S)

As a resuIt of the loss of power to the reactor coolant pumps~ an automatic reactor trip signal is generated by the RPS on low reactor coolant systen flew, as measured by steam generator del a-pressure (0P). The reactor trip signal interrupts power to the reactor trip switchgear which in turn releases the CEA's to drop into the core. The negative reactivity inserted by the CEAs i" sufficient to maintain the cor suhcritical throughout the rest of'he tra rs i ent.

Reactor Heat Removal:

Following coastdown of the reactor coolant pumps, flow through the reactor is maintained by natural circulation. Heat is trans-fer red to the secondary systen through the steam generators.

Primary System Integrity:

A power Operated Relief Valve (PORV) opens to limit the RCS pres-sure increase following turbine trip. Steam released fram the PORV is conta ned in the quench tank. Letdown is isolated by the closing of the letdown control valve on loss of offsite power.

Late in the transient, the Safety Injection Tanks provide borated water to the RCS increasing RCS inventory and helping to maintain svbcooling in the hot leg.

Secondary System Integrity:

A turbine trip signal (TTS) is generated following the loss of offsite powe> and causes the tur bine stop valves to close. The lhin Steam Safety Valves (hSSYs) open to limit the pressure in-crease.

• Those safety ac.ions necessary to maintain the plant in hot shutdown.

DESIGNATED OHIGINAL Certified Bp V

~

~ s

~ ~

Auxiliar feedwater is automatically actuat< 0 '-7'0 "~x&hm 'u'mp:+g erator level Flow is provided by the turb qi." ch derivem.ail its control power from the stat4@a4va@Is. ih

.operator opens .the. Atmospheric Oump Valves (AOVs) and regulates them from the control r om to maintain steam generator pressure below the setpoint of the HSSVs and to reduce the primary system temperature to masntain subcooling in the hot leg.

Restoration of AC power:

Although the analysis which follows shows acceptable results as-suming no AC power for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, in actuality AC power MocOd be restored to the plant prior to this timi (~i%It'4 30m;a)ulcc. 1o e~~ bmmc) 6y<04R,~

b~

~he <c>Pomsiess1 i:oaccc iavic oc ssw5 ~

1) Offsite power is restored and the onsite buses are manualTy connected to the startup transformers. Euipment is manually loaded on these buses~ according to plant emergency proce-dures.oR

') One (or both) Unit guards loads manually 2 diesel generators is started and safe-sequenced 'onto its 4 .16 KV bus .

15C.4.3 Analysis of Effects and Consequences A. Ma themaii ca 1 Model s The NSSS response to a Station 8lackout was simulated using the CESEC-III computer program.

, 8. Input Parameters and Initial Conditions The initial conditions assumed for this event are contained in Table 15C.4-2. These conditions were chosen to provide the largest and most rapid depletion of RCS inventory and shutdown margin. The highest initial pressurizer pressure, least negative Doppler cc-efficient and most positive moderator temperature coefficient maximize the power and RCS pressure early in the transient re-sulting in inventory loss thrauoh the PORV. The major contritu.ors to the RCS depressurization are the pressurizer heat losses and RCS leakage. Maximum values of these parameters were s iected based oh technical specifications, plant ooerating data and reactor coolant pump test results. The lowest initial pressurizer water volume minimizes he available RCS inventory., Initial core inlet temperature, core mass fliow rate and pressurizer pressure have a negligible impac. on the primary system depressurization. The eval-uation of shutdown margin deple:ion was oerformed using the most negative modera"or temperats;re coefficient and the least negative CEA worth or= trip. Tnis m nimizes the shutdown margin remaining at ihe end of the transiient.

~

~

0 vf The disposi ion of normally operating systems is., i .".

15C.4-3. The utilization of safety systems is g )eg d'e ahj,.h-Q g

~

15C.4-4.

C; Results The dynamic behavior of important NSSS parameters following a Station 8lhckout is presented in Figures 15C.4-1 to 15C.4-12. '.

Table 15C.4-1 summarizes some of the important results of this event and the times at which the minimum and maximum parameter values discussed below occur. The loss of all AC electrical power initiates, among other things, a simultaneous loss of feedwater, loss of load, and loss of forced reactor coolant flow. As indicated in Figure l5C.4-1, the core power increases initially cQe to positive reactivity feedback and reaches a maximum value within a few seconds. Subsequent to loss of power to the reactor'coolant pumps, the primary coolant flow decreases and a low flow reactor trip occurs as indicated in Tabl 15C.4-1.

Reactor coolant flow vs. time is shown on Figure- 15C.4-7. Sub-sequently, due to the insertion of large negative reactivity by the scram rods, the core power decreases ver apigly and approaches the deca heat value.cB During the initial few seconds prior to reactor trip, tl e reduced steam generator heat'rejection capability leads to a rapid in-crease in both the primary and secondary fluid temperatures. The volumetric expansion~due to these increases in temperature produces sharp increases in p~imary and secondary p'ressures as well as an insurge of primary coolant into the pressurizer. The variations of the primary and secondary pressures are illustrated in Figures 15C.4- 3, and 15C.4.9. The initial rapid increases in both pres-sures are terminated by the opening of the PORV and HSSVs. The primary relief valve closes rapidly, as the primary system pres-sure decreases below the setpoint value within a few seconds after opening of the valve. The secondary safety va'.ves cycle open and closed until the operator opens the atmospheric dip valves.

HSSY and AOY fTow vs; time are shown on Figures 15C.4-11 and 15C.4-12, respectively.

The steam generator liquid level decreases during the transient and reaches a minimum value after auxiliary feedwhter flow is automatically actuated using the steam-driven auxiliary feedwater pump. Steam generator level increases until normal water level is reached. The operator subsequently controls auxiliary feedwater to maintain normal level. See Figure 15C.4-6.

The RCS pressure and temperature gradually decrease at fairly constant rat s in the long term as a result of pressurizer heat loss, RCS leakage,low heat transfer rates at the steam generators, and M~ the operator manually reducing secondary side pres-sure. Since the RCS pressure decreases at a higher rate than the RCS temperature, the pr essure approaches the saturation pres-sure.

Saturation occu r s in the reactor- vessel head pressure drop without a significant decrease n rWWag em-peratur es would result in saturated conditions in the hot leg.

Credit is taken for operator action to maintain at least 10'F subcooling in the hot leg. This is accomplished by further opening the atmospheric dump valves to reduce the secondary system pressure and temperature. The increased heat removal in the steam generators caused by the larger dT across the steam generator tubes reduces the primary system temperatures. Voiding is restricted to the vessel head and natural circulation is not adversely impacted for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

The Safety Injection Tanks (SITs) provide borated water to the RCS after RCS pressure is reduced below their discharge pressure. No credit is tak n for the negative reactivity added as a result of this discharge.

At 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, su ficient AC power is assumed'to be'restored"to ':

provide power to the charging pumos and pressurizer heaters.

These will be used o pressurize the RCS and to continue hot leg subcooling.

Operability of the turb'.ne driven auxiliary feedwater pump reauires at least 50 psia secondary pressure. At 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the initi-ation of the even', the secondary pressure will be greater than 300 psia . Less than 100,000 gallons of auxiliary feedwater are used during the event. The condensate storage tank capacity is ~~ 4 300,000 gallons.

Conclusions The maximum RCS pressure is ZRl psia ( including reactor coolant pump and elevation heads). This is well below 110~ of design pressure.

4 Natural:circulation'is maintained for at least the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period that of, site AC power and diesel generator power are assumed unavail-able. Ouring this time voids are restricted to the reactor vessel head and subcooling is maintained in the hot leg.

The radiological release due to a Station Blackout results in no more than a 0.4 rem 4 hour inhalation thyroid dose at the exclusion area boundary.

The average RCS temperature at 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is above 430 F. This is above the temperature at wnich the shutdown margin would be depleted.

~

Therefore, the core remains subcritical following reactor trip for the duration of the event.

g, ~ ~au~ d r

j 4~

Table 15C.4-1 SE(UENCE OF EVENTS, CORRESPONDING -"i5 TIMES AND SUMi~QRY OF RESULTS

'OR THE STATION BLACKOUT EVENT Setpoint or Time Sec Event Value 0,.0 Loss of all on - and off-site AC power 1.5 LoQ Primary Coolant Flow Reactor Trip, "; 93 2.0 Auxil iary Feedwater Actuation Si'gnal, '~ of Narrow Range Tap Span 2.4 Power Operated Relief Valve Opens, psig 2385 2.6 Maximum Core Power, ~ 104.8

'T 5.5 Maximum RCS pressure, psia 2541 6.0 Maximum pressurizer pressure, psia 2460 6.3 Main Steam Safety Valves Open, psig 995 "8;5 Power Operated Relief Valve Closes, psi g 2361

2. Total Primary Relief Valve Release, ibm 12 2 Maximum Secondary System Pressure, psia 1038 182. 0 Auxiliary Feedwater reaches Steam Generators, gpm 500 1800:0 Operator Opens and Controls Atmospheric Dump Valves, psia 900

2. Hain Steam Safety Valves close, psig 945

3. Total Hain Steam Safety Valve Release, ibm 116630

Tabl e 15C.4-1 (continued)

Setpoint or Time Sec Event Value 2258.0 Voiding Occurs in Reactor Vessel Head 8600.0 Operator 8egins to Reduce Steam Generator Pressure ..

to Haintain Hot Leg Subcooling 11785;0 ~,Hain Steam Isolation Valves close, psig 435.0 12540.0 Safety Injection Tanks actuated, psia 583.0 14400.0 Operator Restores AC Power

2. Total Atmspheric Oump Valve Release, ibm 363300.0

'<'ii

~4 tp TABLE 15C.4-2 !RL,

~ g>>

ASSUMED INITiAL.CONDITIONS FOR STATION BLAC'(OUT ANALYSIS PARAMETER ASSUMED VALUE Initial Core Power Level, MWt 2630 Core Inlet Coolant Temperature, 'F 551 Core Mass Flow Rate, 106 ibm/hr 133.9 Pressurizer Pressure, psia 2350 Initial Pressurizer Water Volume, ~ Level 40 Steam Generator Mater Level, " of Narrow Range Tap Span 70 Doppler Coefficient Multiplier 0.85 Moderator Temperature Coefficient, 10-4 d p/'F To determine initial power transient, 0- 10 seconds To d termine degree of shutdown margin depletion 2\ 7 CEA Worth for Trip, 10 2'dp 6.68 Pressurizer Heat Loss, 106 BTU/hr 0. 546 Primary Coolant Leakage, gpm: 16 Identified Leakage, gpm a) Technical Specification Steam Generator Tube Leakage b) Primary Safety Va'ive Leakage c) Other Identified Leakage Unidentified Leakage RCP Controlled Bleedoff RCP Seal Leakage 16

~ ~

~ ~

~ ~

~ ~

~ ~

~ ~ ~ ~

~ ~

~ ~ ~ ~ ~ ~ ~

I~ ~ ~ ~

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TABLE 15C.4-4 SL2-F SAR 0F SAFZrZ SVSZ~S

'Ta.TZATE0N FOR STATIOH BLACYOUT A

8 gZ M

fv C>

0 Q CO Aa A O V)

Ch Ch Ch t~

A QI C/7

~1~gr ~ P 4 '4 Z Vl g fthm fee 4 0K

~~

CO I

1. Reactor 2rotection S stem

2. Enzineered Safetv Features Actuation Svstems

3. Diesel Generators and Suooort S stems Reactor Trio Switch C~ar

5. %fain Steam Safetv Valves

6. Pressuriter Sa etv Valves

7. ?fain Steam Isolat on Valves

8. Pain Feedwater Isolation Valves

9. Auviliarv Feedwa ter Svs ten 2,4

10. Safetv Xn)ection S stem 11., Sht tdown Cooline Svstem (CVJ 6 TCN

12. Atmosoheric 3 l'o Valve S stem

13. Contain.-..Ant 'Ksolation Svstem

14. Contair~ent Sorav Svstem

15. Tod inc Removal Svs tern

16. Containment Com'oustible Gas Control Svstem

17. Containment Coo lin Svs tern "Hotes: 1. Both diesel generators fail for this event.

2. Only those portions powered from the safeguard batteries are available.

3. Safety injection Tanks are available.

4. Auxiliary Feedwater is automatically actuated Only the turbine

~

dr i ven pump i s a va i 1 abl e.

