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Steam Generator Tube Rupture Analysis for Byron & Braidwood Plants
	ML20195B781
Person / Time
Site:	Byron, Braidwood, 05000000
Issue date:	08/31/1988
From:	Ballard J, Ramsden K, Tsai R; COMMONWEALTH EDISON CO.
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ML20195B756	List: ML20195B750; ML20195B768; ML20195B781;
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{{#Wiki_filter:-- Nuclear Fuel Services i 4 i l l l l l l STEAM GENERATOR TUBE RUPTURE t ANALYSIS FOR BYRON AND BRAIDWOOD PLANTS i l l August 1988 By K.B. Ramsden J.E. Ballard 1 J.M. Freeman l R.W. Tsai l !ya"= gyg.., e m m: Commonwealth Edison Company

f i STEAM GENERATOR TUBE RUPTURE ANALYSIS FOR BYRON AND BRAIDWOOD PLANTS August 1985 By K.B. Ramsden J.E. Ballard l J.M. Freeman R.W. Tsai f { "I N /b * { Prepared by: 4 ( Reviewed by: %b__ '_ // ,[ _ _ _ /'~ Supervising Engineer Approved by: (d c O /. [hw f/fr/r/ t Nuclear Fuel Services (hpnager Date Commonweahh Edison Compa.ny 72 West Adams Stnet Chicago, Illinois 60603

Statement of Disclaimer "This document was prepared by the Nuclear Fuel Services Department for use internal to the Commonwealth Edison Company as applicable to the Byron and Braidwood Nuclear Generating Stations. This document is being made available to others upon the express understanding that neither Commonwealth Edison Company nor any of its officers, directors, agents or employees makes any war-ranty or representation or assumes any obligation, responsibility, or liability with respect to the contents of this report or its accuracy or completeness pertaining to any usage other than the originally stated purpose." I l l 11

i f Abstract This report provides the plant specific analysis as required by the NRC to resolve the steam r,enerator tube rupture (SOTR) licensing issues for the Byron /Braidwood plants. I in accordance with the NRC acceptance letter of WCAP 10698-P A and Sup. plement I to WCAP 10698 P-A, the following plant specific submittal require-ments for this report were completed: l. Licensed operators utilizing the Byron /Braidwood simulator at the CECO Production Training Center performed comparable SGTR training runs demonstrating the operator action times assumed in this report for both the i margin to overfill (MTO) and offsite dose (OD) case analyses were realistic. l The operator actions used in this study are discussed in detail in Section 2. 2. A site specl0c SGTR offsite radiation dose consequence analysis was per-formed selecting the most limiting failure consistent with WCAP 10698 P-A { Supplement I methodology. The offsite dose was calculated based on the Standard Review Plan (SRP) 15.6.3 guidelines and it was determined the offsite dose does not exceed the 10CFR 100 limits and meets the SRP 15.6.3 2 acceptance criteria. The offsite dose assessment is summarized in Appendix 1 C. 3. An evaluation of the main steam line and associated piping supports has been pcFormed and their structural adequacy under water Olled conditions should a SGTR overfill occur has been verified. This evaluation is not pro-vided as a part of this report. 4. A list of systems, components, and instrumentation which the analyses as-sume are necessary for SGTR mitigation has been compiled. This list in-cludes the safety /non safety related classincation of the equipment and the source of power for the required PORVs and control valves. The list is pre-sented in Appendix D. 5. The compatibility of the Byron /Braidwood systems with the WCAP 10698 P A bounding plant analysis has been evaluated and no major design differences affecting the MTO exist. The same limiting single failures as f identined in WCAP 10698 P A and Supplement 1 of WCAP 10698 P A were utilized in the analysis. The analytical model of the plant is described in Appendix A. I Therefore, based on the results presented in this reporc, it is concluded that the Byron /Braldivood plants demonstrate compliance with the licensing requirements established by the NRC for the mitigation of a SGTR event. ill

I Table of Contents l 1.0 INT R O D U CTI O N................................................. 1 1 2.0 OPERATOR ACTION TISIE STUDY.................................. 2-1 2.1 Oprator Action Sequence Evaluation ...................................21 4 2.2 Worst Offsite Dose Case .............................................23 .................26 2.3 hiargin To Overful Case 2.4 Sumrnary ........................................................28 l 2.5 TABLES ........................................................29 ) TABLE 2-1 : Operator Action Response Time Summary (Offsite Dose).. 2-9 l TABLE 2-2 : Operator Action Response Time Summary (Overfill Case) . 2 10 3.0 SELECTION OF Ll3f FRING CASE P ARAhlE'I ERS....................... 31 3.1 Worst Offsite Dose Case .............................................31 3.2 htargin To Overfdl Case .............................................32 3.3 Surnmary ........................................................33 3.4 TABLES ........................................................34 TABLE 31 : Assumptions and initial Conditions (Offsite Dose Case) ...34 TABLE 3 2 : Assumptions and Initial Conditions (Margin to Overfill Case) 3 6 4.0 RIXR AN AN ALYSIS RESU LTS...................................... 4-1 4.1 I n trod u ct io n...................................................... 4 1 f 4.2 Offsite Dose Case ..................................................41 4.2.1 Automatic Actions............... .............................41 4.2.2 hlajor Operator Actions.......................................... 4 3 4.2.2.1 Identification and Isolation of the Faulted Steam Generator............. 4-3 4.2.2.2 Cooldown of the RCS........................................ 4 3 4.2.2.3 Depressurize the RCS........................................ 4-3 4.2.2.4 Termination of ECCS Flow.................................... 4 3 l 4.2.3 Results .....................................................43 .... 4-4 ) 4.3 hfargin To Overful Case 4.3.1 Automatic Actions............................. ................44 4.3.2 hf aj o r O perator Actio ns.......................................... 4-4 43.2.1 Identification and Isolation of the Ruptured Steam Geneistor........... 4-4 4.3.2.2 Cooldo wn of the R CS.......................................45 4.3.2.3 Depressurization of the RCS ...................................45 4.3.2.4 Termination of ECCS Flow.................................... 4 5 4.3.3 Results ....................................................46 4.4 TABLES ........................................................47 TABLE 4-1 : Sequence of Events for SGTR (Offsite Dose Case) .......47 TABLE 4 2 : Sequence of Events for SGTR (Overfill Case)........... 4 S 4.5 FIGURES ..................................................49 FIGURE 4-1 : Pressurizer Pressure (Offsite Dose Case).............. 4 9 FIGURE 4 2 : Pressurizer Mixture Level (Offsite Dose Case) ........ 4 10 FIGURE 4 3 : Ruptured SG Pressure (Offsite Dose Case)........... 411 FIGURE 4 4 : Ruptured Tube Flow (Offsite Dose Case)............ 4-12 FIGURE 4 5 : Ruptured SG Steam Release. Rate (Offsite Dose Case).. 4 13 FIGURE 4 6 : Intact SG Steam Release Rate (Offsite Dose Case)..... 414 FIGURE 4 7 : PZR/ Ruptured SG Pressure Comparison (Offsite Dose Case) ..................................................415 FIGURE 4 8 : Ruptured SG L! quid Volume (Offsite Dose cc.sc)...... 416 t FIGURE 4 9 : Ruptured SG Water Mass (Offsite Dose Case)........ 417 iv

FIGURE 410 : Ruptured Loop RCS Temperature (Offsite Dose Case). 418 FIGURE 4-11 : Pressurizer Pressure (htargin to Overnll Case) ....... 4-19 FIGURE 412 : Pressurizer hiixture Level (htargin to Overnli Case)... 4-20 y FIGURE 4-13 : Ruptured SG Pressure (htargin to OverSil Case) ..... 4-21 FIGURE 414 : Ruptured Tube Flow (hlargin to Overfill Case)...... 4-22 l FIGURE 415 : Steam Generator Release Rate (hiargin to OverGil Case) 4-23 FIGURE 416 : PZR/ Ruptured SG Pressure Comparison (htargin to O ve r nli C a s e)............................................ 4 24 FIGURE 417 : Ruptured SG Liquid Volume (htargin to Overnll Case). 4 25 FIGURE 418 : Ruptured SG Water hiass (Margin to OverRll Case) .. 4-26 FIGURE 419 : Ruptured Loop RCS Temperature (Margin to Overnll Case) ..................................................427 FIGURE 4 20 : Intact SG Leakage Rate (Offsite Dose Case) ........ 4 28 FIGURE 4 21 : Average Flashing Fraction (Offsite Dose Case)....... 4 29 l FIGURE 4-22 : Intact SG Water Mass (Offsite Dose Case).......... 4 30 l 5.0 RESULTS AND CONCLUSIONS .....................................51

6.0 REFERENCES

...................................................61 I Appendis A. BYRON /BRAIDWOOD RETRAN 510 DEL........................ A.1 A.1 The System ......................................................A.1 A.2 R ET R A N Com puter Code........................................... A.1 A.3 RETRAN liydrodynamic Alodel ......................................A.2 l A.4 Slethodology Utilized with the RETRAN Stedel ..........................A.4 l A. 5 TA D L ES........................................................ A. 9 TABLE A-1 : Input Parameter Summary (Offsite Dose Case) .........A9 l TABLE A 2 : Input Parameter Summary (Margin to Overnll Case).... A-14 ) A.6 F I G U R ES...................................................... A 19 FIGURE A-1 : B/B RETRAN Model .........................A19 Appendit IL RUPTURED TUBE FLOW AIODEL............................. B.1 B.1 Introduction.......... ...........................................B.1 B.2 Ruptured Tube Flow Characteristics ............................B.1 B.3 Friction. Limited Equatio ns.......................................... B.! l Appendit C. OFFSITE DOSE ASSESShlENT................................ C 1 b C.1 Objective............ ...........................................C1 l C.2 Slethod And Assumptions ...........................................C.! C.3 Results....................................................... C.12 C.4 Co n clu sio ns..................................................... C.13 C.5 TABLES....................................................... C 14 ? TABLE C 1 : Preaccident lodine Spike Doses (Rem)............... C 14 I TABLE C 2 : Concurrent lodine Spike Doses (Rem) C 15 C.6 FIGURES......................................................C16 Figure C 1 : Preaccident lodine Spike Model..................... C 16 l Figure C 2 : Concurrent lodine Spike Model..................... C 17 Appendit D. LIST OF EQUIPalENT FOR SGTR SilTIGAllON .................D.I ( D.! List of Equipment for SGTR N!itigation................................. D.1 v

i f [ D. 2 TA B L ES....................................................... D.2 TABLE D 1 : List of Equipment for SGTR Mitigation ..............D2 2 TABLE D-2 : Evaluation of Primary and Secondary Valves .....D4 O 1 vi \\

) )

1.0 INTRODUCTION

Following the 1982 Ginna Steam Generator Tube Rupture (SGTR) event, the Nuclear Regulatory Commission (NRC) expressed concerns over the FSAR as-sumptions and methodology which were used for the design basis SGTR analysis. Specifically, the concern over the possibility of steam generator overfill and higher offsite dose resulted in the following issues regarding the FSAR analysis for a SGTR : 1) the operator action times for SGTR recovery,2) the qualification of f certain equipment required for SGTR recovery, and 3) the basis for the limiting single failure and plant ccaditions for the SGTR analysis. I in response, a subgroup of the Westinghouse Owners Group (WOG) was formed I to address the SGTR licensing issues on a generic basis. The subgroup program involved the development of a revised SGTR methodology. This was completed in h1 arch 1986 and resulted in the issuance of NRC-approved WCAP 10698 P-A I I and Supplement I to WCAP 10698 P A in h1 arch 1987. The NRC safety eval-untions for these two documents list the plant specific information which must be provided to resolve the SGTR licensing issues for the individual plants. This information includes an offsite dose assessment and margin to overfill evaluation i based on the revised SGTR methodology. For the purpose of this evaluation, ) hlarf,in to Overfill (h1TO) is defined as the amount of vapor volume (in cubic ) feet) remaining in the SG untilliquid would begin entering the SG cxit nozzle at the termination of the SGTR event. SG overfillis defined as the condition when liquid enters the SG cxit nozzle. An acceptable margin to overfill exists as long i f as SG overfill does not occur for the limiting case analysis. I in addition,it may be required to address the qualification of certain equipment needed for the design basis SGTR analysis. The objective of the analysis de-scribed in this report is intended to satisfy these NRC requirements for Byron 1/2 and Braidwood 1/2 for a post &ted SGTR event. Also, the analysis inputs were l selected to bound the Ryion and Braidwood (B/B) T Hot reduction plant condi-tions and the D4(Unit 1)/DS(Unit 2) steam generator dimension variations. The report is structured to document the limiting cases for the offsite dose and margin to overfill. ( Section 2 describes a detailed study of operator action times for a SGTR event, Section 3 presents a summary ofinvestigation in selecting the most limiting cases s } in terms of single failure and plant conditions. Section 4 documents the results of thermal hydraulic and offsite dose analyses. Section 5 summarizes the results and conclusions of this study. Additionally, the Byron /Braidwood RETRAN hiodel, Ruptured Tube Flow h1odel, Offsite Dose Assessment and List of Equipment for SGTR hiitigation are presented in Appendices A, B, C and D i respectively. l Page1 1 i

2.0 OPERATOR ACTION TIME STUDY l 2.1 Operator Action Sequence Evaluation The response of the operator and his ability to implement recovery actions is critical m mitigating the consequences of a SGTR event. The operator actions assumed in these two analyses are based upon the plant specific emergency pro-cedures addressing the SGTR accident. The Byron /Braidwood emergency procc-dures are based upon revision 1 of the Westinghouse Owners Group generic Emergency Response Guidelines, and are therefore consistent with the operator action assumptions in the Westinghouse WCAP 10698-P A SGTR analysis methodology. The operator action times used in this analysis are based upon the Westinghouse WCAP 10698 P-A SGTR analysis methodology, portions of the draft standard ) ANS 58.81984, and operator response times observed during initial and requal-ification operator license simulator training. The operator action times used in [ f this analysis are conservative with respect to WCAP-10698 P A and consistent i with operator simulator performance times. This evaluation categorized emergency procedure steps into two types. An "action 1 t step" is a procedural step requiring the operator to take physical action, e.g. opening a valve, or manipulating a switch. An "acknowledgement step" requires the operator to verify and/or assimilate information, but a physical action is not required, it should be noted that action and acknowledgement steps are deGned based upon the operator's decision process for the existing plant conditions. Consequently, a procedure step requiring action in one analysis scenario, may j only require acknowledgement in another scenario containing different plant l conditions. i There are Gye major recovery phases the operator must imp!cment durmg a c SGTR event to terminate the primary to secondary tube leakage. These five re-covery phases are given below and later are specifically discussed for both the h1TO and OD cases analyses.

1) Identify The Ruptured Steam Generator f

The first critical step is for the operator to identify a SGTR exists and determine which steam generator is ruptured. Onr.e the SGTR results in a reactor trip and safety injection, the operator enters the E 0 procedure to verify proper automatic system responses, assess the plant conditions, and determine the appropriate re-t covery procedure. While in the E 0 procedure, the SGTR identification can be made by several possible indications. High secondary activity on the steam jet air ejector radiation monitor or main steamline area radiation monitor outputs would positively identify a SGTR prior to the trip. hlost monitors would lose di-rect sampling capability during a Loss Of Offsite Power (LOOP), but the opera-tor could still view the main steamline area monitor outputs on an ESF display. Since the reactor trip occurs well after the event initiation, there is a definite probability the operator will identify the SGTR prior to the trip. The early [ Page 21 (

identincation would be made based upon a feedwater now reduction to the rup-tured steam generator, or a potential feedwater Dow/ steam now mismatches and/or steam generator level deviation alarms. The main identification factor for analysis purposes is the increase in the ruptured steam generator Icvel and re-covery rate compared to the intact steam generators, following the reactor trip. This is due to the ruptured SG receiving break Dow in addition to the auxilary feedwater now (AFW). The SGTR identincation directs the operator to enter the E 3 SGTR procedure where the remaining recovery actions are performed.

2) Isolate The Ruptured Steam Generator The E-3 procedure directs the operator to isolate the now from the ruptured steam generator by ensuring the h1SIV and h1SIV bypass valve are closed, tue SG power operated relief valve (PORV) is closed (if SG pressure is less than 1115 psig), and the steam generator blowdown valves are closed. After ensuring the ruptured steam generator IcVel is greater than 4% narrow range, the operator isolates the AFW flow to the ruptured steam generator by closing the associated AFW isolation valves.