5. AOVs can be manually operated from the control room.

6. Portions of this system are actuated on loss of instrument air.

Systems not checked "re not uti ."ed durir~ this event.

120 601 30 2 0 6 8 10 12 TIHE, X 103 SECONDS FLGP!DA PG':eR 8 LIG'rlT CG.'.lPANY ST. LUCl"- PL'HT UHIT $

CORE POMER YS TIt1E FIGURE 1GC.4-1

4 &If'-:@4 120 OC

~~ 90 I

>C i UJ

~

~

LL LU IcCLU Q

g~ 60 C CD UJ O CD U

CD pJ 30 2 4 6 8 10 12 14 TIVE, X 103 SECOl'JDS FLOPIOA PG'~'ER 6, LIGHT CC'.IPANY ST. LUCIE P'NT UNIT 2 CORE AVERAGE HEAT FLUX VS Tit1E FiGURE 15C.4-2

Ji L~d 2400 1800 1200-600 2 4 6 8 10 12 14 TINE, .X 10~ SECONDS FLORIDA PG"' it LlGHT CQ.',iP 'NY ST, LUClK Pl At SLCOilDS FLORIDA POV/cR 8 LIGHT COI!PALY ST. LUCIE PLAHT UHIT 2 REACTIVITIES VS. TiiilE FIGURE 15C.4-5

OPQ

~I 600 uJ Cr.

UJ Wl CQ zp Q

6 8 10 12 10 TItiE, X 10~ SECOf')DS

~ LiQHT CP,',(F'ANY FLPRIDA PPW'ER ST. LVCI Pt.AHT LNlT 2 P."ESSURIZER HATER '!'CLUt!E YS. TIt1'"

FIGURE 35C.4-S

1,2 2 LI 6 8 10 12 10 TINE, X 10> SECONDS FLOPIOA PO"'S'R & LIGHT CCh(PANY ST. LUCIS PI 'HT UNIT 2 REACTOR COOLAHT FLO(l 'IS. TIYiE FI GURE 15C. 4-7

320 3.00 2.80 cCI 2.60 z

Q 2.40 Z

2.20 2.00 x

CD I

0 1,60 x

1.60 1AO 1,20 0 4 5 6 7 8 9 10 TIME, SECONDS FLORIO'OY'ER 8 LIGHT COMPANY ST. LOCI~ l'LIT O'll HOT CHANNEL!AINIMU'IONSR YS. TIASE Fl GURE 15C.4-8

p~ p@

pap, .Q 1200 1000 800

~ 600 QQQ.

200

'2 6 8 10 TI>'1E, X 10> SECONDS FLORIDA PONCE 8 LIGHT CQEIPANY ST. LUCIE PLAHi UHIT 2 STEAM GEiIERATOR PRESSURE VS. TIiME FIGURE 15C.4-9

gD V

20000

~ 160000

~V

~ 120000 pP

~~ 80000

~~ 40000 6 8 10 12 14 TINE x 10~ SECOI'lDS Fl PRIDA PQER E LIGHT CP'PANY ST. LUCIE PLIGHT UHIT 2 I

STEAN GEiIERATOR WATER i~aSS, VS; 1 li'..

FIGURE 15C.4-10

~ ~

~ r '4 1200

~ 900

> 500 2 0 6 8 10 Zt 14 16 . 18 TINE. X 102 SECONDS FLORIDA PO"'ER 8 LIGHT CQh'.PANY ST. LUCIE PLANT UNIT 2 i<SY FLO!I YS. Tfi'IE FIGURE lSC.4-11

b 129 90 CD UJ UJ Z

(Q 30 U

2 0 6 8 10 12 10 TINE, X 103 SECONDS FLORIDA POVrcR 8 LlCHT COi~ F~NY ST. lUClE PL@Hi UHlT 2 ADV FLOH YS. TINE FIGURE 15C.4-12

Emergency Procedure 2-0030140 Rev.0 FLORIDA POWER 6 LIGHT CO.

ST. LUCIS UNIT 2 SLACZOUT OPERATION REV. . RG ~ OAT AP PROVAL PLT. KfGR. DTD o Emergency Procedure 20120042 Rev.0 g DESIGNATED ORIGINAI,'ert%l."iel Dy

FLORIDA POWER 8 LIGHT CCHPAHY ST. LUCIE UNXT 2 EMERGENCY PROCEDURE NUMBERS 2-0030140 REVISION 0 Draf" 1 06/12/81 dps 1.0 SYHPTOiafS

~ 1 Alarms associated vf.th the loss of operating plant components.

~ 2 Loss of normal control room lighting and DC lighting energized.

'3 Reactor and turbine trip.

.4 Emergency diesel genera tors star"

.5 Reactor coolant pump trip and steam generator feed pump trip.

.6 Reactor ?o~er decrease

.7 Przr- pressure decrease

,8 T Ave decrease

.9 Prz" ~ level decrease 10 Stm. Gen. Press increase

!.1 Stm. Gen. Level decrease DESIGNATED ORIGINA@

Cert'iiied By

Page 2 of 16 URGENCY PROCEDURE NPiiBER 2-00301.40 REVISION 0 2.0 29KDIATE OPRATION ACTION

2. 1 MEDIATE ZOOID NT POSITION Tr ip Turbine/REactor Push Buttons Tripped Ensure, Full Length CZA's Inserted Znsur e Reactor Trip Breakers Open Turbine Valves Closed Znsur e 240W40349, 240W40352, Gea- Bus.

Close Reheater Control TCV's Closed NV-08-4, 6, 8, 10 Ensure D.G. 2A, 23 Running AND Ensur e Bkrs. 20211, 20401 Closed Open S.U. Brkrs. 20102, 30102, 20101, 30202 Ooen Zas ure T Ave Decreasing Znsur e Atmospheric Steam Dump Oper atiag Close S/G Blowdown Valves Closed Start *I.. Aux. FDVZR. (Steam Driven) Start Easure 2. Automat'c Actions per. sect. 3.0 Actuated.

2 Or Table 8.3-2 (Dies. Gea.

Sequence) Running NOTE:

If aux. fdwtr. oos have started due to the auto start feature, the motor driven pumps may be secured 30 sec. after they star>>

2. ~annually Initiate any auto action that does aot occurr ~

3. If vital indications aad/or controls are 'ost refer to OP.Proc. 2-0970020, 2-0970021 (120V-AC.) or 2&960020, 2-0960022 (120V-DC.)

Page 3 of'6 EMERGENCY PROCEDURE NUMB'Et 2-0030140 REVISION 0 2.0 B&KDIATE OPERATION ACTION: (Cont.)

2.2 'BKDIATE AUTO ACTION Check Reactor and turbine trip, generator lockout Generator breakers open. 240W40349, 240W40352 Incoming feeder breakers open to 6900 V and 4160 V buses.

Tie breakers between Normal 4160 buses 2A2 and 232 and the emergency 4160 V buses (2A3 and 2B3) ooen.

Ties between essential and non-essential sections of emergency 480 V MCC's ooen.

Breakers ooen for the following non-safety related 'oads which are normally ied from emergency buses HOTZ: =hese Loads can be manually reconnected to the emergency buses as needed'harging Pump B. A. Makeup Pumps Instr. Air. Comp.

Przr ~ heater transformers 2A3 and 2B3 Fire pump 1A and 13 CEA Drive M.G. 2A 6 23 Fuel Handling 480 V MCC 2A8, 238 Reactor Cavity sump pump Reactor building elevator Electrical equipment room hoist 120/208 power panel 121 transformer Lighting panel transformers 110, 112, 114, 117, 125, 126

Page- 4 of 16 EMERGENCY PROCEDURE NUaa3Wc, 2&030140 REVISION 0 2.0 QQKDLWTE OPERATTON ACTION: (Cont.)

2. 2 Immediate. Auto Action: (Cont.)

Incoming feeder from 2A2 & 232 4160V buses RCP oil lift pumps (3 pumps only - A. pumos running)

Airborne radioactivity re+oval fans ~~-}.&2 Przr. relief isol valves 1404 & 1405 CVCS heat tracing transformer 2A & 23 480V Lighting panel 2A, 23 & 2C Paste.management heat tracing transformers 2A, & 23 Air conditioner 2HVA/ACC-3C.

Power panel 120 Lighting panels 113, l.l6, 109, 115, 130 Refueling equipment Refuel'ng water to charging pumps V-2504 3oric Acid batching tank heaters Pire siren all Loads oc seerseucy buses ara cripped ecosoc the following:

Emergency lighting Class E power panels~

RCP oil lift pumps (A. pumps only -3 pumps off)

Diesel fuel transfer puma.

Diesel generators A & 3 start and energize 4160 V emergency buses 2A3, 233, and 2A3 and loads listed above

Page 5 of L6 EMERGENCY PROCEDURE NUMBER 2-0030140 REVISION 0 2.0 BQKDIATE OPERATION ACTION: (Cont.)

2.2 Immediate Auto Actions: (Cont.)

Subsequent loads are started at 3 second intervals. See Table 8-3.2, Bnergency Diesel Generator Loading Sequence.

Auxiliary Peedmter auto start sequnce initiates Hen the first steam generator level decreases to 347.

NOT.: Pump start and flo~ init~mtion is delayed for 3 minutes ~

Pumps may be started by the operator AT .QfY TWK.

• l ~

Sl.2" }SAR TABLE 8.3 2 I

, Iep DlESEL GERERATOIl LOADIR~SE

..(5)

UE,ICE III Of(S-RUlltl lllG LOAD (kM)

Per llomin a 1 LOCA I ..r, Diesel Load or ~ =."I e Snistsioua Mith (Recirculation) Hain Stcam Line Automatic Starting Generator Ramenlate Starting '. Tlmlnt, l.oso of bff- Mith l.oss of Break Mith Loss of item I~iwent iti ILuantltv lip I:VA I'. ~ ~

I~eence Site Poucr:(LOOP) itee 1'ouer (LOOP) Offoite I'ouer (LOOP) lligh Prcssure Safety ln) Pump I 400 2422.0 'Il .':

0 Sac I 373 373 Hotor Operated Valveo Lot Lot 40

'l jlI'ater,liei I.

0 Scc bcc 40 70 Ie li I.

ieI" 8

70 (I) 70 Emergency Lighting  : l.'. ll U

1 l 0 Scc 30 ~, 30 30 Poucr Panels e I ~

I -'!; I', I, 5 Dicscl Oil Transfer Puiopo 21. 5 0 Scc I

.5 I.ift Puiaps 19

6.85 RCP Oil 10 '. 0 Sec 19 19 I

I eh

~ ~

0 Sec' 20 i.l.'I e:.'

~

20 20 Unintcrruptiblc Pouer Supply I

~ - 'tll'.

~

~

IIVAC Dampcrs w=

Sec lili I

e

~ 1~

Lot I,,i'I 0 Scc

~ ~I l'.e, IIVAC Valves 10 Elec Equip. Room Exhaust, 2-IIVE-ll 50 244.7 ',.: 0 Scc 47.5 le i.

I

~

47. 5 47. 5 L'luc Equip. Room Exhaust, 2-RV-3 I 34.22 ';  :: 0 Sec li I2 Battery Room Roof Ventilator, 0.75 8.5 0 Sec .75 Il .75 e75 I~

2"RV-1

"',l Lou Prcssure Safety ln']. lump 400 2183.3 3 Scc I l

361 Containment Fan Coolers 125/83 828.4 3 Sec 160 II6 116 IS Elec Equip. Room Supply 100 584.12 3 Scc 95 95 95 yP Component Cooling Mater Pump 450 2491.2 Sec 400 400 400 ansu>4 Hi!B aollouoll <AH Z $ S) f $3 ~ (

IS Shield Bldg llcatero Lot I.' 6 Scc 37.5 37.5 Q intake Cooling Mater Pump 600 3709.0 Sec 527 527 527 I~

Containmcnt Spray Pump 500 2892.6 l2 Sac .a 450 450 1i ~ ~

2I Ilydraz inc Pump 2I.5 12 dcc ~ e 'el

'is,) ' I~

I~ I I. ~

I I I.l ' ~

e,

I

~

)

SL2-)SAR TAULE 8.$ -2 (Cont'<I)

RVttttlttC LOAD (kff)

I . LOCA Itou<inal , ~ I,)

I'.'tic ocl Ioah or St<ut<town itfrn: (Recirculation) Hain Stoa~ Linc Automatic Starting Generator Namcplatc Starting 'fming l.oss o( Of(- " With Luos of 0((- Steak ffitn Loso of Item () ) Ouantitv IIP t(VA . Sueuence I'ower (LOOI') 'ite S itc Power (LOOP ) Of(site Power (LGOI')

22 Auxiliary Fecdwatcr Pualp I 350 I95I.4 ~ . I5 Sec 291 297 297 (2) 23 Uoric Acid ttcat Trace Lot Lot I8 Scc 5 (3) 57 24 Control Roo<a hir Conditioning I 60 IS Sec 51 57 25 Control Room Emcrg Fflter Fan I 10 62.0 I8 Sec 9.5 9.5 9.5 I50 900.l IS Sec I42.5 l42. 5 l42. 5 26 RAU Supply Fan I 60 358 IS Sec 57 57 57 27 ECCS Area Exhaust Fan I 28 Reactor Cavity Supply Fan I 20 I24. I5 18 Sec 29 tleactor Supports Cooling I 40 234.16 IS Sec 38 30 intake Uldg Cooling Fan I 7.5 44(0 IS Scc 5 3l Battery Charger 73.5 73. 5 32 Charging Pumps l25 I656.8 Manual load 237.5 231. 5 I,

33 Uoric Acid Make-Up Pump I 25 I24. I Hanual load 23.75 23.75 34 I.ow Pressure Sa(cty lnj. pump I 400 2I83.3 ttanual load 309 35 lnotrumcnt hir Comprcosor 60 340.6 Manual load 51 36 Fuel Pool (:oolfng Pump 40 234.76 Manual load 38 38 ttydrogen Rccombiner Hanual load 75 Total 3I44.0 ktt 3274.25 kff 3335.53 kti

!, >Itotcs t I) hcruated on RAS

2) Started if operating prior to LOCI')

Approximate kff rcquircd (or temperature maintenance

4) Itc<so 32 to 37 inclusive arc manual loads 5),items i<tcnti(ie.l as 't.sacr" will be aupplic<l in a future amend<1<cot ~

Page 8 of 16 EHERGENCT PROCEDURE NUMBER 2-0030140 REVISION 0 3~0 SUBSEOUENT ACTIONS:

3.1 Ensure adequate natural circulation flow (a.) Loop T is less than full power T (<44 ":)

(b.) Tc is constant or decreasing (c ~ ) Th is stable or decreasing (d.) No adnormal differences between T -RTD's and core exit thermocouples 3 ~ 2 If natural circulation is not assured (a.) Check RCS Temperature/Pressure to ensure subcooling.

(b.) Ensure aux. feed flow to the S/G has been initiated, steam dump to atmosphere is functioning ~

3 ~ 3 Start oae RCP in each loop, as soon as offsite power is available.

3.4 Start or stop equipment in Table 8 '-2 as required CAUTION:

Do not over'oad diesel generators when startinz additional eouioment. 3685 KJ max. cont rat'n ~

3.5 If one diesel ails to start, then (a.) Attempt manual start (b .) Send operator to investigate locally check alams, overspeed trip, local manual start. CHECK Refer to Op. Procedure 2-2200020, 2<<2200050 3.6 Locally OPEN (Condenser vacuum brkrs)

HV 10-13 110 10-13

Page 9 of 16 EKRGENCT RGCWURE NUMBER 2-0030140 REVXSTON 0 3.0 SOBS'E UENT ACTIONS: (CONTe)

CPECX 3.7 Locally CLOSS (M.S.R. Yamen Stean Slack Valves)

MV-08-4 ~

24V 08 MV-08-8 KV-08-)0 3.8 NSR Harm-up valves closed or close manually ill>>08-5

Ã7-08-7 MV-08-9 MV-08-1. 0 3.9 Verify one (1) set of cavity and support cooling fans operating, or start.

3.10 Lock out automatic equ'pment that is not in service.

3.11 ~mnual3.y open all breakers on any non-vita'us or motor control center that is to be energized.

3.12 Reset lockout relays for each required bus to allow closing of feeder breakers.

3.13 Energize 4160V buses 2A2, 2B2 as follows;

~Stni noa-vital 4.16 XV bcs Sttts.

(All should be opened automaticlly)

Insert sync ~ plug.

Close 2-20109 Close 2-20309 Sold and Close 2-20209 Close 2-20411

Page 10 of 16 EKRGENCT PROCEDURE NU44BKL 2-0030140 REVISION 0 3~0 SUBSE UENT ACTTONS: (Cont.)

3.14 Energize non-vital load centers 2<1, 2B1 as follows:

CHECK St"do load centers 241, 231 Class 2-20110 Close 2-20310 3.15 Energize 480V-HCC's 2Al, 2B1, 33).4, 2B4, 2C as follows:

Strdo SCC's, 241, 231, 244, 234, ZC Close 2-40115 Close 2-40410 Close 2-(later)

Close 2-(later)

Close 2&0119 or 40409 3.16 At (CC-2C Close breakers for:

Turning gear - 42510 Bearing os. pump - 42506 Air side seal oQ. pump - 42507 Hydrogen side seal oi'ump-42'04 3.17 Place turbine TC'pl pp in ooeration 3.18 Align TCQ system to the instrument air compressor back to normal 3.19 Place turbine drain valve control to the

~oea position.

3.20 i!afore turbine bear1nS o11 pressure drone to ~(2 os1 Start - bearing oi'ump & oi'ressure drops to 10 psig.

Start - smetteacy D.C. oll pump Do nat run both pumps s~ul".aneausly.

3.21 Remove the following components from service.

a~) Steam )et air efectors b ~) P ~ming e]ector c~) Amc. Priming e]ector d.) Aux. Steam to R.A. 3.

e.) Gland Seal

Page 11 of 16 EMERGENCY PROCEDURE NGK3M 2-0030140 REVXSION 0 3.0 SUBSEOUEVZ ACTIONS: (Cont.)

3. 21 (Cont.)

CAUTION:

Consider equipment starting requirements. Alternate operat'on of equipment may be required to avoid overloading the diesel generators (3685 ZV. am>. cont. rating)

CHECK 3.22 Start CEDH cooling fans A or 3

3. 23 Start reactor support cooling fans A & 3 3.24 Close breakers for pressuriaer heater buses 2-20204 2-20403 3.25 Ar, approx. 600 RPM turbine speed Bear~a oil lift pump - start 3v.26 gtart - tcrgiae lute otl vapor ext:actor gecerator oil vapor ext"atptor 3.27 At approx. 0 RPN turbine speed verify turning gear operation or initiate .mnually.

3.28 Reduce turbine oil temperature to 95-100 P.

3.29 Isolate TCV to the hydrogen coolers.

3.30 If additional CST water is required and sufficient power is available, place the water treatment plant 'n service.

NOTE: Rezer to OP.Proc. 2-0030142 3.31 Place the spent fuel cooling system in operation as necessa~.

Pith fuel cores stored, NOTE:

it will1/3before 3

take 5 hours without reaching the cooling boiling point ~

A g

~ Pi'>>

Page 1.2 of 16

~GENCY .ROCEDURE NUMB'&030140 REVISION 0 3.0 SUBSE UENT ACTIONS: (Cont.)

CHECK 3.32 Sample and analyze che RCS to determine if fuel element failure has occurred NOTE: Periodically verify oil storage and transfer operations.

3.33 Determine expected durat'on oz powez'utage.

If unable to do so or the outage 's to be extensive, borate the RCS to cold shutdown concentration.

3.34 If the outage will exceed 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and che RMT is available, proceed to cold shutdown conditions utilizing thermal circulation, atmospheric steam dump, and feedmter addit'on. Place S.D. cooling in service when conditions permit- Proceed co step 4.43.

CAUTION DO NOT BEGS P~~ COOLDOWN'.

UNTIL COLD SHUTDOWN 3

c IS VERI I.D>>

35 the oucage will exceed 4 houz's and the RVZ is noc available, the S.I.T.'s should be used for makeup to the RCS. Nake the fol'owing preparations.

3.36 Verify ooerac'on of che instr. air systems.

CHECK 3.37 OPEN 480V A.C. bzkrs for:

NV-2504-HV-2501-3.38 OPEN and lock, S X.T Cast line zecurn co RHT V-07009 S.I.T test line return to RVf V-3463 S.X.T test line tie to VCT V-03920

Page 13 of 16 REGENCY PROCEDURE NGaaBER 2&030140 REVISION 0 3.0 SUBSEQUENT ACTTONS: (Cont.)

CAUTION:

Insure that one BAlM remains in service as a source oi borated water in Node 5 ~

3.39 Borate the RCS to cold shutdown Bc ~

3.40 Proceed to cold shutdown conditions utilizing thermal circulation, atmospheric dump and am. fdwtr addition.

CHECK 3.41 Select a S.I.T. to use as a makeup source to the VCT. Operate the approoriate fill and drain valve, 2Al: -AOV-3621, 2A2,

-AOV-3611, 2B1, >>AOV-3631, 2B2, -AOV-3641 CAUTION:

USE ONE S.I.T AT A T~~.E. Insure RCS is )17SO PPN.

3.42 Place shutdown cooling M serv'ce when appropr'ate temperatures and pressures are reached.

3.43 If przr ~ cooldown cannot be accanplished satf.siactorQ.y by ausiliary spray, proceed with the alternate positive means of depressurization a3 'ollcws:

CHECK a.) Place power operated rel'ef valve V1402 and V1404 switches in: overide b.) ~mitiate a high przr. pressure trip signal on two RPS channel trip units.

c.) Place either power operated relief valve (V1402 or V1404) switch in normal range position.

NOTE: This will vent the pressurizer to the quench tank.

To close valve, place svicch lc override d~) Control rate of cooldown/depressurization by selective operat'on of power ooerate relief valves in this mode, untM cooldown vie the a~. spray valves can be initia ted

Page 14 of 16 EHERGENCT PROCEDURE NUK3ER 2-0030140 REVZSZON 0 3.0 SUBSE UEÃT ACTZONS: (Cont.)

3.44 TAhen normal AC power is avaQ.able CHECK a.) Restore bus sections to normal supply b.) Place diesel generator system in standby per 2-2200020 c.) Restore all systems to normal 4 0 PRECAUTZONS-'..

Yanitor diesel oil storage tank levels.

B. Verify operat'on of the fuel oil transfer system.

C. Do not overload the diesel when starting additional equipment (3685 ZR-max. continuous rating) insure that one BAM remains in service to use as a source of borated water wh~~e in mode 5.

Zf an S.Z.T. is to be used as a make-up source, use only on at a time, insure RCS's at >1750 PPM before using a second S.Z'T.

5.0 PURPOSE A%) DZSCUSSZON:

This procedure provides the action to be taken in the event of a ccmplete loss of off site electrical power concurrent, with a turbine tr" p ~

Discussion A, loss of power to the 4160 V buses, results in a loss of power to all 480 V load centers and motor control centers and to all instrumentation not fed directly or indirectly frcm the station battery. A reactor trip wQ.l occur from a low reactor coolant flow rate senal due to the loss of power to the 6900 V buses supplying the reactor coolant pumps and will be accompanied by a turbine trip and generator lockout.