The isolation of the ruptured steam generator provides ) three functions : 1) It minimizes Feedwater accumulation in the steam generator and decreases the potential for over0ll,2) It isolates the ruptured steam generator from the intact steam generators, preventing blowdown and release from the ruptured steam generator when the intact SG PORVsare used to cool the RCS,

3) It maximizes the ruptured steam generator pressure thereby reducing the amount of RCS depressurization needed to terminate the primary to secondary leakage.

3) Cool Down The Reactor Coolant System

) After ensuring the ruptured SG is properly isolated, the operator prepares to cooldown the RCS. This includes verifying the pressurizer PORVs are closed and } the intact SG narrow range levels are greater than 4%, resetting Si and contain- ) ment isolation, and stopping the Residual Heat R:moval(RHR) pumps, since the RCS pressure is greater than 300 psig. The E 3 procedure then directs the oper-( ator to initiate the RCS cooldown at the maximium rate attainab!c by opening the intact SG PORVs (since the condenser steam dumps are not available). The operator cools down the RCS until the ten highest core exit thermocouple average [ is less than the saturation temperature at the ruptured SG pressure (plus a 40 l degree conservatism). This ensures the RCS remains adequately subcooled when depressurized below the ruptured SG pressure.

4) Depressurize The Reactor Coolant System After the RCS cooldown, the operator checks the ruptured SG pressure, verifies adequate RCS subcooling, and then initiates depressurization. This is done by I

opening the pressurizer PORV since thy, normal spray is not available due to the LOOP. The operator ensures the pressurizer level remains less than 76% and the RCS subcooling is acceptable during the depressurization. The RCS depressurization increases the rate at which Si restores RCS inventory and halts Page 2 2

l ) the primary to secondary leakage when the RCS pressure drops below the rup-tured SG pressure.

5) Terminate The Safety injection Flow Unless it is terminated, the Si now would continue to pressurize the RCS until the break now reinitiates. Therefore. the E-3 procedure directs the operator to verify the RCS pressure is stab!c or mcreasing, and then terminate all SI now except for one centrifugal charging pump. The operator then establishes 70 gpm of charging now and adjusts it as necessary to maintain the pressurizer level greater than 21%.

At this poir,t, the primary to secondary leakage has been terminated, and the RCS is in a stab!c condition ready for transition to the cold shutdown condition. Since the ruptured SG level has been stabilized, and the offsite release has been terminated, both already having reached their maximum values, the remaining operator actions to place the plant in the cold shutdown condition have not been evaluated for this analysis. ) 2.2 Worst Offsite Dose Case The major sequence of operator actions for the Offsite Dose (OD) case is the same as the above summary, but there is one extra operator manipulation re-quired d[uring the isolation of the ruptured SG. The siIgle most limitin M involves . which occurs soon after ) the reactor trip. This _causes the SG to be bot 6 ruptured and faulted (ruptured / faulted). TI'is located in~ the MSIV valve room. The remaining operator actions 4,C f are identical ti) the time study. The operator actions and time response intervals for the Offsite Dose case are summarized in Table 21. The determination of these operator action time response intervals follows.

1) Identincation of the Ruptured Steam Generator The ruptured SG identincation is normally made due to a more rapidly increasing level, but this is hindered in the OD case since the stuck open SG PORV de-presses the SG level. However, there is considerable time in the OD cc.se scenario for the operator to identify the rupturedifaulted SG, prior to the reactor trip, based upon pre trip indications. These pre trip indications include feedwater

( Oow differentials between the intact and ruptured SGs or a feedwater/ steam now mismatch alarm. Main steamline area or secondary air ejector radiatica monitors would also help the the operator identify the ruptured SG carly. There is also l sufficient time, while awaithg the SG PORV isolation, for a technician to take local radiation measurements in the MSIV room. This would aid in the ruptured SG identincation. As was observed in simulator exercises, the operator has con. siderable opportunity to identify the ruptured SG prior to the reactor trip. page 2 3 3

Even if the operator has not identified the ruptured SG prior to reactor trip, the three intact SGs would notably trend levels together, esuccially after the intact SG PORVs reclose. This would identify the remaining %.'s the ruptured one. Thus, there is considerable assurance the ruptured SG is :<.mied well before the stuck open SG PORV is locally isolated, and the ruptured w requires isolation.

2) Isolation of the Ruptured Steam Generator The operator can identify the since the ruptured / faulted SG pressure decreases at a much Taster rate, dropping below the SG PORV reset value within 200 seconds. There is also positive valve po$ ion indication of the open SG PORV on the control board. As a result of the the 0,C operator would enter procedure 1BEP-2 " Faulted Steam Generator Isolation ".

This procedure directs the operator to ensure the MSlVs, the MSIV bypass valves, the SG blowdown valves, and the feedwater isolation valves are isolated for the ruptured / faulted SG. The is isolated by locally closing 0,C an isolation valve located in the CISIV valve rooni. The dispatch, travel time, and local isolation of this valve by an oaerator has conservatively been assumed { to require 20 minutes, from the time the o,c The analysis assumes the AFW isolation valves are closed when the ruptured / faulted SG narrow range level exceeds 4%. In simulator training runs t there was sufncient SG level available such that the operators isolated the AFW up to twelve minutes before the SG PORV had been isolated. However, for the OD analysis, the AFW was not isolated until the SG PORV was isolated, with a 60 second delay until AFa flow termination. Therefore, in the worst case OD scenario the ruptured / faulted SG is fully isolated 31 minutes after the SGTR event initiates. This is conservative and consistent with industry experience and observed operator response times during simulator training. Draft standard ANS 58.8 classines the SGTR with a single most limiting active failure as a Condition IV event, thus requiring a minimum assessment time of 20 minutes before operator action can be assumed. However, this is not consistent with industry experience, licensed response training, nor observed simulator op-erator performance. The classification of the SGTR as a Condition 111 event with a 10 minute assessment time is more representative of actual SGTR experience. The operator response times for identification and isolation of the ruptured / faulted SG are consistent with the 10 minute minimum assessment time.

3) Initiate RCS Cooldown The E 3 procedure directs operator preparation for RCS Cooldown by; l) Re-setting the Si signal logic,2) Resetting the containment isolation signals, and 3) stopping the RHR pumps (since RCS pressure is greater than 300 psig). The op-erator then opens the three intact SG PORVs initiating the RCS cooldown. In addition to the four steps requiring operator action, there are five procedural ac-knowledgement steps requiring operator assimilation to initiate the cooldown.

Each procedure step is assumed to require a one minute operator response time, I Page 2 4

{ conservatively establishing a total operator response interval averaged over both the required action and acknowledgement steps. A conservative nine minute op-j erator response interval hcs been assumed, from the time the ruptured / faulted l SG is isolated, until RCS Cooldown initiation. The nine minute cooldown initiation time is extremely conservative with respect to obsen'ed operator simulator performance. In the SGTR simulator runs, the twenty minutes awaiting the remote SG PORV isolation allowed the operators ample time to review the sequential procedural requirements in advance. There-fore, they took immediate and decisive action following the SG PORV isolation and initiated the RCS cooldown within one to two minutes. The ANS 58.8 draft standard specines a one minute response intenal for each required operator manipulation for the variable portion of Time Test 2. There is no 0xed operator delay time (for assessment and action identi0 cation), since the operators have ampic time to clearly delineate the plan of action prior te the SG PORV isolation. The 7 to 12 operator manipulatfors (depending on sigual actu-ations) requires a minimum operator action delay time of 7 to 12 minv.es to ini-tlate RCS cooldown. This is conservative to the simulator times oburved and consistent with the 9 minute interval assumed in the Offsite Dose anaiysis.

4) Initiate RCS Depressurization The operator initiates the RCS depressurization after assimilating three procc-dural acknovtledgement steps and completing the one action step: opening the prm trizer PORV. This operator response intervalis assumed to take 4 minutes from the time RCS cooldown is terminated. Operator simulator performance duivs the RCS depressurization can be injiated within 1 minute, while the mstiy. house WCAP 10698 P A assumes a minute operator response time. Q,C This demonstrates the conservatism of the fininute operator depressurization time used in the analysis.

The ANS 58.8 guidelines stipulate a minimum 1 minute operator action time de-lay to perform the une required manipulation; opening the pressurizer PORV. The 4 minute operator response interval assumed in the analysis is therefore, conservative with Npect to ANS 53.8.

5) ECCS Dow termination After evaluating 2 acknow!cdgemant steps, the E 3 procedure directs the operator to perform one action step; terminating ECCS Gow (stopping the appropriate ECCS pumps). A 3 minute oWrator response interval is thus assumed prior to ECCS Dow termination, During operator simulator training, the ECCS Cow was halted within 1 to 2 i

minutes after depressurization. The Westiq; house WCAP 10698 P A methodol-minute after depressurization. The 3 0,C ogy assumed ECCS Dow was terminated [brvative with respect to these values. minute interval used in the analysis is cons ANS 58.8 requires a 3 to 4 minute operator manipulation delay, depending on the number of ECCS pumps which must be : topped. With no 0xed assessment time, Page 2 5

) ) the total ECCS termination operator action time delay is 3 4 minutes, which is consistent with the interval used in the analysis. 2.3 Margin To Ove> fill Case The operator action sequence for the h1TO case follows the five major setions identiDed.in the Section 2.1. The single most limiting failure of a f does not necessitate any additional operator actions for transient miti- 0% gation. The failure only reduces the rate at which the RCS cooldown can I e per-formed. ) The h1TO case requires a more detailed evaluation of operator actions for the ECCS termination (action 5) since the E 3 procedure termination step actually requires one atrifugal charging pump rernain running. Consequently, the po-tential for overfill is not terminated until further operator actions are taken, climinating all RCS injection flow and equalizing the RCS and ruptured SG l pressures. The operator action response time intervals for the h!TO case analysi; ) are listed in Table 2 2 and are summarized below. 7

1) Identification of the Ruptured Steam Generator

) The N1TO case analysis assumes the operator identifies the ruptured SG after the reactor trip, when the break flow generates a more rapid recovery in SG level. At the time the ruptured SG was assumed identified isolated, the level was over I 15% greater than the other intact SGs. This verifies a sufficient SG level differ-ential existed for the operator to identify and isolate the ruptured SG as assumed. As in the OD case, ther9 is ample time prior to the rea: tor trip (399 seconds), that the operator can often identify the SGTR transient early as was observed in simulator training runs. Feedwater flow differentials or feedflow/steamflow mis-matches, plus the early occurrence of main steamline area radiation monitor or condenser air ejector radiation monitor alarms help the operator idatify the i SGTR prior to the reactor trip. I

2) Isolation of the Ruptured Steam Generator The h1TO case analysis assumes tiie operator isolates the ruptured SG within 16 minutes into the SGTR transient, which is $69.8 seconds after the reactor trip occurs. The 16 minute isolation time is consistent with opsttor training per-formance and is extremely conservative with respect to the minute isolation 0,C

~" time assumed in the Westinghouse WCAP 10698 analysis. f The hlTO case isolation time is based upon a conservatively adequate time in-terval for the operator to complete the required procedural steps, following the reactor trip. However, it is also based on an identifiable difference existing be-tween the intact and ruptured SG levels at the time ofisolation. At the 16 minute isolation time, the ruptured SG level exceeds the intact SG levels by 15% narrow ( range. Therefore, when comparisons of other hlTO cases having different reactor I trip times were made to determine the most limiting h!TO case, the assumed op. Page 2 6

crator isolation time was based on a minimum interval of 600 seconds after the i reactor trip, and a minimum level difference of 15% narrow range between the intact and ruptured SGs.

3) Initiate RCS Cooldown The E-3 procedure steps required to initiate RCS cooldown are the same as in the the OD case, so the 9 mir.ute operator response interval applies for the MTO case i

also. The limiting failure of a PORV on an intact SG does not affect the operator response time. The operator will still attempt to open all three intact SG PORVs for the cooldown, but will proceed with only two. )

4) Initiate RCS Depressurization The operator initla'cs the RCS depressurization for the MTO case with the same procedure steps and 4 minute operator response interval as the OD case.

5) ECCS Flow Terminution j

The operator completes the E-3 procedure ECCS termination step within 3 min- ) utes as assumed in the OD cae. However, as stated earlier, the one centrifugal charging pump remains running. This provides enough now to repressurize the RCS, and the operator would proceed with the E 3 procedure, terminating all RCS injection now to ensure SG overnll does not occur. The next procedure step the operator performs is to establish a 70 gpm charging now from the charging pump. This one action step requires a 1 minute operator f response time interval for completion. The operator then performs 3 acknowl:dgem:at steps and one :' inn steo to e<- tablish RCS letdown. It has been assumed the operator establishes a normallet-down flow equal to the charging Dow, thus creating a zero net injection now into the RCS. This is a conservative assumpuon, since the E 3 procedure allows the operator to manipulate charging and letdown as necessary, to minimize the po-tential for SG over0ll. Therefore, the operator could actually decrease the charg-ing now rate to less than the letdown rate. A 4 minute operator response time interval has been assumed for the net RCS injection now reduction to zero. If the RCS pressure has not yet equalized with the ruptured SG pressure, the operator proceeds through another acknowledgement step and one more action step. The analysis assumes this last action is to brie 0y open the Pressurizer PORY until the RCS pressure has dropped below the S0 pressure. A 2 minute operator response time interval is assumed until the PORV is opened. After the PORY recloses, this represents the termination of the MTO case, since the pisnt s as been placed in a stable condition where additional break now into the ruptured SG can be prevented. Page 2 7

~ 2.4 Summary In summary, the operator actions and the assuraed operator response time inter-vals, for the OD and MTO SGTR analyses, are based upon the specific EOP procedures used by the B/B operators and are representative of observed operator training performance. The operator response time intervals are also consistent with the g':idelines outlined in draft standard ANS 58.8 and are conservative with respect to the operator action times used in the NRC approved Westing-house (WCAP 10698) SGTR analysis. ) l ( i I Page 2 S

2.5 TABLES TABLE 21 Operator Action Response Time Summary (Offsite Dose Case) Operator Aution Rcsponse Delay Time Interval Time to Complete Identification 20 Minutes After ) and Isolation of the Ruptured / SG PORY Opens Faulted SG Initiate RCS Cooldown 9 Minutes After SG PORV on Ruptured / Faulted SG is Isolated i f Initiate RCS Depressurization 4 Minutes Terminate ECCS Flow 3 Minutes L l f i I I l Page 2 9

TABLE 2 2 Operator Action Response Time Summary (Overfill Case) Operator Action Responso Delay Time Interval Time to Complete Iuentification 16 Minutes and Isolation of the Ruptured SG ) Initiate RCS Cooldown 9 Minutes t ) Initiate RCS Depressurization 4 Minutes Terminate ECCS Flow 3 Minutes (except 1 cent. charging pump) ) Establish 70 GPM Charging Flow 1 Minute Establish RCS Letdown 4 Minutes Reopen Pressurizer PORV 2 Minutes l i Page 210 I

3.0 SELECTION OF LIMITING CASE PARAMETERS This section discusses the assumptions utilized in input selection for the two cases (hlaximum Offsite Dose and hiinimum hlargin to Overnil) presented in Section

2. A detailed description of the analytical modelis provided in Appendix A.

3.1 Worst Offsite Dose Case i Selecion of the Worst Single Active Failure The limiting single failure for this case is a failure of the[

Q,C

) Results of the Sensitivity Studies l A series of sensitivity studies were performed to evaluate the impact of input pa-rameter variation on the offsite dose and also to aid in selecting conservative in-put parameters for the worst offsite dose case. The calculated RCS mass released ) from the ruptured / faulted SG was used tc determine the relative offsite dose im- ) pact as the input parameters were evaluated within their expected ranges of var-iation. ) The input parameters evaluated included RCS initial temperature, core decay heat, RCS totalinitial mass, ECCS injection flow rate, and AFW Gow rate. The only two parameters which produceo a significantly measurable change in the RCS mass released were the RCS initial temperature and the core decay heat. A reduced RCS initial temperature or an increase in core decay heat, both resulted in increased RCS mass released. Sensitivity studies were also performed on the assumed operator action response times. Altering those operator actions performed after the ruptured / faulted SG isolation had a neglible effect on the RCS mass released. However, the operator action times fo:.the isolation of AFW to the ruptured / faulted SG and the local isolation of the both directly affected the calculated RCS 3,C mass released. The latter action time exhibited the dominant parameter sensitivity for 'he offsite dose case. An early isolation of AFW would actual _ly cause a slight increat in RCS mass released, while a delay in isolating the signincantly increased the RCS mass released. These sensitivity studies 0,C validated the detailed evaluation of operator action response times performed in Section 2, thus ensuring conservative operator mitigation capabilities assumed during the transient analysis. Page 31

A review of the sensitivity study results determined that the base case model used in the offsite dose analysis conservatively bounded the effects on RCS mass re-leased due to input parameter variations. Discussion of hiodel input Assumptions The model employed to predict the offsite dose case was adjusted to conservatively bound plant differences, as weil as new operating strategies ( T. Hot reduction) currently under consideration. Differences which were signincant l for SGTR analysis exist only in the steam generators. Unit 1 of both stations utilize Westinghouse D4 steam generators, and Unit 2 of both stations are Otted with D5 steam generators. The primary differences between these steam genera-tors are the number, location, and design of the steam separators; level instru-I mentation, recirculation ratio, corrosion resistant materials, and steam dryer drainpipe details. Adjustments in the model bound all the differences between all four units. The T Hot reduction program is intended to reduce the inlet tem-perature to the steam generators,in order to reduce the corrosion rate of the U-tubes. This has the net effect of reducing the secondary side mass release and is j not assumed in this calculation. hlaximizing the predicted offsite dose requires assumptions that result in increasing the quantity of steam released through the l ruptured / faulted SG PORV. A listing of the assumptions used in the Offsite Dose ) Cm and their bases appears in Table 31. ) 3.2 Margin To Overfill Case ) Selection of the Worst Single Active Failure A review of V' CAP 10698 identified the worst single active failures in the generic analysis to be. o,c ] These single failures were investigated, and the "was determined to be the limiting [ failure with respect to margin to overnil. O,C Results of the Sensitivity Studies As in the previous case, a series of sensitivity studies were performed to evaluate s the effect on the margin to overnll due to input parameter variation and also to aid in the selection of limiting parameters for the margin to overfill case. The generic sensitivity studies of Reference I were reviewed and an additional step was added in this analysis. Since several assumed single failures resulted in rela-tively close overfill margins, the sensitivity studies were performed in conjunction with the different assumed failures. This ensured that the selected limiting failure remained consistently the most limiting, after the selection of the limiting input parameters was made. The parameters evaluated in the sensitivity studies included the RCS initial tem-perature, core decay heat, ECCS injection flow rate, the SG PORY lift setpoint. reactor trip time, main feedwater isolation time, and AFW initiation times. Of Page 3 2

these parameters, the RCS initial temperature produced the most pronounced effect, with the reduction of initial temperature yielding approximately a 450 cu. bic feet reduction in the margin to over0ll. Increasing '.he core decay heat was found to nominally increase the marg!D to over0ll for the while Q,C slightly decreasing the margin for the[ie failure was determine'a to be the failure] failu ~ result of these studies, the limiting sing ofa The limiting input parameters selected are presented o,c in Table 3 2. Operator action times were also incorporated into the margin to over0ll sensitiv-ity studies. Additional time isolating AFW to the rupured steam generator re-sulted in reducing the margin to overfill at a rate of approximately 2.8 cubic feet per second of additional delay. Actions following AFW isolation, such as initi-ation of cooldown, initiation of depressurization, and termination of safety in-jection now result in a margin to over0ll reduction at a rate of approximately 1.0 cubic feet per second of additional delay. It was for this reason that much effort was expended to arrive at a conservative AFW isolation time, cooldown initiation time, depressurization initiation time, and termination of ECCS Gow time as dis-cussed in section 2.4. Discursion of h!odel input Assumptions The model employed to predict the margin to over0ll case was adjusted to conservatively bound plant differences as well as new operat ng strategies ( T-Hot i reduction) currently under consideration. Since the RETRAN model utilizes a single volume steam generator modelin the ruptured loop, the D5 steam genera-tor parameters were chosen to be the most limiting because of the higher recir-culation ratio and consequently greater initial mass. The T-Hot reduction program was assumed as input for this analysis, since it yielded a slight margin reduction. htinimizing the margin to over0ll requires assumptions that result in n' creasing the quantity of water (primary and secondary) deposited in the rup-turvi steam generator. A listing of the assumptions used in the hlargin to Overfill I I Case t.nd their bases appears in Table 3-2. l 3.3 Summary Limiting single active failures were cho.sen to be a failed 'l 0 C for the Offsite Dose Case and a failed for the hlargin td a,,c ~ Overfill Case. Limiting initial conditiJns and assumptions we e chosen to maxi- ) ) mize offsite dose and minimize margin to over0ll. plant differences and proposed changes in operating strategy have been considered and conservatively bounded i l to cover the range of possible plant operations, l f l Page 3-3 i

3.4 TABLES TABLE 3-1 Assumptions and initial Conditions (Offsite Dose Case) I I PARAMETER l VALUE l BASIS I I NSSS Power 3411 Mw FSAR Nominal RCS Flow Improved Thermal Nominal Design 145.1x10**5 (lbm/hr) RCS Pressure 2235 psig Nominal RCS Tavg 588.4 degrees F Nominal RCS Initial Water Mass 494,606 lbe Nominal SG Initial Mass (level) 96,445 lbm Maximizes Concentration of Primary Coolant in SG and Radionuclide Release Rate Pressurizer Presst;s Control No Heaters or Heaters Have no Effect on Sprays Concentration of Primary Coolant in SG Maximizes Primary to Break Location a>c Secondary Leakage Shortestiube l Break Flow Model Darcy Frictional Maximizes Primary to Flow (not critical Secondary Leakage flow limited) f Initial Leakage 1.0 GPM Tech Spec Maximizes Primary to Max (per Intact SG) Secondary Leakage l Reactor Trip Setpoint 1845 psig Lo Pres-Maximizes Concentration of I suriser Pressure Primary Coolant in SG and (no OTDT credit) Radionuclide Release Rate j Page 3 4 l

T/ BLE 31 (Cont.) Assumptions and initial Conditions (Offsite Dose Case) I i PARAMETER l VALUE l BASIS I I Cffsite Power Availebility Loss of Offsite Maximizes RCS Preesure after Power Coincident Trip Since Pressurizer with Reactor Trip Sprays and Steam Dumps are Unavailable Which Maximizes Break Flow and Radionuclide Releases ~ O'C Single Failure Single failure to Maximize Offsite dose i Decay Heat 1.2 X ANS (Equiv) Increases Steam Released from l Ruptured SG and Results in l Larger Offsite Doses AW Flow (Ruptured SG) 240 GPM Minimizes the Dilution of i (constant) Primary Coolant in the SG by AW which Maximizes the Radionuclide Release Rate ( ) A N Flow (Intact SC) 3 x 240 GPM Minimizes the Cooling of RCS Maximizing the Has ; Load in the Ruptured SG and Radionuclide Release .., O S AN Initiation Delay seconds Minimizes the Cooling of RCS Maximizing the Heat ~~ Load in the Ruptured SG and Radionuclide Release SG Initial Pressure 985.3 psig Nominal I Intact SG PORV Lift Setpoint 1115 psig (Linear Nominal to Tull Open) SG PORY Full Open Setpoint 1175 psig Nominal Safety Injection Capacity 2.0 x T.S. Min Cap. Maximizes RCS pressure for Dual ECCS which Increases Break Flow Trains and Radionuclide Release Page 3-5

TABLE 3-2 Assumptions and initL1 Conditions (Margin To Overfill Case) l I PARAM3TER l VALUE l BASIS l I NSSS Power 3425 Mw T-Hot Reduction Nominal RCS Flow Improved Thermal Nominal Design 145,1x10**5 (1bm/hr) a'c .0C RCS Pressure pslg THotReducedBasedonResubt RCS Tavg 569.1 degrees F of Sensitivity Studies. This Increases Break Flow Slight-ly but Also Decreases Trip j Time After The Break l l RCS Initial Water Mass 510,407 lbm Nominal Value For Use With T-Hot Reduction Program i (600F). RCS Initial Mass Has Negligible Effect on Margin to Overfill Case ( SG Initial Mass (level) 132.250 lbm Maximizes Initial Volume in Ruptured SG Which Decreases Margin to Overfill i Pressurizer Pressure Control No Heaters or Without Heaters, Reactor g Sprays Trip Occurs Sooner Causing AIV Filling to Begin Sooner Decreasing the Margin to Overfill f Break Location Maximizes Primary to 0:0 Secondary Leakage Decreasing Shortest Tube Margin to Overfill Break Flow Model Darcy Frictional Maximizes Primary to Flow (not critical Secondary Leakage Decreasing flow limited) Margin to Overfill Initial Leakage 1.0 GPM Tech Spec Nominal - Has no Effect on Max (per Intact SG) Margin to Overfill Page 3 6

TA 3LE 3 2 (Cont.) Assumptions and initial Conditions (Margin To OverDil Case) 1 I PARAMETER VALUE l BASIS i Reactor Trip Setpoint 1915 psis Lo Pres-Nominal + 30 psi Setpoint surizer Pressure Results in Earlier Reactor (No OTDT Credit) Trip Causing AW Filling to Begin Sooner Decreasing Margin to Overfill Offsite Power Availability Loss of Offsite Maximizes RCS Pressure after Power Coincident Trip Since Pressurizer with Reactor Trip Sprays and Steam Dumps are Unavailable Which Maximizes Break Flow and Decreases Margin to Overfill Single Failure Failed Closed Single failure to Minimize Intact SG PORY Margin to Overfill Decay Heat 0.95 X ANS (Equiv) Decreases Steam Generator Pressure After Trip Which i l Naximizes Break Flow and Reduces Steam Released from l j Ruptured SG and Results in Decreased Margin to Overfill j K ~. I AW Flow (Ruptured SG) 445 GPM (constant) f 1 ~ ~ AW Flow (Intact SG) 3 x 445 GPM Nominal - to be Consistent With Ruptured SG A W F1t.v Rate 1 _ac .. a,C. AW Initiation Delay seconds AW Temperature 42 degrees F (h=10 btu /lbm) l Page 3 7

TABLE 3 2 (Cont.) Assumptions and initial Conditions (Margin To Overfill Case) I I PARAMETER l VAINE l BASIS I I SG Initial Pressure 812.0 psig Nominal - for T-Hot = 600 F Tavg Reduced Based on Result of Sensitivity Studies. This Increases Break Flow Slight-ly but Also Decreases Mass Released From the SG PORV Decreasing the Margin to Overfill l l SG PORV Lift Setpoint 1115 psig (Lin9ar Nominal l to Full Open) l l SG PORV Full Open Setpoint 1175 psig Nominal Safety Injection Capacity 1.2 x T.S. Min Cap. Increases RCS Pressure for Dual ECCS Which Increases Break Flow Trains Decreasing Margin to Overfill j l l l f 1 l l l l l l i l \\ Page 3 S E

4.0 RETRAN ANALYSIS RESULTS 4.1 IntrodHClion The RETRAN analyses for the Offsite Dose and Margin to Over0ll cases were performed utilizing the most limiting plant parameters and the most limiting sin-gle active failures as identined in Section 3. The RETRAN analyses modeled the required operator actions and response delay times as developed in Section 2 for I i the mitigation of the SGTR transient cases, The following analysis assumptions were made for both the Offsite Dose and j l Margin to Overn!! transient cases, Loss of Offsite Power (LOOP) is assumed to occur concurrent with the re-a actor trip. There is no credit taken for the Chemical and Volume Control system charging or letdown now during normal operating conditions prior to the reactor trip. Prior to the reactor trip, the SG level control system automatically reduces = the feedwater now to the ruptured SG. Consequently, the feedwater now plus the RCS break Dow matches the steam Dow, and the SG water level remains essentially constant. The operator throttles the AFW Cow to the intact SGs as necessary to maintain the narrow range levelindication between 4% and 50% through-t out the transient. L During the RCS depressurization, the operator ensures the pressurizer level = stays between 4% and 76% per the E 3 procedure. The key parameter results of the RETRAN analyses are presented in Figures 41 thru 410 and 4 20 thru 4 22 for the offsite dose case and 411 thru 419 for the margin to overfill case. 4.2 Offsite Dose Case l 4.2.1 Automatic Actions f The tube rupture occurs at time t = 0 seconds, and reactor coolant immediately begins Dowing from the primary system into the secondary side of the ruptured steam generator, due to the RCS pressure (Figure 41) being greater than the SG I l pressure (Figure 4 3). As the RCS loses mass inventory, the pressurizer !cvel de-creases as shown in Figure 4 2, and the RCS pressure also decreases due to the expanding steam bubble in the pressurizer. The RCS pressure continues to de-crease, and a reactor trip occurs on low pressurizer pressure at 599 seconds into Page 4-1

the transient. The reactor trip signal results in the turbine stop valves isolating steam now to the turbine. The LOOP occurs coincident with the reactor trip, causing the RCPs to trip ar.d the main condenser to become unavailable. The normal feedwater Dow to the SGs is also terminated as a result of the LOOP. After the reactor trips, the core power quickly decreases to decay heat levels. However, since the steam dump system cannot be used to dissipate the core decay heat due to the unavailable condenser, the secondary pressure increases (Figt!re 4-3) until the SG PO_RV setpoint is reached. The PORV on the ruptured SG opens at 606 seconds,

4C The RCS pressure continues decreasing, and a low pressurizer pressure Safety injection (SI) signal is generated at 607 seconds. The SI signal automatically starts the AFW pumps, and there is a 61 second delay until the AFW flow begins entering the SGs at 668 seconds. The RCS break flow (Figure 4 4) steadily de-creases from time zero as the RCS pressure drops, and it reduces substantially following the reactor trip as the pressure increases in the ruptured SG secondary side thereby reducing the primary to secondary pressure differential. The RCS pressure drops to a low of about 1715 psig soon after the Safety injection, it then l

begins increasing again, as the ECCS injection now exceeds the RCS break now l restoring RCS mass inventory. l The RCS temperature drops after the reactor trip, and especially when the SG PORVs open, threby drawing,off the core decay het. The RCS temperature continues to decrease due to the transferring heat, and the G '- injection of cooler ECCS Gow. Consequently, the ruptured / faulted RCS loop temperature decreases at a faster rate than the intact loops. With the RCPs tripped, the reactor coolant system evolves into the natural circulation cooling mode. The temperature and pressure in the SGs rise quickly after the reactor trip, and then quickly reduce when the SG PORVs open relieving the secondary pressure. The SG temperature and pressure continue to drop due to the injection of the The ruotured fa alted SG tempefature and much cooler AFW into the SGs. f pressure decrease much rrore rapidly than..te intact SGs, due to the AC continuing to exhaust heat and mass (Fig,ure 4 5). The intact SG water levefs begin increas Sg soon after the SG PORVs ceclose due to the incom-ing AFW Gow. The rugured, faulted SG water level c7ntinues decreasing, as secondary mass exits the until about 950 seconds. At this time, AC. the PORY pressure drivn Cow has been reduced by the dropping SG pressure, until it matches the inconing combination of RCS break now and AFW flow. By this time, the rupturedifaulted SG narrow range level indication is off scale low. The ruptured faulted SG begins recovering level at about 1200 seconds, as the continuing decrease in SG pressure reduces the SG PORV exhaust now below the incoming break and AFW flows. Page 4 2

i i t 4.2.2 Major Operator Actions The RETRAN Offsite Dose case analysis models the operator actions and re-sponse times as identiDed in Section 2.2 and the results are summarized below. 4.2.2.1 Identopcation and holation of the Faulted Steam Generator o,c The ruptured SG is isolated when the Isolation valve is locally closed at 1816 seconds, or twenty minutes after the SG PORV Grst opened. The i operator then allows the SG water level to recover sufficiently before isolating the AFW approximately one minute later at 1867 seconds. l 4.2.2.2 Cooldown of the RCS After the 1.ichtlon of the ruptured / faulted SG, there is a 9 minute operator action response time delay, and the RCS cooldown is initiated at 2356 seconds by i opening the intact SG PORVs (Figure 4 6). The operator continues the cooldown until the RCS temperature is subcooled below the saturation temperature at the ruptured SG pressure. There is also a slight reduction in RCS pressure during the 4 cooldown due to the shrinkage of the RCS mass inventory. The RCS cooldown l 1s then terminated at 2994 seconds by closing the intact SG PORVs. l 4.2.2.3 Depressuri:e the RCS i l A 3 minute operator action response time delay is then imposed until the operator f initiates the RCS depressurization by opening the pressurizer PORV at 3234 i seconds. The operator maintains the pressurizer PORV open until the RCS i pressure decreases below the pressure in the ruptured SG. At this time, there is i actually a brief reversal of flow from the ruptured SG into the RCS. The [ pressurizer PORV is reclosed and the depressurizadon terminated at 3411 sec-i onds. l \\ 4.2.2.4 Termination of ECCS Flow As the ECCS Dow begins repressurizing the RCS, there is a 3 minute operator i response delay time, and the ECCS Dow is terminated at 3591 seconds, f a 4.2.3 Results f The time Sequence of Events for the Offsite Dose case is shown in Table 41. The release of offsite dose activity occurs only during the r'. lease of steam thrqugh 3>e the igtact SG PORVs, and mainly when the SG PORY an the ruptured SG The offsite doses for this case have been calculated utilizing the moderde-scribDd in Apppendix C in accordance with Standard Review Plan NUREG 0800. The results are given in Tables C 1 and C-2. The offsite doses are t seen to be 5vell below the 10 CFR 100 established limits and the SRP 15.6.3 ac. l ceptance criteria. Page 4 3 f i