Steam dump co atmosphere must be used to remove reactor decay heat. Znit'ally, steam generator sa ety valves may actuate to augment the steam flow and to help control. steam generator pressure immediately after the trip.

Page 15 of 16 EMERGENCY PROCEDURE NPiGKL 2-0030140 REVISION 0 5.0 PURPOSE AND DISCUSSION: (Cont.)

On site pover vill be supplied by Emergency Generators.

A, rapid reduction in steam generator water levels vill occur due to the reduceioa of the scesm generacor void fraceioa on the secndary side and also because steam flow will continue after normal feedwater flow stops..kuxi1iary feedvater "'w vill automatically initiate 3 minutes after the irsc steam generacor level reaches 34K (2/4 logic) ~

Core decay heat removal is accomplished by natural circulation in the reaceor col'ant loops.

Core damage is not expected as a result of a loss of power condicion as che steam geaeraeors are maiaca'~ed as a heat sink and no 'oss of water occurs frcm ehe pressurizer.

If operating under blackout conditions and an engineered safety features actuatioa sigaal occurs, any aon emergency loads that are runniag will be automat'cally cripped aad the required emergency loads vill be automatically started.

6. 0 REPERENC ES:

'.1 "-SAR, Sect'oa 15 6.2 'PSAR, Section 8 6~3 Operating Procedure;r0030130, Shucdown Resulciag Prom Reactor/Turbine Trip 6.4 Operating Procedure f0210020, Charg'ag and Letdown 6.5 Operating Procedure 90330020, Turbine Cooling qatar Operation 6.6 Operating Procedure 80250031, Boron Concentration Cont ol, Of f-Ho rmal 6.7 Operating Procedure 81010040, Loss of Iastament Air 6.3 Operating Procedure 91540020, Racer Plant- Startup and Shu down 6.9 Operating ?rocedure:$ 2200020, urgency Diesels - Staadby Liaeup 6.10 Operat'ng Procedure 80700022, Am. Peed uter System Operation 6.11 Operating Procedure 20030142, RCS Cooldown During Blackout,

Page 16 of 16 EMERGENCY PROC')URE NUMB'-0030140 REVISION 0 7.0 RECORDS/NOTIP ICATION:

Normal Log Entries.

Hotify Duty Call Supervisor.

8~0 AP PRO VAL:

Reviewed by Plant Huclear Sa ety Committee October 15 1974 Approved by X. H. Harris Plant Manager October 25 1974 Rev. 19 Revieved by H3Q Pebruarv 1981 Approved by C. M. Vethv Plant ~~nager March 10 1.98 1.

Purpose or Discussion:

"LAST PAGE" Emergency'rocedure 2-0030140 Rev. 0

l r ~ ~

4 U ~1

Attachment to L-81-468 October:27, 1981 Minutes of meeting held on October 23, 1981 on the topic of Compaction Piles at St. Lucie Plant.

P Response to the items mentioned in the meeting minutes of October 23, 1981 on the topic of Compaction Piles.

Minutes of meeting. held on October 23, 1981 on the topic of Electrical SER open items.

Final Submittal to (1) Adequacy of Station Voltages; (2) 90% motor starting.

Corrected Resubmittal of the Inadequate Core Cooling write-up submitted by Letter L-81-463.

Matrix Power Supply Isolation Devise Testing Clarification to our final response to the NRC Control Room Audit Findings (refer to our submittal FP&L letter L-81-420, dated September 24., 1981).

Loss of Coolant Accident (LOCA)

Inadequate Core Cooling (ICC)

l MEETING MINUTES

~

NRC 6 FPL OCTOBER 23, 1981

Subject:

Compaction Piles at St. Lucie Plant.

Location: ,C-E Conference Room, Triangle Towers Building, Bethesda, Maryland.

Attendees:-

\

NRC FPL Ebasco V. Nerses E.W; Dots'on E. Zuchman L. Heller P.P. Carier M.P. Horrell R. Pichumani W.F. Brannen J.L. Ehasz G. Lear (part-time) W.F. Mercurio G. Coscia Proceedings:

The NRC staff opened, the meeting by reviewing their concerns related to a blockage of the plant's circulating water system intake structures by a land slide resulting from the liquefaction of subsurface soils during a seismic event. They noted that their concerns were still valid since it appeared that there was still a layer of in-situ soils that had not been densified by the compaction piles placed in the slopes north and south of the intake structures (see minutes for meeting of October 14, 1981).

Ebasco presented cross sections of each row of compaction piles which they had prepared since the meeting of October 14, 1981. The cross

-sectionswere based on the original pile driving logs and detailed:

1. Ground surface elevation for each pile.

2. Elevation of class II/in-situ soil interface.

3. Elevation go which each pile fell under its own weight.

4. Blow count per foot for each pile.

Using the cross 'sections Ebasco demonstrated that the majority of the piles were driven from a point above the class II/in-situ soil inter-face with significant blow counts and, therefore, densified the. in-situ soil. They noted that the piles that fell into the in-situsoil were probably passing through a clay layer that lies between elevation -20 feet and -35 to -40 feet.

Ebasco also presented documentation which established an increase of 3% to 6% in the relative density of the in-situ soils as a res'ult of driving the. compaction piles. It was noted that this should yield a 76% to 79% average relative density for the in-situ materials.

Ebasco also. demonstrated factors of safety against liquefaction during a seismic event of O.lgand 10 cycles ranging from 2.4 to 3.8.

The NRC noted that, based on the information presented, the compaction piles in the north and -south slopes would be acceptable. They added that several items would have to be included in a docketed submittal:

The existance of the clay layer should be documented.

2~ The fact that only one pass with an auger was made into the in-situ soils should be documented.

I

3. Details of the original excavation shoul'd be pgovided to justify the cross sections.

'4. A reason should be provided for some of the piles following below the class II/in-situ interface.

5. An explanation as to why other piles hung up above the interface should be provided.

N

6. The effectiveness of compaction piles should be documented.

I Ebasco agreed to revise the submittal to incorporate the above items by Wednesday, October 28, 1981.

INTRODUCTION The following information has'een prepared to document FP&L's position that the soils North and South of the Intake Structures is sufficiently dense to resist liquefaction:(1)elaborated on information presented in the compaction pile reports (noted below); (2) graphical. presentation of depths that compaction piles were actually '.driven; (3) calculation of denisty increase due to pile-soil displacement and vibration effects @) liquefaction analysis for 3 different cases: relative densities of 60.8%, 73.3% and 80%;

(5) reference to other projects where compaction piles were successfully used for soil densification.

REFERENCE REPORTS

1) Ebasco Report - Compaction Pile Soil Stabil'ization Program - dated January 1976

2) Ebasco Report - Soils Foundation of the Emergency Wall - dated May 1976

t 1)

Facts Paragraph removal of 5 t on soil was experienced.

page 3 due of January, to augering.

76 report makes comments with respect to This statement is the worst case that Generally'o material paragraph should be changed to read:

was brought to the surface.

/

This "An estimate of the amount of material removed from the hole during the established pre-drilling procedure was made for one of the 74 foot piles. This estimate was very conservative, reflecting the-worst case,--and is"only,indicative of this .case Mhe estimated volume of material removed as a result of the drilling of this worst case pile was 95 cubic feet. The volume of a 74 foot long pile is 167 cubic feet which results in a material displacement of 57 percent of the pile volume. This material was removed from the upper half of the hole in the Class II fill. Very little material was removed from the insitu material poxtion of the hole, making the compaction effects of the pile effective in the insitu material where densification by material displacement was required by the NRC staff. Our visual estimate of material removal from other pile loc'ations was essentially zero, and generally 1/2 to 1 cu. yd; of sand was used in backfilling adjacent to these piles."

These changes give a clearer picture of what happened when we performed the densification by compaction pi.les. It is our engineering )udgement that the areas compacted in this manner now have an in-place relative-density of 80% or better. This is based on the fact that:(1) these areas were pre-loaded during initial excavation and backfilling while dewater" ing was taking place, and(2) that the displacement and compaction of the I

insitu material occurred as a result of driving the compaction piles.

The St Lucie Unit 2 SER indicates some confusion with the information pre-sented on compaction piles used to 'densify the soils beneath the UHS barrier wall and small triangular areas North of the Unit 1 Intake Structure 4

and South of the Unit 2 Intake Structure. This is probably true because of varying- statements in the two reports referenced on page one. This confusion can be cleared up by referring to a field trip report titled, Compaction Piles North of Unit 1 Intake and South of Unit 2 Intake, dated October 22, 1975.

The first area of confusion is in paragraph 4, page 2 of the Januar'y 1976 report. The paragraph as written is not entirely correct. It should be revised to reflect the ideas in paragraph 3, of" the October 22, 1975 memo.

Thus, the January 1976 report, 4th paragraph, page 2 should read:

"The final drilling-driving procedure established was to drill one pass with the auger to a depth of approximately 7(7 feet, to facilitate pore pressure relief in the insitu materials. Two additional passes would be made only to the bottom of the Class II fill, to relieve skinfriction in the backfill and insure that the piles would be driven in the insitu material."

Paragraph 6, of page 2, of the same report should read:

"In areas where hard drilling and driving was encountered, the number of auger passes was increased to no more that 5 but only to the bottom of the Class II fill. This was to ensure that the pile could be driven in the insitu material with only a minimum of skin friction in the backfill."

As stated in the St Lucie 82 FSAR Section 2.5.4.2, occasional discontinuous plastic clay seams were found in the upper part of the Anastasia formation, which extends from the surface to approximately El-150 feet.. Several borings w 3

in the vicinity of the areas where the compaction piles were installed show the existence of clay seams-between El-20 feet and El-45 feet.

Of specific interest are borings B-103, B-104 and B-117, which indicate 1

a seven to eight foot thick clay seam in the intake area occurring beb tween E1-22 feet and-43 feet. Additionally, borings AE-l, AE-13, AE-17 and AE-23 indicate a sandy clay seam varying in thickness from three to nine feet occurring between El-27 feet and El<3 feet. These clay seams have low SPT values, indicating a low shear strength. Although this clay was excavated beneath the main plant island, it is still present beyond the limits of the excavation. Thus, the clay seam intersects the sloping interface between the Class II backfill and the insitu soil. In the intake area, this intersection generally occurs between El-22 feet and E1-43 feet.

The intent 'of pre-augering several times to the Class II fill-insitu soil interface was to minimize the amount of skin friction on the piles driven through the .vary dense Class II fill. However, in areas where as much as 75 feet of fillhad to be penetrated to reach the insitu soils, pile driving began at elevations substantially higher than the interface (in particular,,rows',5,11 and 12) because the pre-augered holes would not remain open for full insertion of the pile prior to driving and because skin friction from the fill could not be entirely eliminated. Rather than remove the pile and perform additional pre-augering to the interface (in excess of five auger passes), the piles were driven as placed in order to limit disturbance of the Class II fill.

In twelve cases, piles dropped up to ten feet below the Class II fill - insitu soil interface before driving began. These piles are located in areas'here the thickest portions of the insitu soils to be densified occur

- 4

• existed around each pile after driving. The cone was 3.5 to 4.0 feet across at the top and 9 feet deep. We estimate that the increase in relative denisty is 3 to 5%. Based on our original determination of Rd (relative density), we estimate that the original relative density prior to dewatering and pile driving was 73.3%. (See paragraph 4). Add to this the 3 to 5% increase. The after construction relative density is 76 to 78%, due to displacement only. The vibrational effects of pile driving also contributed to soil densification; however, due to the difficulties involved in evaluating this increase, vibrational effects have 5een neglected. Based on this increase in relative density, we believe that we have more than an adequate factor of safety against liquefaction.

4) The attached figure presents our calculation for factors of safety against liquefaction in the areas north and south of the intake structures, in the insitu soils. The factors. of safety have been calculated for relative densities of 60.8, 73.3 and 80%. These relative densities were based on values ob-tained during our earlier investigation in the area. The 73.3% is the average relative density and 60.8% is one standard deviation less than

'he average. These values are, presented in the SL2 PSAR Appendix 2G.