4.3 Margin To Overfill Case 4.3.1 Automatic Actions The initial sequence for the M10 case is similar to the OD case, as the tube rupture occurs at time t = 0, and the primary to secoi.dary break Dow initiates. 4 However, the selection of the most limiting plant paramsters for the MTO case discussed in Section 3 was made to generate the reactor trip onservatively earlier in the transient. The reduced T Hot causes a higher initial bri..'k now due to the 'l Increased RCS Ould density at the tube rupture site, and the RCS pressure and pressurizer level ( shown in Figures 411 and 412 respectively ) decrease much more rapidly than in the OD case. This, coupled with a higher pressurizer low pressure trip setpoint, results in the reactor trip occurring much earlier at 393 seconds. The reactor trip signal results in the turbine stop valves isolating steam Oow to the turbine. Again, the loss of offsite sower occurs coincident with the reactor trip, resultirg i in the RCPs tripping, anc the condenser becoming unavailable. The LOOP also [ results in termination of the normal feedwater now to the steam generators. After the trip, the core powe r quickly decreases to decay heat levels. The sec- ) ondary pressure in the SGs it crease, but due to a reduced ANS decay heat curve and a higher SG PORV press are setpoint, the SG pressure (Figure 4-13) increase i does not cause the SG PORVs to open. This conservatively climinates any l blowdown of the ruptured SG vater mass and maximizes the potential for over-l fill, as the ruptured SG water Icel (Figure 418) begins increasing immediately [ after the reactor trip. The RCS pressure continues decreasing and initiates a Safety injection on low I pressurizer pressure at 399 seconds. The AFW pumps automatically start en the Si signal, and the AFW Cow immediately begins entering the SGs at 400.1 sec-l onds. The RCS break now shown in Figure 414 steadily decreases as the RCS pressure drops. The RCS break Dow then stabilizes soon after the reactor trip as the rup- [ tured SG pressure decreases at about the same rate as the RCS pressure. Though the ECCS injection now exceeds the break dow, the RCS pressure actually con-I tinues to fall due to the RCS mass inventory shrinkage. This is caused by primary heat removal as the cooler AFW lowers the SG temperatures and also due to the cooler ECCS injection now. i 4.3.2 Major Operator Actions f P 4.3.2.1 Identification and Isolation of the Ruptured Steam Generator l t The operator identtila ed isolates the ruptured SG within 16 minutes into the transient or at t = 960 seconds. at this time, the ruptured SG narrow range level l is over 19% greater than the intact SG levels. After isolation, the RCS pressure Page 4 4 I

and pressurizer level begin to quickly recover. This is due to the SGs increasing temperature (upon isolating AFW to the ruptured SG and throttling AFW Dow to maintain the intact SG levels), and the steady increase in RCS mass inventory from the ECCS injection Gow. The ruptured SG water level (Figure 417) con-tinues increasing afte isolation due to break flow, though at a reduced rate. 4.3.2.2 Cooldown of the RCS The operator then requires 9 minutes to initiate the RCS cooldown by opening the 1 tact SG PORVs at 1500 seconds (Figure 412). At this time, one of the in-1 tact With the reduced cooldown rate, the operator ful-fills tie E 3 procedure RCf subcooling requirements and terminates the RCS cooldown at 2605 seconds. 4.3.2.3 Depressuri:ation of the RCS A 3 minute delay is imposed for the operator to initiate the RCS depressurization by opening the pressurizer PORV at 2845 seconds. Since the PORY does not open, the ruptured SG pressure is greater, and the RCS depressurization requires less time for the h1TO case. The pressurizer PORV is reclosed at 2948 seconds. 4.3.2.4 Termination of ECCS Flow Three minutes after termination of the RCS depressurization at 3128 seconds, the operator halts the majority of ECCS injection now by stopping all ECCS pumps except one centrifugal charging pump per the E 3 procedure. Since the single l charging pump flow exceeds the RCS break Dow, the RCS pressure continues to increase, though at a reduced rate. The operator requires one minute to establish a normal charging Dow of 70 gpm at 3188 seconds. With the charging now reduced below the RCS break Dow rate, the RCS pressure levels stabilizes and then slowly begins decreasing. After an-other operator response delay time of 4 minutes, the operator establishes an RCS !ctdown now equal to the 70 gpm charging now at 3428 seconds. This results in a zero net injection Dow, and the RCS begins steadily decreasing due to the RCS i break Dow. As the operator proceeds through the E 3 procedure aware of the potential SG overfill cone.rn, the RCS pressure has not yet equalized with the ruptured SG. After a 2 minute operator response delay, the operator brieGy reopens the pressurizer PORY at 3548 seconds. This quickly equalizes the RCS and ruptured j SG pressures and terminates the break Dow. This accomplished, the pressurizer i PORY is reclosed at 3576 seconds, and the SGTR htargin to Overull transient is considered terminated. Page 4 5

4.3.3 Results The Sequence of Events for the margin to overfill case is shown in Table 4 2. At the time the SGTR transient is terminated, the ruptured SG contains 125.3 cubic feet of gas volu.me (Figure 4-17) as the margin to overfill. This conclusively demonstrates that etilizing the most limiting plant parameters, along with the most limiting single acdve failure for the SGTR model, there is adequate margin ensuring the ruptured SG 6es not overfill. N i Page 4 6 1

s r L \\ 4.4 TABLES TABLE 41 Sequence of Events for SGTR (Offsite Dose Case) System Response / Operator Action Time (sec) SG Tube Rupture Occurs 0 Reactor Trip 599 Ruptured SG PORV opens 606 Safety Injection 607 Auxilary Feed Water Injection 668 Ruptured SG Isolated 1816 Auxilary Feed Water Isolated 1867 RCS Cooldown Initiated 2356 RCS Cooldown Terminated 2994 RCS Depressurization Initiated 3234 RCS Depressurl=ation Terminated 3411 ECCS Flow Terminated 3591 Page 4 7 .2

TABLE 4 2 Sequence of Events for SGTR (Overnli Case) } System Response / Operator Action Time (sec) SG Tube Rapture Occurs 0 Reactor Trip 393 Safety Injection 399 l Auxilary Feed Water Injection 400 Ruptured SG Isolated 960 RCS Cooldown Initiated 1500 RCS Cooldown Terminated 2605 RCS Depressurization Initiated 2845 RCS Depressurization Terminated 2948 ECCS Flow i'erminated 3128 70 GPM Charging Flow Established 3188 RCS Letdown Established 3428 Roopen Pressurizer PORY 3548 Reclose Pressurizer PORV 3576 Page 4 8

l 4.5 FIGURES FIGURE 41 Pressurizer Pressure (Offsite Dose Case) 2,400---------,-------,-------.--------r-------,-------, .i i e i i i i 1 I I I I i 2,200--------i--------l-------'-------'I -f--------j I i I I t 1 1 I I I i t i i I I l I m .9,, 2,000 ------ - A,------ a,------- 4,------ a. i i ,t CL I i 8 I 1 V 1 1 2 1,8002 --------<----- => vi WI 8 I I I I t j1,600---------+-------4.---------------'r,-------f,--- - - - - -i. 6. U l i i l l l .5 1.400-------- A,------ a,------- '------- 5 ----- A,--- s, = [ t. ,t ,i 6 i 4 E 1,200i-------'.-------,'.--------l-------',------!------'. o. 1,000-- - - - - - - - ; - - - - - - - - - - - -;- - - - - - - - ;. - - - - - - - ; - - - - - - -; t t t I t I 800 o 600 1200 1800 2400 3000 3600 Time (sec) Page 4 9 i .~

FIGURE 4 2 Pressurizer Mixture Level (Offsite Dose Case)

c-------r-------,-------,

50- -------,-------,t 5.ressurizeir height = l49.66 ft l l l overal 45i- - - - - - - - i - - - - - - - -l - - - - - - - 'i------- r-------i--------i e 1 i a t I l I I I l 2------ J ^402------- 2---- J-------'------- 'i I i t a l i i i i l 4 w O I I I I I I T> 3 5."

+------

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f i i l I 1 i 0 4 I I I I i e i 4 4 30-

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--,I--------i--------r-------v----- d i i i t .I I l l I s.

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,I I I I "3

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T------ ,I I .e t I I i 4 i 2 I l i I I I 2---- -J A------ J-------'------- 'I D 202 I I 8 I I l I l I i N I a i i i 1 'C +-------

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I M i t i I i e e i i i

,i e

i i n'.10 - - -,i

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5 'U 5 f-------l------- r-------i-------. e i e i i i l e i i i 1 1 i g ,ig g g g g i i 1 i i i v i 1 i i 1 1 0-iu i i T r 1 1 i 0 600 1200 1800 2400 3000 3600 Time (sec) Page 410

FIGURE 4 3 Ruptured Steam SG Pressure (Offsite Dose Case) .{ e l 1, 3 0 0 - - - - - - - - v - - - - - -, - - - - - - - i- - - - - - - r - - - - - - v, - - - - - -, i i i i ^ I i i l i I O i i i I 11,200

d--------l--------F-------f,-------i, i

i i W i i I u e a e i a

'1.100-d,-------'-------

a, n i I M i i I i 1 l k 1 i 1 i I c.3,ggg;m . _ _ _ _ _ _ ; _ _ _ _ _ _ _ _;_ _ _ _ _ _ _ _ i i i 1 i l 1 i i O" i, g i g i M 1 1 I i i b 9002 - - - - - - - - i - - - - - - -l - - - - - - - -l- - - - - - - 'r - - - - - - l - - - - - - - -I, C i i U l i i 1 e I i b0 i i I I i 1 e 800-------- 'i --8-------'---- -- i------- '------ a 6 i i I I I O i i i i e i i y

,'------'-------'i-------r-------+-------,'

i i i t vi 700-x3 i i i i i i 0 ,e i i i i t $.600 - - - - - - - i - - - - - - - -l - - - - - -l - - - - - - - F - - - - - - - + - - - - - - - -i l

3 i

i i i Q: 1 I i 1 i ) I e i i e i 500 .....j..,,,j ,...i.....j.....i.....i O 600 1200 1800 2400 3000 3600 Time (sec) [ I l i 1 P I l l i i t I f 1 Page 411 t i L a ( ) 1

FIGURE 4 4 Ruptured Tube Flow (Offsite Dose Case) 60------ 2-,------ ,--------r-------r,-------,-------, i i i. I I l i i i i i

+-------s 50-

+-------d---

--.u------- i i, i i, i I ,1 m i e o - - - _ q.. - _ - _ _ _;- _ _ _ - - - - p _ - - - _ - _ 9, - -..--_q 3 40_ 1-- { s i. E i i _2_3 30-------- T------ ,i-------,------- r------ T--- - -,i O 1 i l i 1 0 g = 8 I I I i 1 i i i e i i %20---------r------,i--------r------r------v---- - -,i i i e i u i i e e i i i i as e. t i i 1 1 i i i I i i i I i i i i

<----------------*-------+----- - - *i 10---------+i i

i i e i i i i i i i i i i i i i i i I i i 8 a 1 0 0 600 1200 1800 2400 3000 3600 Time (see) Page 412

I 1 FIGURE 4 5 Ruptured SG Steam Release Rate (Offsitt

A w e '.

l A E 6 0 0 - - - - - - - - v - - - - - -, - - - - - - - i- - - - - - - - r - - - - - - - v - - - - - - -, I 6 i i l i y) \\ i i i i i i E I i i i 1 i I i i l ---~---d----------------*-------+-------* v500- --------< i i i i i 1 I I I I eU i i i i i I i t i 1 QC 1 i i l i E400-J-------'------- A------ J 8 8 8 8 8 O i i i i 1 g i I I i i i i i i i o OI I i i i n - - - - - - - i - - - - - - - '.- - - - - - - 'r - - - - - - - i - - - - - -i 8300-13 i i i i i 1 I i e i y O 8 I I i i C I I I I i - - - - - - - - - - - -l- - - - - - - 'r- - - - - - - - - - - - - 4 c5200-E e i i i i i i i i i 8 Total Mass Rele'ased from kuptured S'lG = 8955b lbm l f t i i i i / m ico - _____4._______,________ i e i i i 33 i i i i e i i i ..3 I 1 1 i 11. .'i...........i..... 0 2 a: 0 600 1200 1800 2400 3000 3600 Time (sec) } } Page 413

FIGURE 4 6 Intact SG Steam Release Rate (Offsite Dose Case) g 1, 2 0 0 - - - - - - - - r - - - - - - -, - - - - - - - i- - - - - - - r - - - - - - -, - - - - - - -, i i i i i i i i t i i i es i i i i i i i i i i i i E i i i i i i e 1,000---------4-------d--------i--------*-------+-------* i i i ,i m i i i i O i i i i i 5 i i i i i a: i i i i i _______q._______;________p_______;_______q 800_ ________. i = o i i i i i je i i i i i i i i i i e - - - - - - - f - - - - - - - -l- - - - - - - 'r - - - - - - - { - - - - - - - f T 600- --------- 8 8 8 8 8 .C. i i i i o Total Moss Released fromilntact S/GIs = 130710 lbm i i i i i 4________l________'._______;... ____a g 400_ i i e i c3 e i e i E i I I I O i i i i 200- --------<

+--------

vi e i i i i i e i i i e i l = y O 8 i i I ed i i i i 5 0 .....i.....;.....J; o 600 1200 1800 2400 3000 3600 Time (see) l Page 414

FIGURE 4-7 PZR/ Ruptured SG Pressure Comparison (Offsite Dose Case) m 2, 4 0 0 - - - - - - - - v - - - - - -, - - - - - - - i- - - - - - -.- - - - - - - v - - - - - -, O i i i i i i i i i i i 8.2,200. - ------+-------*--------i----------------,-------- i i i i i m i i i i i i 2 2,000, -------+-------a--------i-- --- -----+--

d 3

i i i i i i d E 1,8002 E Press'urizer l l l i ' 1.6002-------A--------------'-------'------4--- --- J e i. i i i i i i i i i D1,400 ~- - - - - - - - f - - - - - - - d - - - - - - - -l- - - - - - - - l - - - - - - - f - - - ~---i y i i i i i i E 1,2002- - - - - - - - - - - - - -l - - - - - - - -l- - - - - - - ' - - - - - - - i - - - - - - -I r \\ a i e i e i } 1,0006 - - \\- - - - - -! - - - - - - - -l- - - - - - - 'r - - - - - - - l - - - - - - 4 ( -,_____u___ i, i i i i e 800-_------,,--N-g s.,i-------,---,,-,.------,i i i e / i i i c