In addition, we show the safety factor for a relative density of 80%. This 80% is a conservative lower bound based on the increase due to dewatering alone or due to compaction by pile diving alone. In any case, using the procedures outlined by H.B. Seed, the minimum safety factor against liquefaction in the insitu soil is greater. than 2.2 for any depth for any possible relative density and ranges up to a value of 3.7 safety factor.

6

(and consequently, the overlying Class II fill is at a minimum thickness).

In these areas the Class II fill-insitu soil interface occurs in the previously described clay layer. Since less Class II fillhad to be penetrated to reach the insitu soil than in the other areas, the piles were able to be inserted close to the interface elevations prior to driving. However, due to the high static contact stress at the pile tip (approximately 6 TSF), the pile also penetrated the soft clay layer (which was further weakened when remolded by the one auger pass that extended. into the insitu soil to relieve pore pressure), and driving began with the pile tip at the bottom of the clay. Since clays are not sub)ect to liquefaction, densification was not required in the clay layer, and therefore the absence of pile driving through the clay did not detract from the overall quality of the compaction pile program.

2) The attached 14 figures'present a plan of compaction pile locations and a cross section through the different rows of piles. The cross sections show the Class II filland insitu soil interface as well as the depth the piles settled to and the driving records per foot of pile. As shown on these cross sections, the piles were driven through the insitu material as required.

I'n fact, in most cases, the pile blow counts are very high. Based on these profiles and the length of pile that was driven, we are convinced that the insitu soils were densified by displacement and compaction.

3) We have calculated the density increase in the insitu soil based on the pile displacement and an estimate of the volume of soil that followed the pile down during pile driving. From the photos of the construction operation, we have calculated the volume of a cone of depression that

Various other pro)ects have been documented in which driving of piles resulted in soil densification. Several of these are listed below:

(a) Dames & Moore Report prepared for Dairyland Power Cooperative, LaCrosse Boiling Water Reactor (March 21, 1980)

(b) "Dames & Moore Report prepaied for Dairyland Power Cooperative, LaCrosse,Boili'ng Water Reactor (July 11, 1980)

(c) Liquefaction Potential Study, South San Francisco Medical Center, San Francisco, California, for Kaiser Foundation Hospitals (Dames & Moore, August 11, 1978).

(d) Basore, C.E., and J.D. Boitano, "Sand Densification by Piles and Vibroflotation," Placement and Improvement of Soils to Support Structures, ASCE Specialty Conference'Proceedings (August 1968).

(e) Nakayama, J.,E. Ichimoto, H Kamada, S. Taguchi, "On'Stabilization Characteristics of Sand Compaction Piles," Soils and Foundations, Vol. 13, No. 3 (September 1973).

(f) Woodward-Clyde Consultants, Results and Interpreation of Pile-Driving Effects Test Program, Existi'ng Lock and Dam No. 26, Mississippi River, Alton, Illinois, "Report to U.S. Army Corps of Engineers.

(g) Endo, M., "Relation Between Design and Construction in Soil Engineering--

Deep foundations," Caissons and Pile Systems, Proceedings of Specialty Session No. 3 of 9th International Conference of Soi.l Mechanics and Foundation Engineering (1977)..

(h) Dames & Moore Report No.- 05676-008-07 for Sargent & Lundy Engineers, Bailly Nuclear Generating Station (1978)

Su~zur We are convinced that the insitu soils at the St. Lucie site are dense and provide more than an adequate safety factor against liquefaction as noted above under items 1 through 4. We believe that both construction E

techniques (dewatering and compaction piles) have densified the insitu soil to relative densities greater than 80%.

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FLORIDA POMER 6 LIGHT COMPANY St. Lucie Unit 2 NRC-FPL-Ebasco Meeting on Electrical SER Open Items October 23, 1981 Those present at the meeting wexe:

Ebasco E. Dotson* V. Nerses E. Zuchman*

J. Franklin . A. Ungaro .G. Attarian P. Carier . 0. Chopra

• part-time P

'I The purpose of this meeting was to present FPL responses to SER electrical open items:

l. 90X starting of 460VAC motors

2. Adaquacy of station voltages.

FPL and Ebasco presented draft xesponses to item 1 above and reviewed the methodology of the analysis. The NRC found the response acceptable and con-sidered the item closed pending formal submittal of the response.

FPL and Ebasco presented a draft response to .item 2 above and reviewed the methodology of the an'alysis. Following lengthy discussions several modifi-cations to the draft response were agreed upon. The NRC found the modified draft acceptable and considered the items'losed pending formal submittal of the response.

A concern wag, raised by FPL regarding the. SER description and Technical Specification requiremetns for the safety related AB bus the breakers.

,The SM requires in several places that the Technical Specifications include "the requirement that these tie breakers be locked open (except for normally closed breakers) during plant operation FPL stated that the tie breakers pre-sently have electrical interlodes and that breaker misalignment alarms are provided in the control room. The SER requirement, if interpreted as meaning pad locks on the breakers, would be detrimental to safety since an operator would be required to leave the control room during the loss of a safety train to remove" the padlocks and realign the swing (AB) bus.

To provide an added measure of security foi tie breaker operation. FPL proposed that captive key switches be provided on the RTG boards in place of the standard switches.

The NRC agreed that this would meet their concerns, eliminate the need for a Technical Specification and provide control room operability of the tie breakers. The NRC has agreed to modify the appropriate paragraph of the SER to clearly indicate the means of locking open the AB tie breakers would be via captive key switches on the RTG board and delete the Technical Specifications requirements.

FPL agreed to change the RTG board control switches for the AB bus tie breakers to capture key type.

Response to SER Open Item: Adequacy of Station Voltages t

Branch Technical Position PSB-1 requires that two levels of undervoltage protection be provided for the Class lE busses.

In accordance with PSB-1 the first level of undervoltage protection is provided to detect a loss of offsite power. One Type CV-2 inverse time voltage relay is provided for each Class 1E division and is set at time.

dial 2 which will provide undervoltage tripping in accordance with the relay characteristic curve provided in Figure 2998-PSB1-E. The tap voltage value is set at 105VAC which produces a tripping characteristic of approximately 12 seconds at 79% voltage.

Each-Class-lE- division-ie provided-with"one Class-1E relay .as described above mounted in the Cla'ss lE 4.16KV switchgear. Upon detection of a loss of voltage condition this relay automatically indicates diesel gen-erator starting and disconnection of the offsite source on a loss of offsite power.

Branch Technical Position PBB-1 requires that a second level of under voltage protection be provided for the'Class 1E busses. Plordia Power and Light meets the requirements of the position for St. Lucie Unit 2 by providing for each Class 1E division, a coincident logic protection scheme consisting of three definite time relays, ITE Type 27D or equiva-lent set at 92.5% of 4.16KV and provided with a 10 second time delay. The relay logic actuates control room annunciation to alert the operator to a degraded voltage condition and aligns the trip circuitry associated with the undervoltage logic such that subsequent occurance of a safety injection actuation signal (SIAS) will separate the Class lE system from the offsite power system automatically.

To evaluate the acceptability of the relay setting an analysis of station electric system voltages was performed under steady state conditions with the full plant running loads and minimum design main generator voltages

.supplying the on site system through the Unit Auxilia Transformers.

• 'The results of this analysis were shown on Figure'99B-PSBI-A'hich demon-strate that voltages -on Class-1E systems -at the 4.16KV level, the 480VAC level and the 120VAC level with the exception of PP247, remain above the design limits of the equipment.

The most limiting equipment was considered to be the 460VAC motors rated at 90% of nameplate operating voltages. Inspection of Figure 2998-PSBl-A reveals that in this condition, on the worst case 480VAC the operating voltage remains above 90.8% of 480VAC which corresponds to 94.7% of motor namepla'te voltage, safety above the. 90% operating limit.

The voltage level on the 4.16KV busses remains above 94.5% of 4.16KV which insures that the alarm and SIAS alignment relays described above are not picked up during this steady state operating condition.

To meet the requirement of Branch Technical Position PSB-1 section B.1.6(2) a second set of ITE-27D or equivalent definite time relays will be provided in a coincident logic arrangement for each Class 1E division. These relays will be set at 90% of 480VAC and located downstream of the 480VAC powercenter 2A5 and 2B5 reactors. The output of the relay logic will enable a CV-2 inverse time relay having a time voltage characteristic shown in Figure 2998-PSB1-E. The inverse time relay will separate the Class 1E system from the offsite source in accordance with the selected time dial setting should the operator fail to restore system voltages.

The setting of the definite time coincident logic relays at 90% of 480VAC.

insures'ositive operation within the defined region of the operating curve of the inv'erse time relay. The operating characteristic of the .inveise time relay assures that- under the worst case starting transient which is the 4.16KV condensate pump, when generator voltage is at its expected minimum or switchyard voltage:is at its..expected minimum, inadvertent relay actuation will not occur.

In can be seen from Figure 2998-PSB1-E that with a time dial setting in the range of 2 to 4 and'with tap voltage selected such that a 90% tap voltage value corresponds to 90% of 480VAC, the condensate pump starting transient which dips the 480VAC bus voltage to a minimum of 80% with a recovery to 91.7% within 6 seconds, with. generator voltage are at their .

expected minimums, will,not produce inadvertant actuation of the protection feature.

'Under steady state conditions with normal plant operating loads and with the switchyard or generator voltages at their expected minimum, 480VAC bus voltage remains above 90.6% of 480VAC which is above the setpoints of the definite time relays, preventing sperious actuation of the protection feature during steady state conditions.

Should 480VAC bus voltage decrease to 90% of 480VAC, voltage at the worst case moto'r control center will be at 90% of 460VAC or 86.2% of 480VAC.

The definite time logic relays will pick up energizing the CV-2 relay which will transfer the Class 1E busses to the Diesel Generators in approximately 20 .seconds. Should the 480VAC bus v'oltage continue to decrease the inverse time function of the relay will shorten the time to 'trip in'ccordance with the time dial setting selected..

The, relays and all associated equipment are Class 1E and will be in the Class 1E switchgear. The capability for test and calibration during power operation will be provided.

Flordia Power and Light will provide test verification of the analysis per-formed to est'ablish adequate station electric system voltages prior to fuel loading. Optimum relay setpoints will be determined and based on the test results.

The minimum acceptable operating voltage at the 120VAC level was established by equipment ratings to be 90% of 120VAC. Inspection of Figure 299B-PSBl-A reveals that for all 120VAC panels except PP247 .the operating voltage remains above the 90% limit. The unacceptably low voltage of PP247 will be corrected prior to plant operation by load redistribution or other means such .that under the defined operating conditions voltages of PP247 and all 120VAC power panels remain above 90% of 120VAC.

Analysis of station electric system voltages was also performed under steady state conditions with the full plant running load and minimum design switchyard voltage supplying the onsite system through the'gtart-u Transformers. The results'f this analysis are, shown in on Figure 2998-PSBl-B which demonstrates that, as shown in the analysis for the Unit Auxilary-Transformer-, all voltages'n. the-Class&E system. with the excep=

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tion of 120VAC panel PP247 remain above minimum acceptable- design condi-tions. Modification to panel PP247 will be made as previously committed, to insure all voltages remain above the acceptable minimum.

The worst case starting transient w'as also analyzed for .the most limiting conditons which occur on the 2A system since this is the most heavily loaded with all normal plant running loads on the busses, when the startup trans-former is supplying the 2A system and offsite switchyard voltage is at the design minimum of 230KV. The results of this analysis are provided in .

igure 2998-PSB1-C., The analysis indicates that following the starting transient, voltages on all Class lE busses remain at values above the acceptable design limits and that the voltage on the 4.16KV busses returns to above the relay setpoint of 92e5% within the timer setting of 10 seconds.

In accordance with Branch Technical Position, PSB-1, relay actuation during the worst case motor starting tr'ansient does not occur.