,e -------,i %--- % i------ i N

i i o 600-mg i i i i I .g 400;_ - - - - - R@.t u te.d. S tehm t.m teto t - - - - - ',. - - - - - - ', - - - - - - J 3 i i i i i i n i e i i i i 200.--------+-------a--------w-------'------ +-------a av i i i i i i c". i i i i i O ' ,,,,, ',,,,,,',,,,,,',,,,, ',,,,,,',,,,, i 0 600 1200 1800 2400 3000 3600 Time (sec) 1 Page 415

l ( ( FIGURE 4 8 Ruptured SG Liquid Volume (Offsite Dose Case) --+7,000---------t------,-------i-------t------r------, i i i i i i u 2

steam (enbrotor totoj volume =s'6314 cu f(

l 2 u d-------*------- '-------'------ a l v 6.000 --------- 'I I i t i t .I U t i I l 4 i E i i i i i i a i i i i i T)5,000-- - - - - - - - i, - - - - - - - i, - - - - - - - -l - - - - - - - ',- - - - - - - - t, - - - - - - - i, 23 i i 3 .cr4,000;........;___....'...........__,.________..____.l 1 L i i 1 'l I 1 I i l I i 6 I I I e i O i i i i i i a------ u--------'-- ---'-- --- a 3.000.------- 'i i i i i e I I I i C ,I 0 I i I I I I I 4 I i 1 () _- - - - - - -J - - - - - - - -l - - - - - ' - - - - - - - l- - - - - - - - t - - - - - - - i E,000-2 O 8 8 8 3 0 I I l I I i 6 4 I I I I I t i I VI

,t -------,--------i--------r-------,-------,

o 1,000-- i i i i i i 1 I 1 I I t w A 3 l tube rup,'re locatior) at top of ltubesheet l l } CL 0 ,,,,,,,,i ,,.,,,,,,,;,,,,,,,,,,,i a a: 0 600 1200 1800 2400 3000 3600 f Time (sec) Page 416 9 (

FIGURE 4 9 Ruptured SG Water Mass (Offsite Dose Case) / l I } E 1 80.000 - - - - - - - -, - - - - - - -, - - - - - - - i- - - - - - - c - - - - - - -, - - - - - - -, 22 i i i, i, i e. e b I e i O i i i i e i 1s i peo,ooo_..___...; ......q.............. .p...... ;.....__q c i i i i i, e i e ,i i i I) e i e e e i i i i i i i e i a v140,ooo---------,i -------,i

v-------,i i

e i

r i

i i I y) i i i e i T3 i i e i i i e i i i i 3' e, e i i i e i i i i i a120,ooo-........ A...... a........i. _.... L...... _ A.... _ a, a e i i i i i e i a i i e i e i c e i i i i i i i e i i i i e i i i e y 100,000_....... 3.......,e...... r-

T------

,i y i i e i i i i e i, i, e, i ,i o i e i i e i i i e i e i i ) y so coo o 600 1200 1800 2400 3000 3600 Time (sec) { I Page 4-17

1 f FIGURE 410 Ruptured Loop RCS Temperature (Offsite Dose Case) l l l ) 650---------,-------,-- ,--------e-------,-- n i. e. i. i u. i 0600 - - - - - - - -l - - - - - - - -l- - - - - - - - F - - - - - - - i - - - - - - - -l e i i i e i i Hotile9 'ei i i i e 550 --------- %-----s-4------ i i -t i o 's l ) e5002- - - - - - - -.l - - - k l - - - - - - - -l- - -.~ e =X

i.

t .~ u,e i i m i s i i

c---,\\---v------

,i -e450---------v--- --,i i i i i [ l l Cold le l I3l l - - - - - - - - i - - - - - - - i - - - - - - - -l- - g-----F----klef--,(-- 4 E 4002 t. y i i i i i 11 i i i i 8 i A------ a------- i-------.'----*-- -,l.4 - - s. u)3502 c3 i i i e e i i e i i i i i i n i i c.300_-_........i................................ 6 4'.... l o .i i s,i i i i o i i i i i i t a ( o 250 - v------ ,i------- ------- r------ v---.-- ,i 1 .i i. i i i i i i m / 3 2002- - - - - - - - - - - - - -[ - - - - - - - -l- - - - - - - - F - - - - - - - i - - -. N - - -l i i i i i 150:,,,,,;,,,,,;,,,,,;,,,,,;,,,,,,,,,,-; i i i g o 600 1200 1800 2400 3000 3600 Time (sec) t l s i l Page 418 ( -D

l-I f FIGURE 4-11 I Pressurizer Pressure (Margin to Overfill Case) r I 2, 4 0 0 - - - - - - - - r - - - - - - -, - - - - - -, - - - - - - - r- - - - - - - r - - - - - -, i i i i i i 1 1 1 l i I I e i i i i 2,200- - - - - - - - t - - - - - - - i - - - - - - - ' - - - - - - - - l- - - - - - - - t - - - - - - - i 1 I i 1 .I 1 I i 1 l l 1 i i l i i i .9 2,000----- 'I d-- -l------- '-------'------ a m I I I i 1 CL I I I I I I V 1 1 I i 1 ._'_______ I e i,8002._______;__ .,________l_ _____.__/__ 1 I I a I a l M 1 1 I 1 I M I I i 1 I i [ 1,600-- - - - - - - - t - - - - - - - -l - - - - - - - -l - - - - - - - - l- - - - - - - t - - - - - -j i l i 1 1 I I i a i i i U 1 I 1 1 1 0 .g 1,400_- 2 ________t_______a________i_______ u______ _t i i i i i i I i i i i i I i i l I I { 8 1,200---------?------'--------l--_----'r------ o. I i 1 l I I I I l l I i i i I ) 1,000__ _ _ _ _ _ _._ t _ _ _ _ _ _ i _ _ _ _ _ _ _ _l_ _ _ _ _ _ _ _ p _ _ _ _ _ _ ;._ _ _ _ _ _ _ q i I i i i 1 i i i i 1 i t 1 i I i I 800 0 600 1200 1800 2400 3000 3600 Time (sec) L i Page 419

h~*,y_

f l

' FIGURE 412 Pressurizer Mixture Level (Margin to Overfill Case) 50---------v-------,-------i--------r------r------, l overall pressurizdr height =l49.66 ft l l 45i- - - - - - - - t, - - - - - - - -l - - - - - - - -l- - - - - - - 'r - - - - - - - t - - - - - - - i. i 1 I i i i m40;_------ 1,------ a,-------i------- c------ t------ a. I, I, i. I O 1 35.--------+-------d--------i--------

+-------*

o> i i i i i i, e i i a 30.------- x-------,i

i--------r------

r------ i i i i s. t i i 1 i 4 "3 - - - - - - - t, - - - - - - - -l - - - - - - - -l - - - - - - - - l,- - - - - - - - t - .1 25i

s i

i i i ,20 : .~ 2,------ >-------'------- '------- - - - - - - - i, e c,15. --+-------,---------------,------ +-------4 m i i ose i 6a.10i_ - - - - - - - ; - - - - - ' - - - - - - - -l - - - - - - - ;i i i i i i 8 i a i 5'. i i i i 1 l i i i O' ......'....,'.....'.....'i....., ) 0 600 1200 1800 2400 3000 3600 Time (sec) l f Page 4 20 l - i

'\\ FIGURE 4-13 l Ruptured Steam SG Pressure (Margin to Overfill Case) 1,300--------r------,------,-------c------r------, i i i i i i l ^ ,i ,i .o i i i I I 11,2002 - - - - - - - - + - - - - - - - -{ - - - - - - - -l - - - - - - - - l- - - - - - - - i,- - - - - - - - ! i 1 i l 6 i i i i i o I i i i 1 5 g1,joo_________;_______a_______.a________i________t_______4 = U l 6 I 8 I I I I ou 1,000-

,i

,i--------r--------r---- -,i i i i --r f h i i i i i I 1 1 l i I a i i e i e i k IB 2 l C - - t - - - - - - - -l - - - - - - - -l- - - - - - - - l- - - - - - - - l- - - - - - - - i 900 U ~ t I i i i i e

n

,l 8, i 1 I I E 800.------- J-------u------- '-------a i i i i i O j 1 i l i I 1 1 n I l i 700;_ _ _ _ _ _ _ _ ; _ _ _ _ _ _ _ 4 - _ _ _ _ _ _ _l _ _ _ _ _ _ _ _ '_ _ _ _.. _ _ _ ; _ _ _ _ _ _ _ 4 m 'O i i l i I 4 O i l i I i i '.3 l 1 i l i 1 y 600f- - - - - - - - } - - - - - - - l - - - - - - - -l - - - - - - - - l- - - - - - - - l- - - - - - - - -l 3 I 1 i f 4 I t ( Z 1 1 ,I I I I a 1 1 1 500 ....j.....j.... ,.....;.....;.....i / O 600 1200 1800 2400 3000 3600 Time (sec) t { Page 4 21 l A

L FIGURE 4-14 Ruptured Tube Flow (Margin to Overfill Case) / 60--------r----,------,-------r------r------, I l i i i 1 I i 1 1 1 I ~ i 1 I i 1 1 I i 1 1 I i 1 1 1 1 1 1 50-

+-------a---------------..~-------+-------*

l i 1 1 I I ~ i 1 i i i i I i 1 1 1 1 k' n ~ l i I I I L O 1 I I I I I g 40_- s i________p_______p_______4 / 1 I i l I 1 e i l i I I o 1 I i e i i i I i I I I g , 30_ _ _ _ _ _ _ _ 4 _ _ _ _ _ _ _.; _ _ _ _ _ _ _ _; _ _ _ _ _ _ _ _ l_ _ _ _ _ _. _ p _ _ _ _ _. 4 0 ~ 8 8 8 I I 8 I I I I I i i l I i i l I l i I i i 2d

r------

,I------ ,I O I l i ,I o20-r------ 0'0 i i i i i 1 i l I i l I i 1 1 i i l 1 i i I I I i l 10---------+1 -------*------- -------- ------ 4 I i i i i f,l I I I I I i i i i i ~ l i 1 1 I J 1 1 1 1 l 0 0 600 1200 1800 2400 3000 3600 Time (sec) Page 4 22 1

i l f ( FIGURE 4-15 Steam Generator Release Rate (Margin to Overfill Case) d 600--------r------,-------,-------r------r------, i i i i i n i l i i i i O I i i i I l I I i i i i } 0 i i i i i M N500---------+-------d-------d--------

+-------*

'e E i 23 i i i l l l l l l 0 i oc -- - - - - - - - t - - - - - - - -l - - - - - - - -l- - - - - - - - F - - - - - - - t - - - - - - - j a400-i i i i i i g i i i i i i Total Mass Rele'ased from huptured S'/G = 0.0 lbm l o - - - - - - - - - - - { - - - - - - - -l - - - - - - - - t - - - - - - - -l - - - - - - - -l- - - - /G's l = 15019 . 300-i f Total Mass Releaped from Irltact S l 6 I I I I I i O i e i e o200-- - - - - - - - ? - - - - - - - - - - - - -l - - - - - - - - l- - - - - - - - ? - - - - - - - -; o i i s i i i i C I i i i I i CD ~ l i i l i 0 i i l i l i ~ l i i l f E 100---------+-------4---- --------------

4 o

i i i i i i

d i

1 i i l i O i e i I ,i i l I i i 1 1 i i i i t 0 ...........i.. ..j.....;.....,.... 0 600 1200 1800 2400 3000 3600 Time (sec) f I l Page 4 23 k

FIGURE 4-16 PZR/ Ruptured SG Pressure Comparison (Margin to Overfill Case) n .D -ma "2,400--------r------,--------------r------r-------, e i i i i o i i i i i i .e 2,200.

+-------

i--------r-------+-------*

i i i i i i o' i i i i i i E ,000'---- ---+-------*i '2

-------+-------*

i e i i i i i i O0 1,800.--------.;-- a - - - - - - - -l-

p---y -p------

a Press,'urizer i i i i e i 51.600 ~. L-N a A------ J------ s------- 'e------ i i i i i n f n i i i i i i S 1,400-- - - - - - - - t - - - - - - - -l - - - - - - - -l - - - - - - - - }- - - - - - - -t ------ i _o-i i i i i i i c - - - - - - - - t - - - - - - - i - - - - - - - -l - - - - - - - l- - - - - - - )1,200f

- r q % # v -- - - - i- - - - - - - r - - - - - - r - - - - - -,4 fs;

-l- - -.- - q- - - - 1,000 : .o i i i i i 4 g %=- r------ ,i- - - - - -,i g i i i i 6a 800-r------ r------ 600i Ryptured Stepm Genera}or l l l a

+--------i--------i--------r--------+-------,

U i i i i i i i i l i i i c 400---------+-------8--------i--------~-------+-------* a i i i e i i ~ i i i i i i b 200~--------+-------s----------------w-------+-------a f N i I e i i i i i i i i i 0 . j...., j..... j .... j..... j.... r-t } 'g g E O 600 1200 1800 2400 3000 3600 i cE Time (sec) f Page 4-24

f FIGURE 4-17 Ruptured SG Liquid Volume (Margin to Overfill Case) n +d 7, 0 0 0 - - - - - - - - r - - - - - -, - - - - - -, - - - - - - - r- - - - - - - r - - - - - - -, o i i i i i i '.5 .._ ' steam gen >rator total volume =l6314 cu ftl l I 2 3 8 1 l i gv6,000 --------A------a--------------'------'- -a I i I I I i i i i i i o i i i i E i i i i i a 3>5 5,000---------t--------l,-------',-

t-------i i

i 13 i i i i i '.5sr4,000q"._______'_____,________l________',._______'_______.; =d i I I i 1 4 L. 1 I 4 8 I i O I I e i t i I i e i i } +' 2 3,000-.------ a,------- a. o C I i i I i t () I I I I I i o I I I i i a E,000-- - - - - - - - t - - - - - - - - - - - - -l - - - - - - - - l- - - - - - - - t - - - - - - - i 2 1 I I I I I o I i i i e i g)

d i

I I I i i 1 l 1 8 l N "--------r-------,I y 1,000-

r-------c.------,

t i i i i .i s. I i i i i i 3 l Tube Rupth,re Locatioh at Top oflTubesheetl l ct 0 a a: 0 600 1200 1800 2400 3000 3600 Time (sec) Page 4 25

FIGURE 418 Ruptured SG Water Mass (Margin to Overfill Case) ) i i i n E 300,000 - - - - - - - - r - - - - - -, - - - - - - - i - - - - - - - - r- - - - - - - r - - - - - -, 23 i 1 i i l i i i 1 1 1 1 y 1 i i i 1 ' 280,000---------+-------4-------w--------r-------+---- -4 0 3 e i i 0 t i i i t i 1 I I I I 6

4--------8-------l-------'--- ---'e------

d

260,000,

e i i 1 i l 8 I i i I I 1 i i i i i O 1-------8-------l---- L------ J c 240,000, L 3 I I I I i I O I i i i i 1 O 1 1 1 I I -- - - - - - - - t - - - - - - - -l - - - - - - -l- - - - - - - - }- - - - - - - - { - - - - - - - -lI 5 5 220,0002 i I i i i 73 O I I i i i 1 $ 200,000 --------t------ - - - - - - - -l- - - - - - - - }- - - - - - - - h - - - - - - - 4 I I I I I I i CL 1 I I I I i l 3 a: 180,000;_ - - - - - - - - - - -.l - - - - - - - -l- - - - - - - 1. - - - _ _ - - ;. - - - - - - -.; C 1 1 i i i 1 8 i i 1 i i 1 1 1 i i I .'0160,000-l

+

4--------i--------1--------c-------4 f

O 1 I I I I g g i i i i i i 1 i l 1 I i g 140,000-------/-;-------q--------l--------p------

-------3 m

1 1 1 I i 1 M I I I I I i .j 120,000 -.... j ....;.....;.....;,,,..j. t 0 600 1200 1800 2400 3000 3600 f Time (sec) L f ( Page 4 26

FIGURE 419 Ruptured Loop RCS Temperature (Margin to Overfill Case) I 650.--------v------ ,--------r------ r-------, ) g 1 I i l i i n i i i i i 1 E600'. - - t - - - - - - - i - - - - - - - -l- - - - - - - ' - - - - - - - f - - - - - - - 4 r f,,s50 g l Hot Leg l l l l o 1-t------ a i i i ....i~.,.._i ...s i i o i i i s i i