The 10 second time delay is based on preventing, the worst case motor starting, transient, which is the 4.16KV condensate pump which accelerates to full speed upon the minimum voltage conditions expected on the main generator or switchyard in 6 seconds, from causing sperious alarms in the control room.

.Axi'dditional analysis was performed on the onsite system to .evaluate the impact of an SIAS and resultant fast dead bus transfer when the offsite source is at the minimum design voltage conditions. The results of-::this analysis are provided in Figure 2998-PSBl-D which demonstrate that, the voltages on the 4.16KV level, 480VAC level and 120VAC level remain with acceptable design limits following the fast dead bus transfer.

I a

The relays and all associated equipment will be Class lE and will be located in the Class 1E switchgear.

'Cabability for test and calibration of the relay scheme during power operation will be provided.

The above scheme meets the requi'rements of Branch Technical Position PSB-1 section B.l.6(1).

Response to SER Open Item: 90% Motor Starting When ESF motors are sequenced onto the diesel generator the voltage at the motor terminals must be sufficient to start and accelerate the motor and driven equipment without damage to the motor or impact to the accident analysis. Motors that are supp1ied for St. Lucie 2 and that are rated 460 volts are designed as standard motors. (90% start) or specially de-signed for 75% star'ting voltage.

When the ESF motors are sequenced onto the diesel. generator three motors experience starting voltages less than their 460 volt 90% start design.

They are the Containment Fan Coolers, and the Shield Building Exhaust Fan.

The voltage of the-Containment Fan Cooler motor. experiencing the worst starting transient is 84.4% of motor nameplate voltage at, the instant that the motor is applied tothe diesel generator. This voltage recovers to 94.4% of motor nameplate voltage as the -result of the recovery of the diesel generator voltage brought about. by the voltage regulator action. The next load block to be started by the diesel generator occurs in 3 seconds sub-jecting these motors to a motor terminal voltage of approximately 87% at the instant the load block is connected which recovers as a result of the diesel generator voltage regulator action to 91.8% motor terminal voltage.

To assure that the motor has sufficient torque to accelerate the driven equipment under this type of transient, the motor manufacturer supplied speed torque curves for motor acceleration considering a constant motor terminal voltage of 80% which is bounding to the starting transient de-scribed above. This curve is shown in Figure 1. From this curve net torque (motor torque minus loading torque) was determined at 20% speed intervals and the acceleration time of the motor was calculated to be 7.6 seconds. Comparing this acceleration time to the acceleration time measured in the accident analysis, 10 seconds, indicates that the motor is accelerated in sufficient time as to not impact the accident analysis.

To assure that the motors are not damaged during this starting transient, the motor acceleration time was compared to the safe-; stall time,'of'the motor. From manufacturer's data applied, the safe. stall time at 100%

starting voltage is ll secs. (hotstart). The acceleration time of 7.6 secs. is less than 11 seconds and therefore motor damage will not occur.

It must be noted that the safe stall time of a. motor increases as a result of lower starting voltage since the inrush current is less. Therefore, by comparing the acceleration time at the lower voltage (7.6 seconds) to the safe stall time at the higher voltage (ll seconds) is very conser-vative. Actual manufacturers data for starting transients such as described above indicates that the safe stall time is increased to 15 seconds.

During the third diesel generator load block and the acceleration of the containment fan coolers, the Shield Building Exhaust Fan is started.

The voltage at its motor terminals is approximately 87% of motor nameplate voltage. Since this motor is 90% motor, the motor load was analyzed

in a similar manner as the containment fan coolers described above utilizing the same conservative constant 80% motor terminal voltage.

The speed torque curve, taken, from manufacturers data for the motor and load is shown on Figure 2. The acceleration time is calculated for this motor is 4.9 seconds. Again comparing this time to the time assumed in the accident analysis, 10 seconds, and comparing this time to the safe stall time typical for motors this size, 11 seconds; indicate that the reduced voltage starting of this motor and load does not impact the safety analysis or damage the. motor.

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1. Saturation/Subcooled Margin 'F of PSIA (subcooled or superheat)

C Inputs 'F orPSIA

2. Reactor Vessel Level Above  % height above the core and Core 'he discrete level displays Inputs oF

3. Core Exit Thermocouple oF Temperature

Question 16: Describe which parameter or parameters would need to be calculated from the sensor inputs. The description of the QSODS implies that such a calculation might or might not be required. When would it be required2 When would it not be required'esponse: The following ICC detection parameters or variables require calculation from sensor inputs:

1. Saturation or subcooled margin The maximum of the temperature inputs and the minimum of the pressure inputs are compared to the saturation temperature oi pressure to determine the temperature and pressure margin to saturation. Superheat will be calculated up'o the difference between the range of the inputs and the saturation temperature.

2. Reactor vessel level above thecore The HJTC sensor dif-ferential temperature and the unheated temperature are compared to setpoints to determine if a liquid covered or uncovered con-dition exists at each senso'r location. The corresponding level output is directly related to the number of sensors that detect liquid or an uncovered state.

3. Representative core exit" thermocouple temperature A tem-perature will be calculated to represent the number of core exit thermocouple temperatures across the core. This calcula-tion has not been determined yet.. It is anticipated to be an average calculation such as the averaging of the five highest temperatures.

Question 17: Specifically, describe the automatic on-line surveillance tests. Response: , 'he following on-line surveillance tests are performed in the QSPDS:

1. The temperature inside the QSPDS cabinet with a cooling system alarm on high temperature.

2. Power failure to the processor with alarm on failure.

3. Bad sensors and broken communication links with indication on the display.

~ 4 ~ CPU memory check and 'data communication checks with alarm and indication on the plasma display and digital panel meter on the cab'inet. (These checks are performed periodica11y.) 5.. Alalog input offset 'voltage with compensation performed automatically. - 6. Inputs out of range with alarm (see Question 14) . 7 ~ Low HJTCS differential temperature with alarm. I Question 18: Describe the manual on-line diagnostic capability and procedures. Response: The automatic on-line surveillance tests replace the need for a manual initiated on-line or off-line diagnostic test to be per-formed by the computer. A page displaying the status of the au'tomatic surveillance tests will be provided to aid operator diagnostics. 4 Additionally, the following manual test capabilities are included in the design

1. Calibration of the A/D boards (with automatic offset voltage compensation).

2. Reset of the system.

Discuss the predetermin'ed for the heated junction ther-Question 19: mocouple signals and how itsetpoint will be selected. Response: A setpoint on each of two inputs determines the presence or absence of liquid at each HJTC senor location: 1; Differential temperature between the unheated and heated HJTC junctions, and

2. Unheated HJTC junction temperature.

When either of'hese two input temperatures exceeds the setpoint for the respective input temperature, the logic indicates that the liquid level has dropped .to a level lower than the sensor location. The setpoint values are predetermined and are installed as part of the level logic software. The differential temperature setpoint is calculated (based on tests) to be low enough to obtain a good response time but high enough to assure liquid is not present. The unheated junction temperature setpoint is calculated to assure that liquid is not present at the sensor position. ATTACHMENT ."B". Draft Responses to Appendix 1.9B Section 3.1.1 Replacement 3.1.1 SATURATION MARGIN r Saturation Margin Monitoring (SMM) provides information to the reactor operator on (1) the approach to and existence of saturation and (2) . existence of core uncovery. The SMM includes inputs from RCS=cold and hot leg temperatures measured by RTDs, the temperature of the maximum of the top three Unheated Junction Thermocouples.(UHJTG),- representative core-exit temperature;- and pressurizer pressure sensors. ~In nt'Ran The UHJTC,input comes from the output of the HJTCS pro-cessing units. In summary,'he sensor inputs 'are as follows: Pressurizer Pressure e 0-3000 podia Cold Leg Temperature 0-710 F Hot Leg Temperature 0-710 F Maximum UHJTC Temperature of top three 200-2300 F sensors (from HJTC processing) Representative CET Temperature 200-2300 F

3.2 DESCRIPTION

OF ICC PROCESSING The followirig sections provide a preliminary description of the processing control and display functions associated with each of the ICC detection instru-ments in the AMS. .The sensor inputs for the ma)or ICC parameters;'satura-tion mar'gin; .reactor vessel inventory/temperature above the core, and core exit temperature are proc'essed in the two channel QSPDS and transmitted to the Safety Assessment, System for primary display and trending.

'3.2.1 SATURATION MARGIN The QSPDS processing. equipment will perform the following saturation margin

.monitoring functions:

1. Calculate the saturation margin The saturation temperature is calculated from the minimum pressure "input. The temperature subcooled or superheat margin is the difference between saturation temperature and the sensor temperature input. Three temperatures subcooled or superheat margin presentations will.be avail-able. These are as follows:

a. RCS saturation margin the temperature saturation margin based on the difference between the saturation temperature and the maximum temperature from the RTDs in the hot and cold legs.

b. Upper head saturation margin temperature saturation margin based on the difference between the saturation temperature and

,the UHJTC temperature (based on the maximum of the top three UHJTC).

c. ,CET satuiation margin temperature saturation margin based the difference between the saturation temperature and the representa-tion core exit temperature calculated from the CETs (Section 2.2.3).

2. Process sensor outputs for determination of temperature saturation margin.

3. Provide an alarm output for an annunciator when temperature saturation.

margin reaches a preslected setpoint (expected to be within O'F to 50'F subcooled) for RCS ox upper head saturation margin. CET satura-tion margin is not alarmed to avoid possible spurious alarms.

3.2.2 HEATED JUNCTION THEMOCOUPLE The QSPDS processing equipment performs the following functions for the HJTC:

1. Determine collapsed liquid level abo~e core.

The heated and unheated thermocouples in the HJTC are connected in such a way that absolute and differential temperature signals are available. This is shown in Figure 2-6. When liquid water surrounds the thermocouples, their temperature and voltage outputs are approxi-mately equal. The voltage V(ACy, on Figure 2-6 is therefore, approxi-mately zero. In the absence of liquid, the thermocouple temperatures".and output voltage become unequal, causing VpA Cq to rise. When V of the individual HJTC rises above a predetermined setpoint, liquid inventory does not exist at this HJTC po'sition.

2. Determine the maximum upper plenum/head'fluid temperature of the top three unheated thermocouples for use as an output to the SMM calcula-tion. (The temperature processing range is from 100 F to 2300 F)..

3. Process input signals to display collapsed liquid level and unheated

]unction thermocouple temperatures.

4. Provide an alarm output when any of the HJTC detects the absence of liquid level.

0

5. Provide control of heater power for proper HJTC output signal level.

Figure 2-'7 shows the design for one of the two channels which includes the heater controller power supplies.

3.2.3 CORE EXIT THERMOCOUPLE SYSTEM The QSPDS performs the following CET processing functions:

1. Process core ex'it". thermocouple inputs for display.

2. Calculate a representative core exit temperature. .Although not final-ized, this temperature will be either the maximum valid core exit temperature. or the average of the five highest valid core exit tem-peratures.

3. Provide an alarm output when temperature reaches a preselected value.

4. Process CETs for display of CET temperature and superheat.

These functions are intended to meet the design requirements of NUREG-0737, II.F.2 Attachment l.

3.3 SYSTEM DISPLAY The ICC detection instrumentation displays in both the SAS (primary displays) and the QSPDS (backup displays) have an ICC summary page as part of the core heat removal control critical function supported by more detailed display pages for each of the ICC variable categories.

The summary page will. include:

1. RCS/Upper Head saturation margin the maximum of the RCS and Upper Head saturation margin.

2. Reactor vessel level above the core.

Representative core exit temperature.

Since the SAS has more display capabilities than the QSPDS such as color-graphics, trending, and a larger format, additional information may be added and with a better presentation than is available with the QSPDS. These variables are incorporated in other SAS system displays.

Since 'the SAS receives both QSPDS channels of ICC input, the SAS displays both channels of ICC information. The QSPDS displays only one channel of ICC information for each video display unit.

Although all inputs are accessible for trending and historical recall, the SAS has a dedicated ICC trend page for RCS/upper head saturation margin, reactor vessel level, and representative core exit temperature and core exit saturation margin. These are also available as analog outputs from the QSPDS cabinet.