+,-------i --------i--a-----

i E5002 5 i l l Cold Leg l \\, l l l e 4502- - - - - - - - ? - - - - - - - -l. - - - - - - - -l- - - -\\- -4o - l- - - - - - - - ?, - - - - - - - -l ~ i g lg i 3 i i i i f, i i a . _ - _ - _ _ _ 4 _ _ _ _ _ _ - ; _ _ _ - _ _ _ _l_ _ _ _ y _y _ _ _ _;_ 4 _ ;. _ _ _ _ _ _ _.; e 400; )i e i i y r i i i i ---8 - r,t------,o m 3 5 0 r - - - - - - - - - - a - - - - - - - '- - - - - - - - i i o i i i e i i i i. f. i i i\\ i i a 300_._ _ _ _ _ _ -. - - - - _ - 4. _ _ _ _ _ _ _i -. _ _ _ _ - _ i_. _.j _ _ Le _____I_ i i i is i ii o j i 8 l

d. 2 5 0 2

' - - - - - - - -l- - - - - - - ' - -W - - hg---/--il o O i i i i g g c i i i l. i i e i i i 't - .3 200-. -----1------>-------'-------'i------- \\,,,i i i i a i i i i i o i i t i *" i 150 j, ,j,,,,,j,,,,,;,,,,,j,".,,,; g i O 600 1200 1800 2400 3000-3600 Time (sec) / l 1 I Page 4 27

FIGURE 4-20 Intact SG Leakage Rate (Offsite Dose Case) ?. 1 5 0 - - - - - - - - r - - - - - -, - - - - - - - i- - - - - - - r- - - - - - - v - - - - - - -, 0 i i i i i i g I i 1 1 1 l m i 1 I I I i 1 1 I I l i N i e i 1 i E 0

+-------d--------i--------*-------+--

d e.125-i i

i i_ i v i 1 1 1 1 i i i i i i O l 1 1 1 'l I LO i e i i

l------J-------'

t-------2---

-- J ~ 0.100-1 I I i i i 1 1 i 1 i .c i i i i i i i i i n - - - - - - -{ - - - - - - - -l- - - - - - - 'r - - - - - - - i, - - - - - - -l 0.075- --------~ .o. i i i i l i 1 I .b = i 1 1 1 1 4 3 I i 1 l i I e0.050-- - - - - - - - - - - - - - - - - - -l- - - - - - - - l- - - - - - - ', - -. - - - - - 4, i I ,a 1 I I 1 I y _a I i 1 i i I g) e i i s e I 1 i i 2 0.025----- ---+I -------d--------i--------*-------+-------- o. i i i i i i i O i i i e i e i i e i C3 1 I e i i l i i i i i i " 0.000- ,,,i,,,,j..,,-j,,-,,r-j ,,,-l,,,,,j 0 600 1200 1800 2400 3000 3600 Time (sec) \\ Page 4 28

FIGURE 4 21 - Average Flashing Fraction (Offsite Dose Case) n ao C 0.1 0 0 : - - - - - - - r - - - - - - -, - - - - - - - - - - - - - - r - - - - - - v - - - - - -, i i i i i i a i i I i i i O 2 0.090+- - - - - - - t - - - - - - - -l - - - - - - - -l- - - - - - - 'r - - - - - - - - - - - - -I 4 e i e i i i g i i i o 0.080-i- - - - - - - - t - - - - - - - -l - - - - - - - -l- - - - - - - - F - - - - - - - t - - - - - - - -l i e i i i i x i i i i i i y e 0.070+-------+-------d--------+-------*-------+-------- i i i i i r i-m i i i i i i O -'------,i-------i------- r------ T------ ,i i i i c0.060: i i i i i E i i i i i - - - - - - - -l - - - - - - - -l- - - - - - - ' - - - - - - - i - - - - - - - -l

9 0.050+

r v I i l i i 4 e i i i i i

J-------'-------i-------2------a

.9 0.040+ - - - - - - - - i i l i i esU i i e i i i i i i O .------- --------i-------- -------+-------- d- 0.030 i i i i i en i i i i e 0.020 : ,i

,i-------i------- r -----

T------ ,i i i 2 1 i i i i i m O i i i i i i t 0,010.;- _ _ _ _ _ _ _ 1 _ _ _ _ _ _ J _ _ _ _ _ _ _ _i_ _ _____L______.1_______; i i i i i i i i l i i en i i i i i o 0.000 : m .i...,,i,,,,,i.,,,,,,...,,,,,,,i e i 0 600 1200 1800 2400 3000 3600 Iime (SeC) i l ) f Page 4 29

b;.. mpu sb. FIGURE 4-22 Intact SG Water Mass (Offsite Dose Case) m 4 50,000 - - - - - - - - r - - - - - -, - - - - - - - - - - - - - - r - - - - - - v - - - - - E l 1 1 i i i 1 1 1 1 1 7,,425,000--- - - - - - - - t, - - - - - - - -{ - - - - - - - -l- - - - - - - F - - - - - - f - - - - - -, i i i i i 0 1 I I I 8 1 8 E A------ d------- 8-- 4------ d ' 400,000-U s. i e i s 8 l 1 I i 1 i 1 y l l 1 I I i 0 $ 375,0002--------?-------4-------I--------r-------?-------4 m i i i i 8 i 1 l i i I O i e i i ~ 0 350,000-- - - - - - - - j - - - - - - - -{ - - - - - - -l- - - - - - - - F - - - - - - - j - - - - - - - -l 0 i i l i i i c i i i i l i O A------ J

t-------A------d I

1 1 I I I O 325,000-- i i i i i 0 1 I i 1 1 1 I i 1 i 1 0 1 1 --------1----------------,-------,I 1 l 1 gj 300,000--------- 7----- -,I I I i 1 ^ 1 I e i I F3 l I I I i 1 v '--------f - - - - - -j - - - - - - - - - - - - - - - - F - - - - - - - j - - - - - - - i 275,000-o 1 i i 1 i i o i l i i .i i J .c 8 8 i i - 250,000J 4 O 600 1200 1800 2400 3000 3600 Time (sec) \\ l Page 4 30

5.0 RESULTS AND CONCLUSIONS The rupture of a single steam generator tube in one of the Byron /Braidwood plants was evaluated. The assumptions and methodology used were consistent with those developed by Westinghouse as presented in WCAP-10698 P-A and Supplement I to WCAP 10698-P-A. Significant plant parameters and single failures were investigated ensuring conservative results were presented for the offsite dose and the margin to overfill cases. Since the response of the operator is criticalin mitigating a SGTR event, a conservative representation of the ANS Standard 58.8-1984, the Byron /Braidwood emergency procedures, and the Byron /Braidwood operator training data were used for the analyses. The most limiting single failure for the offsite dose case is a 0,C . With this single failure and the preaccident and concurrent lodine Spike moders, as prescribed by the Standard Review Plan (3RP) 15.6.3, the offsite doses (for both Exclusion Area Boundary and Low Population Zone) do not exceed 10 CFR 100 limits or the acceptance criteria of SRP 15.6.3. The most limiting single failure for the margin to overfill case is a o,c With this single failure and the B/B T-Hot reduction plant conditions, it is shown that SG overfill does not occur. ) I { Page 51

6.0 REFERENCES

1. Letter from C. E. Rossi(NRC) to A. E. Ladieu (WOG SGTR Subgroup),

"Acceptance for Referencing of Licensing Topical Report WCAP 10698', dated hlarch 30,1987.

2. WCAP-10698-P-A,"SGTR Analysis hiethodology to Deterrrine the Margin to Steam Generator Overfill", August 1987.

3. Supplement I to WCAP 10698 P-A,"Evaluation of Offsite Radiation Doses for A Steam Generator Tube Rupture Accident", hlarch 1986.

4. Letter from J.W. Swogger (W) to H.E. Bliss," Commonwealth Edison Project, Byron /Braidwood Nuclear Power Plant, Byron Unit I Design and Physical Data",84CB* G 043, November 21,1984.

5. WCAP il388,"T Hot Reduction Program Engineering Report',

Vol. I and 2, hiay 1987.

6. WCAP-9640,"Setpoint for Commonwealth Edison Company Byron Units I and 2, Braidwood Units I and 2", November 1979.

7. Technical h!anual 1440-C282, "Vertical Steam Generator Instruct.ons CECO. Byron Generating Station Unit 1, Braidwcod Generating Station Unit 1", July 1976.

t

8. Techntel blanual 1440 C312, "Vertical Steam Generator instructions CECO. Bywn Generating Station Unit 2, Braidwood Generating Station Unit 2", January 1980.

9. Byron /Braidwood FSAR, Chapters 6,7,15, and 16.

10. Technical h1anual 1440 C283, "Pressurizer Instructions for CECO.

Byron Generating Station Units 1 and 2, Braidwood Generating Station Units I and 2", July 1976,

11. Byron Station Units I and 2, Braidwood Station Units I and 2,

{ Precautions, Limitations, and Setpoints for Nuclear Steam Supply Systems", Revision 8, h! arch 1987. {

12. J.L. Tain (W) !ctter to J.D. Deress (CECO.), ' CECO. Byron and Braidwood Stations Unit 2, htodel D 5 Steam Generator Level Control Problems /Recommmendations", CAW-10072, CBW 5627, September 11,1986.

13. WNET 143 Volume 1,"Engineering Stress Report for h1odel D Steam Generators", CAW-3058, CBW 2544.

Page 61 i

?yy , ' b; ~ ~ '14. Braidwood Unit 1 Pre Operational Test SI 12, Test Number BwPT-SI-12, Revision 0.

15. Braidwood Unit 1 Pre Operational Test SI 12, Test Number BwPT-SI-12, Retest No. 90.

o

16. Ceco. Letter from B.B. Palagt to J.D. Campbell (W), "HELB Plant I

Specific Data", March 26,1986.

17. NRC Branch Technical Position ASB 9 2, "Residual Decay Energy for Light Water Reactors for Long Term Cooling", Rev. 2, July 1981.

18. American National Standard ANSI /ANS-58.81984,"Time Response Design Criteria for Nuclear Safety Related Operator Actions",

September 1984.

19. Byron Emergency Procedure iBEP 0 "Reactor Trip or Safety injection Unit 1", Rev. 2A WOG 1, December 14,1987.

20. Byron Emergency Procedure IBEP-3 "Steam Generator Tube Rupture Unit 1", Rev. 2B WOG 1, December 14,1987.

21. Byron Emergency Procedure IBEP-2 "Faulted Steam Generator Isolation Unit 1", Rev. 2 WOG 1, July 30,1987.

i.

22. Byron Emergency Procedure iBCA-3.1 "STGR with Loss of Reactor Coolant Subcooled Recovery Daired Unit 1", Rev. I A WOG-1, March 24,1986.

23. Byron Emergency Procedure IBEP-ES.3.1 "Post STGR Cooldown Using Backfill Unit 1", Rev. 2 WOG-1, July 30,1987.

24. Byron' Emergency Procedure 1BEP ES-3.2 "Post STOR Cooldown L

Using Blowdown Unit 1", Rev. 2 WOG 1, July 30,1987.

25. Byron Emergency Procedure 1BEP ES 3.3 "Post STGR Cooldown Using Steam Dump Unit 1", Rev. 2A WOG 1, September 28,1987.

I } Page 6 2

Appendix A. BYRON /BRAIDWOOD RETRAN MODEL A.I The System The Byron /Braidwood power plant is a 3411 h1Wt Westinghouse pressurized water reactor. The reactor coolant system (or primary system) consists of a re-actor pressure vessel, four U tube type steam generators, four reactor coolant pumps, an electrically heated pressurizer and tne inter connecting piping. The system is arranged in four heat transfer loops A, B, C and D, each with one re-actor coolant pump and one steam generator. The pressurizer is located in loop A. The reactor coolant Dows through the steam generator tubes transferring heat to the liquid and vapor on the shell side of the steam generator. The secondary system is a heat utilization circuit where dry steam p.oduced in the steam generator Dows through a turbine-generator to generate electricity. The condensate is pumped back to the steam generator (via the feedwater system) to complete the cycle. The plant control systems are designed to produce signals for control of the major components (reactor, pressurizer, steam generator, feedwater system, turbine and bypass valves, etc) under all operating conditions and power levels. This control is to provide safety and stability of the plant systems. A.2 RETRAN Computer Code The RETRAN02/h!OD3 computer code was employed in performing neutronic and therma' hydraulic calculations for this study. RETRAN02/h10D3 is the corrected version of RETRAN02/h!OD2, which received an NRC SER in Sep-tember 1984. The NRC SER was reviewed for the intended application of using RETRAN02/h10D3 for design analysis of a SGTR event, it was concluded that I the general and speciSc limitations cited in the RETRAN SER do not apply to ) this analysis, and RETRAN02/htOD3 is an acceptable code for SGTR transient analysis; f The RETRAN02/h10D3 code package was received from the Electric Power Software Center in January 1984 and was installed on the Commonwealth Edi-son Company (CECO) 18h1 system in accordance with approved installation f procedures. A code certincation project was then undertaken by CECO to assure the integrity of the code after the initialinstallation. The NRC SER and CECO software QA program justify use of RETRAN02/hlOD3 for thermal hydraulics analysis applications, such as the SGTR esent. Page A 1

it.3 RETRitN Hydrodynamic Model MODEL OVERVIEW The RETRAN nodalization diagram of Byron /Braidwood for the SOTR analysis is shown in Figure A-1. The RETRAN model employs two heat transport loops. One represents a single loop (the ruptured / faulted loop), while the second loop (intact loop) combines the remaining three plant loops into one. The second loop is further branched into two cold leg subloops, with one RCP and two RCPs (combined into one) respectively. This model simulates principally the primary system. The secondary system is represented by four nodes with a single node steam generator model. The balance of plant is represented by boundary conditions (011 tables). The plant control systems are implemented using RETRAN's basic control modules. These systems produce signals to control various components in the RETRAN model during the plant transients. l The tube rupture was postulated to occur just above the tube sheet to maximize the break flow. A control system was developed to conservatively predict the flows through both short and long sections of the ruptured tube. Appendix B l oresents a detailed description of the ruptured tube flow model. The operator action times employed in this study are a conservative represen-tation of the ANS Standard 58.8 1984, the Byron /Braidwood operator training data, and the emergency procedures for a SGTR event. The dimensions and the initial conditions for the hydrodynamic volumes and junctions are presented in Tables A 1 and A 2 for the offsite dose and the margin to overfill cases, respectively. The schematic of the B/B RETRAN model is shown in Figure A-1. i 1 MODEL OF THE PRIMARY SYSTEM l l The following major components of the primary system (RCS) were specifically l modeled : { Reactor Vessel (12 Volumes) The reactor vessel model includes the reactor core (Vol.1,2,3), core bypass (Vol. 13), upper plenum (Vol.14), lower plenum (Vol. 27,28), upper downcomer (Vol. 25,39), lower downcomer (Vol. 26,40) and vessel head (Vol. 29). 'T he reactor core and core bypass volumes are provided with one to-one correspondence heat con-ductors (same length as their corresponding fluid volumes) for heat transfer. The core power generation is determined by the RETRAN kinetics model. Page A 2

i Reactor Coolant Piping (9 Volumes) The reactor coolant piping model includes the hot leg (Vol.15,41) and cold leg (Vol. 22,24,36,38,48,50,51). These constitute the piping between the reactor ves-sel and inlet / outlet plenums of the four steam generators. The charging / letdown and safety injection system are modeled as fill junction to the cold legs. Reactor Coolant Pumps The reactor coolant pump model includes pumpi (Vol. 23,2 pumps combined) pump 2 (Vol. 37), and pump 3 (Vol. 49). The Westinghouse pump homologous performance characteristics curves are incorporated in the model. Pump heat (thermal energy generated by the RCS pumps)is added to the pump volumes. Pressurizer The pressurizer model includes the pressurizer surge line (Vol. 30), pressurizer (Vol. 31) and pressurizer spray (Vol. 57). The pressurizer is modeled as a single non equilibrium volume. The pressurizer safety and relief valves which are set to open and reset on pressurizer pressure via trip functions are included in the model.. hianual operation of the PORVs as decribed in Chapters 2,3 and 4 is also modeled. The SRV's discharge to the containment volume (Vol. 32). Accumulators The accumulator model includes accumulatori (Vol. 34), accumulatori line (Vol. 35), accumulator 2 (Vol. 54), accumulator 2 line (Vol. 55), accumulator 3 (Vol. 52) and accumulator 3 line (Vol. 53). Steam Generator The steam generator model includes SGI inlet (Vol. 42), SGI outlet (Vol. 47), SGI tubes (Vol. 151,152,153,154,155,156,157,158), SG3 inlet (Vol.16), SG3 outlet (Vol. 21) and SG3 tubes (Vol. 351, 352,353,354,355,356,357,358). The L steam generator tube volumes are provided with one to one correspondence heat conductors (same length as their corresponding Guld volumes) for heat transfer. The Guld volumes and the conductor transfer areas and volumes of SG3 are three times greater than those of SGl. htODEL OF THE SECONDARY SYSTEh! The following major components of the secondary system were specincally mod. eled : Steam Generator The secondary side of the steam generator model includes SGI (Vol.101) and SO3 (Vol. 301). The steam generator is modeled as a single saturated volume. This simplined noding approach is consistent with the Westinghouse methodol-ogy. Conservative steam generator initial conditions are employed for the analy-sis as described in Sections 3 and 4. Page A 3

F.I a Main Steamlines (MSL) The main steamline model includes MSLI (Vol. 201) and MSL3 (Vol. 401). l These constitute the piping between the steam generator and MSIVs. I Power Operated Relief Valves (PORV) The MSL atmospheric relief valves (one for each MSL) are modeled using the pressure-controlled fill junctions (Jct. 211,711,811). These SG PORVs are set to open and reset on steamline pressure during the initial transient. Manual opera-tion by the operator is also modeled as described in Chapters 2,3 and 4. The SG PORVs discharge to the atmospheric volumes. Safety Relief Valves (SRV) There are Dve SRVs per main steamline, with each SRV having a dif ferent pres-f sure setpoint. The MSL SRVs are modeled using the pressure controlled fill ( junctions (Jct. 205,210). These SRVs are set to open and reset on steamline pressure via the trip functions. Main Feedwater System (FW) The main feedwater system is modeled using the time dependent fill junctions (Jct. 38,66). t Auxiliary Feedwater System (AFW) The auxiliary feedwater system is modeled using the time dependent fill junctions j (Jct.501,503). Different delays of AFW were used to maximize the offsite dose and margin to overfill cases. t it.4 Methodology Utilized with the RETRilN Model OVERVIEW of WESTINGHOUSE MARGIN to OVERFILL METHODOL. [ OGY f Reference I contains a detailed description of the methodology utilized by Wes-tinghouse to address the generic SGTR margin to overtill analysis. For compar-i ison purposes, a brief overview has been shown below: Operator actions identified for SGTR recovery Data gathered on operator action times from simulator and plant Conservative operator action times chosen f Development of the LOFTTRI model for SGTR analysis i Validation of LOFTTRI model Selection of a reference plant suitable for SGTR generic analysis i Page A 4 I

I - Evaluation of base case SGTR margin to overfill with reference plant - Sensitivity 5.tudies conducted to identify conservative assumptions - Equipment failure evaluation - Final analysis of design basis SGTR OVERVIEW of CECO MARGIN to OVERFILL METHODOLOGY The methodology used in this report for the design basis SGTR (margin to over-011) is briefly presented below and is consistent with the methodology presented in reference 1. However, the differences in methodology produce more conserva-tive results for margin to overfill than the Westinghouse methodology. Added conservatism is gained by conducting sensitivity studies with the worst single ac-tive failure included. This was used to measure the effect of various modeling assumptions and their possi e interaction with the worst single active failure. For example: It was found that a'c _ reference 1). However, a ( ~ Ceco sensitivity study showed that under a minimizing decay heat was a'more conservative assumption. %C-Therefore, the raethodology used in this report is consistent with the approved one and contains additional conservatism to ensure appropriate limiting calcu-lations are obtained. Below is a brieflisting of the methodology used by CECO: - Development of a RETRAN model comparable to LOFTTRI for SGTR anal-ysis - Selection of a case suitable for Byron /Braidwood I & 2 SGTR analysis - Equipment failure evaluation * - Operator actions identified for SGTR recovery - Data gathered on operator action times frca simulator and ANS $8.8 Conservative operator action times chosen Sensitivity studies conducted to identify conservative assumptions' - Final analysis of design basis SGTR for Byron /Braidwood Units 1 & 2*

Operator actions with conservative response times were included throughout these evaluation steps l

Page A 5 [

OVERVIEW of CECO and WESTINGHOUSE OFFSITE DOSE METHOD-OLOGY Reference 2 contains a detailed description of the methodology utilized by Wes-tinghouse to address the generic SGTR offsite dose analysis. The issued SER approved of the methodology, with the exception of the lodine transport model which was not explicitly shown. It also stated that X/Q factors could not be ge-nerically approved and site specinc doses would have to be calculated. Following a survqy of the plant analyzed in Reference 2, the generic limiling sin-gle active failure applies D, to the Byron and Braidwood Nuclear Generating Stations. The basis for the applicability to Byron and Braidwood is that the generic analysis operator action times were comparable to those developed by CECO, and also the similarities of the NSSS and balance of plant equipment between the models. Appendix C explicitly shows the Iodine transport models used in the offsite dose case of the SGTR analysis. Major assumptions used in section 5.2 of Reference 2 which are consistent.with the CECO methodology are the sin,cle active failure mentioned above, an{e. 2,C per the SER requirements in Referenc The CECO SGTR methodology used for the Byron and Braidwood offsite dose case analyses was consistent with the approved methodology in Supplement I to WCAP 10698, with the following exception: releases assumed during the 2 to 8 hour period after the tube rupture were not calculated. Releases during the 2 to 8 hour period were not calculated because the operator actions required to achieve cold shutdown conditions do not result in signiReantly large releases. In particular, these post mitigation releases are subject to 10CFR20 limits rather than 10CFR100 limits. The three different methods available per the ES 3 series procedures to perform the transition to cold shutdown are: Post SGTR Cooldown Using Backfill This method drains the ruptured steam generator through the ruptured tube into the RCS by incrementally decreasing RCS pressure below the steam generator pressure. Post SGTR Cooldown Using Blowdown - This method depressurizes the ruptured steam generator by draining it through the blowdown lines. Post SGTR Cooldown Using Steam Dump This method depressurizes the = ruptured steam generator by dumping steam into the condenser via the steam dump system or using the SG PORV. The method used for the transition to cold shutdown is determined by the Tech-nical Support Center (TSC) based upon available plant equipment and system i conditions. Page A 6

Reference 2 calculates the releases and associated dose during this recovery pe-riod as a result of the RCS cooldown and the ruptured steam generator depressurization to RHR coadhions. The Byron and Braidwood ES 3 emergency procedures allow several alteaatives for the RCS cooldown p4ior to ruptured steam generator depressuriution: use of the steam dump valves to the condenser, cooling by opening the irnact steam generator PORV's, or cooling by opening the ruptured steam genera',or PORV. The three alternatives for steam generator depressurization are as listed previously. ,c The would yield the greatest offsire dose so that se'enario was included in the W"estinghouse thodology. Upon a review of the EOP's for3yron and Braidwood, the option of 3'g was only possibic if a calculation of e resulting radioactive concentrations within the exclusion area boundary from that steam release could be shown to stay within the 10CFR20 limits. Based upon the calculated radioactive concentrations in the ruptured steam gen-erator after SGTR mitigation, a controlled release of steam at 1% of the steam generator PORV capacity would violate the 10CFR20 limits by at least 2 orders of magnitude. A release of this type could not be allowed without a direct vio-lation of the procedures and the 10CFR20 limits which apply after the SGTR is mitigated. Throttling of the ruptured swam generator PORV to depressurize_would also be difficult since this valve was for the offsite AC dose case. Manual operator action would be necessary to close thc PORV or to ~ close the PORV's isolation valve,in order to isolate the ruptured steam generator. Therefore, this manual throttling of the PORV on the ruptured steam generator is not credible. Summarizing, the intact steam genciator PORVs were assumed to be used for the RCS cooldown to RHR temperatures during the 2 to 8 hour period after the ac-cident. Since it is not credible to assume a reopening of the ruptured steam gen-erator PORV as explained previously, the backfill method was assumed used for the depressurization of the ruptured steam generator. Radioactive releases from the intact steam generators were estimated and found to be less than the 10CFR20 limits, provided a very conservative cooldown rate is used. Accumu. lated offsite doses occurring after mitigation of the accident resulting from the cooldown and depressurization through the intact steam generator PORV's, if assumed to be of the same order of magnitude as the first cooldown, would only be a small fraction of additional dose (estimated to be approximately 0.10.2% of the total offsite dose) and therefore was not included. Below is a brief listing of the methods used by CECO in the offsite dose case l analysis: Development of a RETRAN model comparable to LOFTTRI for SGTR anal-l ysis - Equipment failure evaluation and chosen to be consistent w'th Ref. 2 Page A 7 1

I Operator actions identified for SGTR recovery Conservative operator action times chosen Conservative initial conditions and model assumptions chosen Final analysis of design basis SGTR for Byron /Braidwood Units 1 & 2 Data gathered on operator action times from simulator and ANS 58.8 Sensitivity studies conducted to verify conservative assumptions t 1 Page A 8

A.5 TABLES ! ABLE A-1 Input Pr a ar Summary (OITsite Dose Case) VOLUME VOLUME M72 VOLUME VOLUME SIZE 'rDt? PRESSURE DESCRIPTION (cu ft) d) (psia) I L.. I i 1 220.7 567.5 2267.6 Lower third of active core length 2 020.7 590.0 2262.9 Middle third of active core length 3 220.7 611.0 2258.0 Upper third of active core length 13 264.5 559.7 2273.5 Core baffle region of RPV 14 1374.1 617.7 2248.7 Upper plenum region of RPV 15 379.2 617.1 2236.5 Hot leg (3 intact loops lumped) 16 442.9 617.1 2232.4 Inlet plenum for intact SG (3 lumped SG) 21 442.9 559.1 2206.5 Outlet plenum for intact SG (3 lumped SG) 22 226.6 559.1 2191.4 Crossover pipes-intact SG to RCP (2 lump) 23 160.3 559.5 2234.8 Reactor coolant pumps (RCP) intact (2 lump) 24 222.4 559.6 2274.5 Cold legs, Intact loops (2 lumped) 25 171.4 559.6 2274.3 Upper downcomer region of RPV (2 lumped) 26 145.8 559.6 2274.6 Lower downcomer region of RPV (2 lumped) 27 555.2 559.7 2276.9 Lower core support / inlet plenum of RPV 28 479.8 559.7 2275.0 Upper core support / inlet plenum of RPV 29 596.9 559.6 2246.9 Upper head volume above outlet plenum (RPV) 30 91.5 617.3 2258.0 Pressurizer surge line 31 1800.0 654.1 2250.0 Pressurizer 32 2.81E6 211.9 14.7 Containment volume 34 2700.0 495.3 654.7 Accumulators for intact loop (2 lumped) 35 78.1 125.0 666.1 Accumulator surge lines (2) for intact loops 36 113.3 559.1 2191.5 Crossover pipe-intact SG to RCP (single) 37 80.1 559.5 2234.9 Reactor coolant pump intact loop (single) 38 112.7 559.6 2274.6 Cold leg intact loop (single) 39 171.4 559.6 2274.4 Uppor downcomer region of RPV (2 lumped) 40 145.8 559.6 2274.6 Lower downcomer region of RPV (2 lumped) 41 126.4 617.1 2236.8 Hot leg, ruptured loop (single) 42 147.6 617.1 2232.7 Inlet plenum to ruptured SG (single) 47 147.6 559.1 2206.8 Outlet plenum from ruptured SG (single) 48 113.3 559.1 2191.6 Crossover pipe-ruptured SG to RCP (single) j 49 80.1 559.5 2234.9 Reactor coolant pump (1) ruptured loop 50 56.3 559.6 2275.0 Cold leg, Rupt. loop (1/2 volume near RCP) 51 56.3 559.6 2274.3 Cold leg, Rupt. loop (1/2 volume near RPV) 52 1350.0 495.3 654.7 Accumulator for ruptured loop (singlo) 53 39.1 125.0 666.1 Accumulator surge line (1) for rupt. 1>op 54 1350.0 495.3 654.7 Accumulator for intact loop (single) 55 39.1 125.0 666.1 Accumulator surge line (1) for intact loop 57 13.2 559.6 2291.1 Pressurizer spray line 101 6314.2 544.2 1000.0 Ruptured steam generator, secondary side 151 138.5 604.9 2724.1 Tubes, vertical upflow section, ruptured SG 152 78.1 587.6 2216.6 Tubes, vertical upflow section, ruptured SG Page A 9

TABLE A 1 (Cont.) Input Parameter Summary (Offsite Dose Case) VOLUME VOLUME VOLUME VOLUME VOLUME SIZE TEMP PRESSURE DESCRIPTION (cu ft) (F) (psia) l I I I 153 42.0 581.0 2212.5 Tubes, vertical upflow section, ruptured SG 154 72.7 575.9 2209.0 Tubes, U bend section, ruptured SG j 155 42.0 571.4 2208.0 Tubes, vert. downflow section, ruptured SG 156 78.9 567.6 2207.4 Tubes, vert, downflow section, ruptured SG 157 56.0 563.8 2206.7 Tubes, preheater section, ruptured SG 158 82.6 560.8 2206.3 Tubes, preheater section, ruptured SG 201 680.1 545.0 1001.1 Main steamline from ruptured SG 301 18942.7 544.2 1000.0 Intact steam generator, secondary side 351 415.6 604.9 2223.7 Tubes, vert. upflow section, intact SG(3) 352 236,.7 587.6 2216.2 Tubes, vert, upflow section, intact SG(3) 353 125.9 581.0 2212.2 Tubes, vert, upflow section, intact SG(3) 354 218.2 576.0 2208.6 Tubes, U bend section, Intact SG(3) 355 125.9 571.5 2207.7 Tubes, vert, downflow section, intact SG(3) 356 236.7 567.6 2207.1 Tubes, vert. downflow section. intact SG(3) 357 167.9 562.2 2206.4 Tubes, preheater section, intact SG(3) 358 247.7 559.1 2206.0 Tubes, preheater section, intact SG(3) 401 2040.2 545.0 1001.1 Main steamlines from intact SG(3) 410 1.00E8 211.9 14.7 Atmospheric volume 710 1.00E9 211.9 14.7 Atmospheric volume i I I l i l Page A.10

TABLE A-1 (Cont.) Input Parameter Summary (Offsite Dose Case). JUNCT JUNCT JUNCT JUNCTION FLOW FLOW AREA DESCRIPTION (1bm/sec) (sq ft) l I I 1 39842.1 31.84 Upper inlet plenum to lower active core in RPV 2 39842.1 50.95 Lower active core to middle active core in RPV 3 39842.1 50.95 Middle active core to upper active core in RPV 13 201.5 2.40 Core baffle region to upper inlet plenum in RPV 14 39842.1 50.95 Upper active core to upper outlet plenum in RPV 16 100.8 0.52 Upper downcomer to core baffle region in RPV 17 29926.9 25.76 Upper outlet plenum in RPV to intact hot leg 18 30229.2 15.72 Intact hot leg to Anlet plenum of intact SG 24 20152.8 10.48 Intact SG outlet plenum to intact crossover (single) 25 20152.8 10.48 Intact loop crossover to intact RCP (single) 26 20152.8 8.25 Intact loop RCP to intact loop cold leg (single) 27 20152.8 13.55 Intact (1) loop cold leg to upper downcomer in RPV 28 19820.3 12.75 Upper downcomer to lower downcomer in RPV 29 19819.3 12.75 Lower downcomer to lower core support / inlet in RPV 30 39640.6 49.30 Lower inlet plenum to upper core support / inlet in RPV l 31 30.2 0.01 Upper downcomer to upper head region in RPV 32 60.5 0.92 Upper head region to upper outlet plenum in RPV l 33 0.0 0.69 Ruptured loop hot leg to pressurizer surge line 34 0.0 0.69 Pressurizer surge line to pressurizer l 35 0.0 0.01 Pressurizer safety valves l 36 0.0 0.06 Pressurizer safety valves i 37 -3153.1 1.00 Intact SG to main steamlines for (3) intact SG l 38 3153.1 1.00 Feedwater for (3) intact SG 39 302.3 0.04 Leakage from upper downcomer in RPV to intact hot les 40 100.8 0.04 Leakage from upper downcomer in RPV to rupt. hot lg 41 10076.4 5.24 Intact SG outlet plenum to intact crossover (2) 42 10076.4 5.24 Intact crossover (2) to intact RCP 43 10076.4 4.12 Intact RCP to intact cold legs (2) 44 10076.4 6.78 Intact cold legs (2) to upper downcomer in RPV l 45 -10076.4 16.20 Upper downcomer(1/2 region) to upper downconer(1/2 reg) 46 1.0 13.65 Lower downcomer(1/2 region) to lower downcomer(1/2 reg) 47 19820.3 12.75 Upper downtomer to lower downcomer in RPV 48 19821.3 12.7% Lower downcomer to lower inlet plenum in RPV 49 9975.6 8.59 Upper plenum in RPV to ruptured loop hot leg i l 50 10076.4 5.24 Ruptured loop hot leg to ruptured SG inlet plenum 56 10076.4 5.24 Ruptured SG outlet plenum to ruptured crossover pipe 57 10076.4 5.24 Ruptured loop crossover pipe to ruptured loop RCP t l 58 10076.4 4.12 Ruptured loop RCP to 1/2 section of ruptured cold leg 59 10076.4 4.27 Ruptured loop cold leg to ruptured loop cold leg 60 10076.4 6.78 Ruptured loop cold le3 to upper downcomer in RPV 61 30.2 0.01 Upper downcomer to upper head region in RPV 62 0.0 0.84 Intact loop accumulator to accumulator line(2 lumped) Page A ll