Each QSPDS safety grade backup display also has available the most reliable basic information'or each of the ICC instruments. These displays are human engineered to give the operator clear unambiguous indications. The backup displays are designed:

1. To give instrument, indications in the remote chance that the primary display becomes inoperable.

2. To provide confirmatory indications to the primary display.

3. To aid in surveillance tests and diagnostics.

I The following sections describe displays as presently conceived for. each of the ICC instrument systems. Both primary and backup displays are in-tended 'to be designed consistent with the criteria in II.F.2 Attachment 1 and Appendix B.

3.3.1 'ATURATION MRGIN DISPLAY The following information is presented on the primary SAS and backup (QSPDS) displays:

1. Temperature and pressure saturation margins for RCS, Upper Head, Core Exit Temperature.

2. Temperatures and pressure inputs.

3.3.2 HEATED JUNCTION THERMOCOUPLE SYSTEM DISPLAY The following infor'matron is displayed on the CFMS and QSPDS displays:

Liuqid inventory level above the fuel alignment plate derived from the eight discrete HJTC positions.

2. 8 discrete,HJTC positions indicating liquid inventory above the fuel alignment plate.

3. Inputs from the HJTCS:

a. Unheated junction temperature at the 8 positions.

b. Heated 5unction temperature at the 8 positions.

Co Differential Junc'tion temperature at the 4

8 positions.

2.3.4. CORE EXIT THERMOCOUPLE'DISPLAY The following information is displayed on the SAS display:

l. A spatially oriented core map indicating the temperature at each of the CET's.

2. A selective reading of CET temperatures.

3. The representative core exit temperature.

r The following information is displayed on the QSPDS display:

~

l. Representative core exit temperature.

2. A selective reading of the CET temperatures (two highest tempera-tures in each quadrant)

3. A listing o'f all core exit temperatures.

Replacement Section S.O SYSTEM UALIFICATION The qualification program for St. Lucie-2 ICC instrumentation will be based on the following three categories of" ICC instruments:

l. Sensor instrumentation within the pressure vessel.

2. Instrumentation components and systems which extend from the primary pressure bounda'ry up to and including the primary display isolator and including the backup dispfays.

3. Instrumentation systems which comprise the primary display'quipment.

The in-vessel sensors.repr'esent the best equipment available consistent with quali'fication'and schedular: requirements (as per NUREG-0737, Appendix 3). Design of the equipment will be consistent with current in-dustry practices in 'this area. Specifically, instrumentation will be designed such that they, meet appropriate stress criteria when subjected to normal and design basis accident loadings. Seismic qualification to safe

'hutdown conditions will verify function after being sub/ected to the seismic loadings.

The out-of-vessel instrumentation system, up to and including the primary display isolator, and the backup displays will be environmentally qualified in accordance with IEEE-323-1974. Plant-specific containment temperature and pressure design profiles will be used where appropriate in these tests.

This equipment will also be seismically qualifed according to IREE-STD-344-1975. CEN-99(S), "Seismic Qualification of NSSS Supplied Instrumentation 1

Equipment, Combustion Engineering, Inc." (August 1978) describes -the methods used to meet the criteria of this document.

FPSL is evaluating what is required to augment the out-of-vessel Class 1E instrumentation equipment qualification program to NUREG-0588. Consistent with Appendix. B of NUREG-0737, the out-of-vessel equipment under. procurement is the'best available equipment. FPL expects to complete this evaluation by the end of the first quarter. of 1982.

Revision to Section 6.2 PROTOTYPE"TESTING The Phase 3 test program will consist of high temperature and pressure test-ing of the manufactured prototype system HJTC probe assembly and processing electronics. Verification of the'HJTC system. prototype will be the'oal -of-this test program. The Phase 3 test pr'ogram is expected, to be completed.

by the end of the first Quarter of 1982.

Revision to Setion 9.0 SCHEDULE FOR .ICC INSTRUMENTATION'INSTALLATION Flordia Power and Light is actively pursuing,'rocuring and expediting equipment necessary to implement requirements for THI item II.F.2, "Instrumentation for Inadequate Core Cooling". However, this commitment is predicated upon'anufacturers and vendors meeting their scheduled delivery promisesi When firmschedules are developed FPL will inform NRC of the most probable implementation date.

APPENDIX 1.9B Section 10 Will Be Deleted

Replacement Table I.9B-2 TABLE l."9B-2 EVALUATION OF ICC DETECTION INSTRUMENTATION TO DOCUMENTATION RE UIREMENTS OF NUREG-0737 ITEM II;F.2 ITEM RESPONSE l.a. Description of the ICC Detection Instrumentation is provided in Section 3.0. The instrumentation to be added includes'.the modified SMM, the HJTC Probe Assemblies, and Improved ICI

,(CET) Detector'ssemblies.

l.b. The instrumentation described in Section 2.0'ill be the ICC detection instrumentation design for FPL.

lee ~ The planned modifications'o the existing Unit 2 instrumentation will be made prior to fuel load. Modifications include changes to the SMM, design, procurement and installation of the HJTC probe assemblies, and improved ICI Detector Assemblies (which necessitate installation of improved ICI Nozzle Flanges). The final ICC Detection Instrumentationwillbe as described in Sec-tion 3.0.

2~ The design analysis and evaluation of the ICC Detection Instru-mentation is discussed in Sections 2.0 and 4;0. and Appendix A.

'Testing is discussed in Section 6.0.

3~ ,The HJTCS has one remaining test phase. The Phase 3 test program will consist .of high temperature and pressure testing of a manufactured production prototype system HJTC probe as-sembly and processing electronics. The Phase 3 test program will be executed at the C-E test facility used for the Phase 2 test and is expected to be completed by the first quarter of 1982.

No special verification 'or exper'imental tests are planned for the hot leg and cold leg RTD sensors, the pressurizer pressure sensors, or the Type K (chromel-alumel) core exit thermocouples since they are standard high quality nuclear instruments with well known responses.

For qualification testing, all out-of-vessel sensors and equip-ment, including the QSPDS up to and including the isolation to the SAS, will be environmentally qualified to IEE Std. 323-1974 as interpreted to CENPD-255 Rev. 01, "Qualification of C-E Instru-ments", as interpreted by CENPD-182, and seismically qualified to IEEE STd. 344-1975, "Seismic Qualification of C-E Instrumen-tation Equipment",. The qualification to NUREG-0588 is being addressed by the C-E Owners'roup (See the response to item 1 in Table 3 for more information).

Table 1.9B-2 Continued Necessary augmenting of out of vessel class 1E instrumentation to NUREG-0588 requirements will be addressed by the FPL evala- 'I tion to be completed by the end of the first quarter of 1982.

C 4~ This table evaluates the ICC Detection Instrumentation's con-formance to the NUREG-0737, Item II.F.2 documentation require-ments. Table 1.9B-3 evaluated conformance to Attachement 1 of Item II.F.2 Table 1.9B-4 evaluates conformance to Appendix B of NUREG-0737.

5. The ICC detection instrumentation processingand display con-sists of two computer-systems;--the--2-redundant. channel safety grade microcomputer based QSPDS; and the SAS. The ICC inputs are acquired and processed by the safety grade QSPDS and isolated and transmitted 'to the primary display in the SAS. The QSPDS also has the seismically qualified backup displays for the ICC detection instruments. The software functions for processing are listed in Section 3.2, the functions. for display are listed in Section 3;3.

The software'for the"QSPDS is being designed consistent to the recommendations of the draft standard, IEEE std. P742/ANS 4.3.2, "Criteria for the Application of Programmable Digital Computer Systems in the Safety Systems of Nuclear Power Gener-ating Stations". This design procedure verifies and validates that the QSPDS software is properly implemented and integrated with the system hardware to meet the system's functional require-ments. This procedure is quality assured by means of the C-E QADP. Since C-E .has designed the only licensed safety grade digital computer system in the nuclear industry, C-E has the facilities and experience to design reliable computer systems.

The QSPDS hardware is designed as a redundant safety grade qualified computer'ystem which is designed to the unavail-ability goal of 0.01 with the appropriate spare parts and main-tenance support.

6. Section 9.0 discusses the schedule for installation and imple-mentation of the complete ICC Detection Instrumentation.

7~ . Guidelines for use of the ICC Detection Instrumentation are discussed in Section 7.0.

8. ~ A future amendment will discuss key operator actions in the current emergency procedures for ICC. The ammendment will be submitted prior to fuel load. Section 7.0 discusses the emer-gency procedures to be implemented, upon .incorporation of the complete ICC Detection System.

Table 1.9B-2 Continued

9. The following describes additional submittals that will be provided to support the acceptability of the final ICC Detec-tion Instrumentation.

1) Environmental and Seismic Qualification of the instru-mentation equipment. Additional evaluation to NUREG-

~

0588 will be provided by June 1982.

2) Modifications to emergency procedures (prior to fuel load) 3).- . Changes-to-Technical- Specifications -(prior-to-fuel load)

TABLE l. 9B-3 EVALUATION OF ICC DETECTION INSTRUMENTATION TO ATTACHMENT 1 of II.F.2

RESPONSE

St. Lucie 2 has 56 core exit thermocouples (CETs) distributed uniformly over the top of the core, Section 3.1.3 has a dis-cription of the CET sensors, Figure 1.9B-7 depicts the locations of the CETs.

2. The SAS meets the primary display requirements for CET tem-peratures;"-

2 ~ ao A spatial CET temperature map is available on demand.

2.b. A selective representative CET temperature will be displayed continuously on demand; Although not finalized, this tempera-ture will be either the maximum CET temperature or the average of the five, highest CET temperatures.

2sc ~ The SAS provides direct readout of CET temperature with a de-dicated display page. The line printer provides the hardcopy capability for recording CET temperatures.

2.d. The SAS has an extensive trend and historical data storage and retrieval system. The historical data storage and retrieval system functionallows all ICC inputs to be recorded, stored, and recalled. by the operator. The:operator (and other user stations) can graphically trend any CET value on the display screen. A dedicated ICC trend page which includes the representative CET temperature and representative CET saturation margin will be accessible to the users.

2 ~ ee The SAS has alarm capabilities and visually 'displayed value alarms on the system level pages.

2.f. The SAS is. an extensively human-factor designed display system which allows quick access to requested displays.

3. ICC i'nstrumentation QSPDS design incorporates a minimum of one backup display with 'the 'capability of selective reading of a minimum of 16 operable Thermocouples, 4 from each quadrant.

All CET temperatures can be displayed within 5 minutes. --

4~ The types and locations, of displays and alarms are determined for the primary display by performing a human>>factors analysis.

The'SPDS also incorporates human factors engineering. The use of these display systems will be" addressed in operating proce-dures, emergency procedures, and operator training.

5~ The ICC instrumentation was evaluated for conformance to Append&i B of NUREQ-0737 (see Table 1.9B-4).

Table 1.9B-3 Continued

6. The QSPDS channels are Class 1E, electrically independent, energized from independent station Class 1E power sources and physically separated in accordance with Regulatory Guide 1.75 "Physical Independence of Electric Systems" January 1975 (Rl) up to and including the isolation devices.

II 7~ ICC instrumentation shall be environmentally qualified pursuant to C-E owners group qualification program. The isolation de-vices in the QSPDS are accessible for maintenance following an accident.

8. Primary and backup display channels are designed to provide the highest availability possible. The QSPDS,is designed to provide 99% availability. The availability of the QSPDS will be addressed in'he'Technical Specifications.

9. The quality assurance provisions of Appendix B, Item 5,,will be applied to the ICC detection instruments as described in the Appendix B evaluation in Table 1.9B-4.

Revision to Table 1-9B-4 ITEM RESPONSE

5. 1.144 "Auditing of Quality Assurance Programs for Nuclear Power Plants!'.

6. The ICC detection instrumentation outputs are continuously avail-able on the QSPDS displays through manual callup of displays through manual callup o'f displays. Additionally, one channel of analog 'trend

.recording will continuously indicate the ICC summary variables.

- 1 7~ The ICC instrumentation is designed to .provide readout display and .trending information to 'the opeartor through the SAS and analog trend recording of the ICC summary variables.

(S'ee Section 3.3).

8. The i'nadequate,core cooling instrumentation is specifically and singularly identified so that'he. operator can easily discern their use during an accident condition.

9. Transmission of signals from instruments of associated sensors between redundant IE channels or between lE and non-1E instru-ment channels are isolated with isolation devices qualified to the provisions of Appendix B.

10. The QSPDS consists of two redundant channels to avoid inter-ruptions of display due to a single failure. If in the remote chance that one complete QSPDS channel fails, the operator has:

1) Additional channels of ICC sensor inputs for cold leg temperature, hot leg temperature, and pressuizer pres-sure on the control board separate from the QSPDS.

2) .The HJTCS -and CET have multiple sensors in each channel for the operator to correlate and check inputs.

3) The HJTCS sensor output may be tested by the 'op'erator reading the temperature of the unheated thermocouple and comparing to. other temperature indications.

4) Other variables are available to the operator on the .

Main Control Board for verifying the ICC parameter,.

F Servicing, testing and calibrating programs shall be consis-tent with operating technical specifications.

12. The ICC instrumentation, including the QSPDS, are not intended to be removed or .bypassed during operation. Administrative

~ control I

will be necessary to removepower from a channe1.

13. The system design is such as to facilitate administrative control of access to -all setpoints adjustments, calibration adjustments and test points.

t'

Revision to Table 1.9B-4 Continued

14. , The QSPDS is designed to minimize anomalous indications to the operator (see section 3.3).

15. Instrumentation is designed to facilitate replacement of com-ponents or modules. The instrumentation design 'is such that malfunctioning components can be identifed easily.

.16. The design incorporates this requirement to the extent prac-tical.

17. The design incorporates this requirement to the extent. prac-tical.

18. The system is designed to be capable of periodic testing of instrument channels.

MATRIX POHER SUPPLY ISOLATION DEVISE TESTING Isolation within the Reactor'rotective System is discussed in general within the response to NRC question 420.7. Below are excerpts from this response:

"Each matrix is powered from the diode isolated power supplies located in 'two different channels of the PPS. Each power supply has with it an isolation circuit which limits the fault to acceptable values and prevents the fault from disturbing the independent vital buses.

All isolation devices discussed above are qualified to 480V ac and 325V dc and tested to 600V ac and 400 dc. The entire system is also subjected to an EMI test in accordance with MlL-STU-461

'Electromagnetic Interference Characteristics Requirements for Equipmentr both conducted and'adiated signals using test CS01, CS02, CS06, RS07.and RS03."

The following provides further definition on the method of qualifying the RPS matrix power supply (with associated isolation networks) to the requirements of IEEE-323-1974. Aging qualification requirements are not considered in this discussion.

A. Fault Isolation uglification The maximum credibIe fault is limited to 600 VAC and 400 VDC due to the following design" separation and precaution described below:

All cables routed from the respective instrument bus to various loads classified as low level circuits and are routed in enclosed race- 're ways with one exception. This cable is a control circuit whose cable route is through the cable vault area. Both instrumentation and con-trol cables do not exceed a voltage of 480 volt.

The cable spreading area and control room do not contain high energy equipment such as high energy switchgear, transformers over 480 volts, high energy rotating equipment, or potential sources of missiles or pipe whip, and are not used for storing flammable materials.

High energy circuits are considered to be those with available

.fault'urrents in excess of the interrupting rating of the 480V motor control centers.

Circuits in the cable spreading area and control room are limited to control functions, instrument functions and those power supply circuits and facilities serving the control room and instrument systems.

D C Power supply feeders from redundant t1A, t<B, MC and HD instrument buses to the control room are installed in en-closed raceways that qualify as barriers.

The instrument power supply system equipment is designed to meet seismic and environmental qualification requirements for class IE equipment.

All cables are flame resistant and are qualified in accor-dance with IEEE Standard 383.

Different parameter signal cables are in the same wireway as as they do not belong to separate redundant channels; ong

'eparate tray and conduct systems are provided for power and control and low level instrument systems.

All cables are inspected by. site quality control to assure that they are not damaged in the process of cable pulling. The in-spection of these cables is documented and subject to random audit by quality compliance.

All electrical raceways are seismically supported.

1 t1atrix power supplies and isolation circuits are configured within the RPS as shown in Figure 1. The isolation test, will consist of the application of a 600 Vac and 400 Vdc fault in the circuit in the common and transverse modes. The basis-for -the-600 Vac'nd the 400 Vdc test voltage is as follows:

600 Vac: The highest credible AC fault voltage which could appear within the RPS is 480 Yac. This voltage is increased by lRl to 528 Vac to account for normal voltage tolerances and then again increased by 105 to 581 Vac to account for IEEE-STD-323-1974 margin. This voltage is then rounded off to 600 Vac.

400 Vdc: The highest credible DC fault voltage which could appear within the RPS is 325 Vdc. This voltage is increased by 105 to 358 Vdc to account for normal voltage tolerances and then again increased by 10K to 394 Vdc to account for IEEE-STD-323-1974 margin. This voltage is then rounded off to 400 Vdc.

1. Common trode Test The common mode test is accomplished by applying a fault to the DC side of a matrix power supply between point (G) and the power supply chassis. The fault voltage and current are monitored to define the fault characteristics.

Also, the 120 Vac line side of the power supply is monitored to document any effect as a result of application of the fault. All monitoring is by means of a light beam'ecorder. This same process is repeated for point (H) to the power supply chassis.

For the purpose of this test, it has been conservatively assumed that it is a .

fault appeared on vital bus B (points A or B to chassis ground in Figure 1) it

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would propagate through the DC power supply (PS-B) and appear at points C or D. Since PS-B is directly connected to PS-A (through CR-1 and CR-2) the fault is assumed to appear at points G of H to ground. Therefore, it is re-quired to show that when a fault'is present on the BC side of a matrix power supply it does not propagate to the 120 Vac side of the power supply, there-by affecting more than one vital bus. It should be noted that complete propagation of a fault from power supply primary to secondary is a conserva-tive fault circuit evaluation which would most likely not occur.

2. Transverse Mode Test The transverse mode test is accompl,ished by applying the fault directly to the output terminals (E and F) of the isolation circuit. This fault voltage and current are monitored to define the fault characteristics. Also, the input side (G and H) of the isolation circuit and the 120 Vac line side (J and K) of the power supply is monitored to document any effects as a result of appli-cation of the faults. All monitoring is by means of a light beam recorder-.

Similar to the common mode test, a f'ault appearing 'on vital bus B (Figure 1

.points A and B) is assumed to propagate completely to points E and F.. There-fore, it must be shown that. application of a fault to

'isoTation circuit (points E and F) does not propagate the output of the in the 120 Vac side of power supply A thereby affecting more than one vital bus. It should be noted that the isolation circuit clamps the fault voltage such that power supply damage does not occur, as discussed below:

~CT Cd 1 -TP p pplyd 1 1 p 1 tt1 d 1 d to limit or shortout a positive or negative fault. Figure 1 is a schematic of the fault clamp circuit which is connected to each matrix power supply. During. normal operation VRI is in the open circuit condition, SCR-gl is deenergized and CR4 is reverse biased.

The normal 28 Vdc output of the power supply will be seen between points E and F.

The clamp circuit operates in the following manner. On the nega-tive cycle, the fault is clamped or shorted out by CR4,.causing Fl to open. On a positive cycle,. the fault would cause VR1 to

. conduct upon reaching an amplitude to 47Y (combined 28V PS volts and 19Y fault).

With VRI conducting, SCR-gI will energize, shorting out or clamping the fault and the power supply output, causing F1 and F2 to open.

3. Acce tance'Criterion The acceptance criterion for the above tests is that upon application of the fault the input power supply voltage does not vary more than + 105 from the nominal voltage.

B. Sur e uglification A surge test will be performed on the RPS according to the guidance of IEEE Standard 472-1974, to the extent practical. The test will be performed similar to that which was performed on the ANO-2 Plant Protection System (PPS) and sub-sequently approved by the NRC..

The test involves simulating (with identical equipment) a typical RPS matrix (Figure 2) including bistable trip. units, bistable power supplies, matrix power supplies, matrix. relays, and isolation relays. Vital bus power (120 Vac) is simulated by using two power isolation transformers. A 300 Vac surge (negative peak to positive peak) will then be superimposed on one vital bus.

Thus, the test voltage from neutral to peak will be 337 volts (120 Vac + 105) x 1.414 plus the neutral to peak surge 300V/2. The surge voltage is based on a calculation performed for the ANO-2 PPS,which concluded that circuit damage or false operation would: not occur provided the peak AC voltage is maintained below 400 Vac. Since the equipment within the St. Lucie Unit 2 PPS is similar (but not identical) to the ANO-2 PPS it is assumed that calculation conclusions

're applicable to the RPS.

An ultra isolation transformer is being added to the vital, bus inverter system in order to attinuate any line surges which may pass through the inverter system.

The isolation transformer will be surge qualified in accordance with the guide-lines of IEEE standard 472-1974. This will include application of the surge to the primary winding in both the common and transverse modes. The acceptance criteria for this test is that the transformer limits this surge on the secondary to a 50 Volt pulse. Note that thredible -surge-seen-by=-the-RPS-is limited -to 50 volts. which is a factor of one third less than the surge being applied to the RPS. The transformer will also be qualified to the requirements of IEEE standard 344-1975 and IEEE standard 323-1974 (minus aging).

1. Common Mo'de Test (Figure 1)

The common mode test is accomplished by applying a surge to the AC side of the matrix power supply between point (A) and the power supply chassis. During surge application the simulated RPS circuit is operated to show proper func-tion and accuracy. Also', the 120 Vac line of the associated power supply is monitored across points (J) and (K). The same process is repeated for point (B) and the power supply chassis.

2. Transverse Mode Test (Figure 1)

The transverse mode test is accomplished by'applying a surge to the AC side of the matrix power supply between points (A) and (B). During application o'f the surge the simulated RPS circuit is operated to show proper function and accuracy. Also the 120 Vac line of the associated power supply is monitored across points (J) and (K).

3. Acce tance Criterion The acceptance= criterion for the above tests is that all circuits shall operate correctly arid within their normal accuracy requirements. + Also, the voltage ob-served at points (A) and (B) should not vary more than 105 of the nominal voltage.

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'I Clarification to Our Final'Res onse to the NRC Control Room Audit'Findin s A meeting was held at the St. Lucie Site on Friday, October 30, 1981, with Joe Joyce of the Human Factors Engineering Branch of the NRC and representa-tives of Flo'rdia Power 5 Light. Discussed were several clarifications to our final response to the NRC Control Room Audit Findings.

This letter is to document those clarifications. The page numbers and sec'-

tion numbers refer to our submittal, Florida Power 8 Light letter L-81-420, Attachment H, dated September 24, 1981.

Page 5 to 59 Add - This item will be scheduled for implemen-Section 1.12 tation prior to issuance of an operating license.

Page 8 of 59 Add - This item will be scheduled for implementa-Section 2.1 tion prior to issuance of an operating license.

Page 16 of'9 Replace first sentence with:

Section 4.lb The 2C pump is a .swing pump used while either the 2A or 2B pump is out for, maintenance.

Add the word "The" in front of the second sentence.

Page 19 of 59 After the word conventions insert "(teeth down)".

Section 4.11 Page 27 of 59 Replace the entire response with the following:

Section 5.16 A lighting color convention will be established with implementation scheduled prior to issuance of an operating license.

should be revised to read as

'he Page 30 of 59 second sentence follows:

"The following method will be..."

Replace 24.b with:

Installing filament warning circuits to ex-tend filament life.

In 24.f replace the'word "periodic" with the word "monthly".

Page 35 of 59 Replace "NUREG." with "Reg. Guide".

Section 6.12