l TABLE A-1 (Cont.) Input Parameter Summary (Offsite Dose Case) L JUNCT JUNCT JUNCT JUNCTION FLOW FLOW AREA DESCRIPTION 3 (1be/sec) (sq ft) l I I 63 0.0 0.84 Intact loop accumulator line to intact cold les (2) 64 0.0 0.42 Intact loop accumulator to accumulator line (single) 65 0.0 0.42 Intact loop accumulator line to intact cold leg (1) 66 1051.0 1.00 Feedwater for ruptured steam generator 67 -1051.0 1.00 Main steneline from ruptured SG to turbine 68 0.0 4.27 Rupt. loop cold leg to containment (LOCA valve, N/A) 69 0.0 4.27 Rupt. loop cold leg to containment (LOCA valve, N/A) 70 0.0 0.42 Ruptured loop accumulator to rupt. loop accum. line 71 0.0 0.42 Ruptured loop accum. line to ruptured loop cold leg 72 0.0 0.07 Intact loop cold les to pressurizer spray line 73 0.0 0.07 Pressurizer spray line to pressurizer, (valve) 74 100.8 0.52 Upper downcomer to core baffle region in RPV 75 0.0 0.55 Safety Injection to intact (2 lumped) loop cold leg 76 0.0 0.28 Safety Injection to ruptured loop cold leg 85 0.0 0.28 Safety Injection to intact (single) loop cold les 86 0.0 0.01 Pressurizer to containment, (pressurizer PORV) 151 10076.4 11.01 Ruptured SG inlet plenum to ist SG tube segment 152 10076.4 11.01 1st SG tube segment to 2nd SG tube segment (ruptured) 153 10076.4 11.01 2nd SG tube segment to 3rd SG tube segment (ruptured) 154 10076.4 11.01 3rd SG tube segment to 4th SG tube segment (ruptured) 155 10076.4 11.01 4th SG tube segment to 5th SG tube segment (ruptured) 156 10076.4 11.01 5th SG tube segment to 6th SG tube segment (ruptared) 157 10076.4 11.01 6th SG tube segment to 7th SG tube segment (ruptured) 158 10076.4 11.01 7th SG tube segment to 8th SG tube segment (ruptured) 159 10076.4 11.01 8th SG tube seguent to ruptured SG autlet plenum 186 0.0 0.01 Pressurizer to containment, (pressurizer PORV) 199 0.0 5.00 Main steamline ruptured SG to steam dump (N/A) 201 1051.0 4.20 Ruptured SG to Main steamline for ruptured SG 205 0.0 1.00 Main steamline (ruptured) to atmosphere (SG safety) 210 0.0 1.00 Main steamline (intact) to atmosphere (SG safety) 211 0.0 0.14 Main steamline (intact) to atmosphere (SG PORV) 351 30229.2 33.03 Intact SG inlet plenum to ist SG tube segment 352 30229.2 33.03 1st SG tube segment to 2nd SG tube segment (intact) 353 30229.2 33.03 2nd SG tube segment to 3rd SG tube segment (intact) 354 30229.2 33.03 3rd SG tube segment to 4th SG tube segment (intact) 355 30229.2 33.03 4th SG tube segment to 5th SG tube segment (intact) 356 30229.2 33.03 Sth SG tube segment to 6th SG tube segment (intact) 357 30229.2 33.03 6th SG tube segment to 7th SG tube segment (intact) 358 30229.2 33.03 7th SG tube segment to 6th SG tube segment (intact) Page A 12

r l TABLE A-1-(Cont.) ,e Input Parameter Summary (Offsite Dose Case) i JUNCT JUNCT JUNCT JUNCTION FLOW FLOW AREA DESCRIPTION (Ibe/sec) (sq ft) I l_ l-359 30229.2 33.03 8th SG tube segment to intact SG outlet plenum 399 0.0 15.00 Main steamline intact SG to steam dump (N/A) f 401 3153.1 12.60 Intact SG to Main stenaline for Intact SG 501 0.0 1.00 Auxiliary feedwater for ruptured steam generator 503 0.0 1.00 Auxiliary feedwater for intact steam generator l 711 0.0 0.05 Main steaaline (ruptured) to atmos. vol.(SG PORV) 811 0.0 1.00 Main steksline (intact) to atmosphere (SG PORV) l 900 0.0 0.002 Ruptured SG inlet plenus to long end of ruptured tube l 901 0.0 0.002 Long end of ruptured tube to ruptured SG } 902 0.0 0.002 Ruptured SG outlet plen. to short end of rupt. tube 903 0.0 0.002 Short end of ruptured tube to ruptvreo SG l 904 0.0 2.5E-5 8th SG tube segment to intact SG(for

PM !sakage)

ABBREVIATIONS: RPV - reactor pressure vessel l RCP - reactor coolant pump l j SG - steam generator PORV - power operated relief valve LOCA - loss of coolant accident N/A - not applicabla to steam generator tube rupture analysis i GPM - gallons per n!.nute l l h l l i j 4 t i i t f i Page A 13 1

I TABLE A 2 l Input Parameter Summary (Margin to Overfill Case) VOLUME VOL'JME VOLUME VOLUME VOLUME SIZE TEMP PRESSURE DESCRIPTION (cu ft) (F) (psia) l I I i 1 220.7 546.8 2232.9 Lower third of active core length 2 220.7 570.5 2228.2 Middle third of active core length 1 3 220.7 592.8 2223.4 Upper third of active core length 13 264.5 538.5 2238.5 Core baffle region of RPV l 14 1374.1 599.9 2214.3 Upper plenum region of RPV 15 379.2 599.3 2202.6 Hot leg (3 intact loops lumped) 16 442.9 599.3 2198.5 Inlet plaaum for intact SG (3 lumped SG) 21 442.9 538.0 2173.3 Outlet plenum for intact SG (3 lumped SG) 22 226.6 537.9 2158.9 Crossover pipes-intact SG to RCP (2 lump) 23 160.3 538.4 2205.1 Reactor coolant pumps intact loop (2 lump) 24 222.4 538.5 2247.8 Cold legs, intact loops (2 lumped) 25 171.4 538.5 2247.6 Upper downcomer region of RPV (2 lumped) 26 145.8 538.5 2248.2 Lower downcomer region of RPV (2 lumped) 27 555.2 538.5 2250.5 Lower' core support / inlet plenum of RPV a 28 479.8 538.5 2240.2 Upper core support / inlet plenum of RPV 29 596.9 538.4 2212.4 Upper head volume above outlet plenum (RPV) [ 30 91.5 599.4 2223.1 Pressurizer surge line 1 31 1800.0 651.7 2215.0 Pressurizer 32 2.81E6 211.9 14.7 Containment volume 34 2700.0 495.3 654.7 Accumulators for intact loop (2 lumped) 35 78.1 125.0 666.1 Accumulator surge lines (2) for intact loops 36 113.3 537.9 2158.9 Crossover pipe-intact SG to RCP (single) 37 80.1 538.4 2205.2 Reactor coolant pump (1) intact loop 38 112.7 538.5 2247.9 Cold leg intact loop (single) 39 171.4 538.5 2247.7 Upper downcomer region of RPV (2 lumped) 40 145.8 538.5 2248.2 Lower downcomer region of RPV (2 lumped) 41 126.4 599.3 2202.9 Hot leg, ruptured loop (single) 42 147.6 599.3 2198.9 Inlet picnum to ruptured SG (single) 47 147.6 538.0 2173.6 Outlet plenum from ruptured SG (sinr,le) 48 113.3 537.9 2159.0 Crossover pipe-ruptured SG to RCP (single) { 49 80.1 538.4 2205.2 Reactor coolant pump (1) ruptured loop 50 56.3 538.5 2248.2 Cold leg Rupt. loop (1/2 volume near RCP) 51 56.3 538.5 2247.6 Cold leg, Rupt. loop (1/2 volume near RPV) 52 1350.0 495.3 654.7 Accumulator for ruptured loop (single) 53 39.1 125.0 666.1 Accumulator surge line (1) for rupt. loop 54 1350.0 495.3 654.7 Accumulator for intact loop (single) 55 39.1 125.0 666.1 Accumulator surge line (1) for intact loop 57 13.2 538.5 2263.3 Pressurizer spray line 101 6314.2 521.6 827.0 Ruptured steam generator, secondary side 151 138.5 586.3 2190.3 Tubes, vertical upflow section, ruptured SG 152 78.9 $68.0 2182.8 Tubes, vertical upflow section, ruptured SG Page A-14

TABLE A 2 (Cont.) Input Parameter Summary (Margin to Overfill Case) VOLUME VOLUME VOLUME VOLUME VOLUME SIZE TEMP PRESSURE DESCRIPTION (cu ft) (F) (psia) I I I I 153 42.0 561.0 2178.7 Tubes, vertical upflow section, ruptured SG j 154 72.7 555.7 2175.2 Tubes, U bend section, ruptured SG 155 42.0 551.0 2174.3 Tubes, vert. downflow section, ruptured SG 156 78.9 546.9 2173.8 Tubes, vert, downflow section, ruptured SG 157 56.0 543.0 2173.3 Tubes, preheater section, ruptured SG l 158 82.6 539.7 2173.0 Tubes, preheater section, ruptured SG 201 680.1 522.6 828.3 Main steamline from ruptured SG 301 18942.7 521.6 827.0 Intact steam generator, secondary side i 351 415.6 586.3 2190.0 Tubes, vert. upflow section, intact SG(3) 352 236.7 568.0 2182.5 Tubes, vert. upflow section, intact SG(3) 353 125.9 561.1 2178.4 Tubes, vert, upflow section, intact SG(3) 354 218.2 555.8 2174.9 Tubes, U bend section, Intact SG(3) 355 125.9 551.0 2174.0 Tubes, vert. downflow section, intact SG(3) 356 236.7 547.0 2173.5 Tubes, vert, downflow section, intact SG(3) 351 167.9 541.2 2173.0 Tubes, preheater section, intact SG(3) 358 247.7 537.9 2172.7 Tubes, preheater section, intact SG(3) 401 2040.2 522.6 828.3 Main steamlines from intact SG(3) 410 1.00E8 211.9 14.7 Atmospheric volume 710 1.00E9 211.9 14.7 Atmospheric volume i f I l Page A-15 f

TABLE A 2 (Cont.) Input Parameter Summary (Margin to Overfill Case) JUNCT JUNCT JUNCT JUNCTION FLOW FLOW AREA DESCRIPTION (1bm/sec) (sq ft) l I i 1 39842.1 31.84 Upper inlet plenum to Iwer active core in RPV 2 39842.1 50.95 Lower activa core to middle active core in RPV 3 39842.1 50.93 Middle active core to upper active core in RPV 13 201.5 2.40 Core baffle region to upper inlet plenum in RPV 14 39842.1 50.95 Upper active core to upper outlet plenum in RPV 16 100.8 0.52 Upper downcomer to core baffle region in RPV 17 29926.9 25.76 Upper outlet plenum in RPV to intact hot leg 18 30229.2 15.72 Intact hot leg to inlet planum of intact SG 24 20152.8 10.48 Intact SG outlet plenum to intact crossover (single) 25 20152.8 10.48 Intact loop crossover to intact RCP (single) 26 20152.8 8.25 Intact loop RCP to intact loop cold leg (single) j 27 20152.8 13.55 Intact (1) loop cold lieg to upper downcomer in RPV l 28 19820.3 12.75 Upper dortcomer to lower downcomer in RPV 29 19819.3 12.75 Lower downcomer to lower core support / inlet in RPV 30 39640.6 49.30 Lower inlet plenum to upper cc m support / inlet in RPV 31 30.2 0.01 Upper downcomer to upper head region in RPV 32 60.5 0.92 Upper head recion to upper outlet plenum in RPV 33 0.0 0.69 Ruptured loop hot les to pressurizer surge line 34 0.0 0.69 Pressurizer curge line to pressurizer 35 0.0 0.01 Pressurizer safety valves 36 0.0 0.06 Pressurizer safety valves 37 d153.1 1.00 Ictact SG to main steaulines for 3 intact SG 38 3153.1 1.00 Feedwater for (3) intact SG 39 302.3 0.04 Leakage from upper downcomer in RPV to intact hot leg. 40 100.8 0.04 Leakage from upper downcomer in RPV to rupt. hot leg 41 10076.4 5.24 Intact SG outlet plenum to intact crossover (2) 42 10076.4 5.24 Intact crossover (2) to intact RCP 43 10076.4 4.12 Intact RCP to intact cold legs (2) 44 10076.4 6.78 Intact cold legs (2) to upper downcomer in RPV 45 -10076.4 16.20 Upper downcomer(1/2 region) to upper downcomer(1/2 reg) 46 1.0 13.65 Lower downcomer(1/2 region) to lower downcomer(1/2rea) 47 19820.3 12.75 Upper downcomer to lower downcomer in RPV 48 19821.3 12.75 Lower downcomer to lower inlet plenum in RPV 49 9975.6 8.59 Upper plenum in RPV to ruptured loop hot leg 50 10076.4 5.24 Ruptured loop hot leg to ruptured SG inlet plenum 56 10076.4 5.24 Ruptured SG outlet plenum to ruptured crossover pipe 57 10076.4 5.24 Ruptured loop crossover pipe to ruptured loop RCP 58 10076.4 4.12 Ruptured loop RCP to 1/2 section of ruptured cold les 59 10076.4 4.27 Ruptured loop cold leg to ruptured loop cold leg f ( Page A 16 f (

I TABLE A 2 (Cont.) Input Parameter Summary (Margin to Overfill Case) l JUNCT JUNCT JUNCT JUNCTION FLOW FLOW AREA DESCRIPTION (1bm/sec)-(sq ft) I I I 60 10076.4 6.78 Ruptured loop cold leg to upper downcomer in RPV 61 30,2 0.01 Upper downcomer to upper head region in RPV 62 0.0 0.84 Intact inop accumulator to accumulator 11ne(2 lumped) 63 0.0 0.84 Intact loop accumulator line to intact cold leg (2) 64 0.0 0.42 Intact loop accumulator to accumulator line (single) 65 0.0 0.42 Intact loop accumulator line to intact cold leg (1) 66 1051.0 1.00 Feedwater for ruptured steam generator 67 -1051.0 1.00 Main steamline from ruptured SG to turbine 68 0.0 4.27 Rupt. loop cold leg to containment (LOCA valve, N/A) 69 0.0 4.27 Rupt. loop cold leg to containment (LOCA valve, N/A) 70 0.0 0.42 Ruptured loop accum, to ruptured loop accum. line 71 0.0 0.42 Ruptured loop accum. line to ruptured loop cold leg 72 0.0 0.07 Intact loop cold leg to pressurizer spray line 73 0.0 0.07 Pressurizer spray line to pressurizer, (valve) 74 100.8 0.32 Upper downcomer to core baffle region in RPV ) 75 0.0 0.55 Safety Injection to intact (2 lumped) loop cold Icg 76 0.0 0.28 Safety Injection to ruptured loop cold leg 85 0.0 0.28 Safety Injection to intact (single) loop cold leg 86 0.0 0.01 Pressurizer to containment, (pressurizer PORV) 151 10076.4 11.01 Ruptured SG inlet plenum to ist SG tube segment 152 10076.4 11.01 1st SG tube segment to 2nd SG tube segment (ruptured) 153 10076.4 11.01 2nd SG tube segment to 3rd SG tube segment (ruptured) 154 10076.4 11.01 3rd SG tube segment to 4th SG tube segment (ruptured) 155 10076.4 ?.1. 01 4th SG tube segmant to 5th SG tube segment (ruptured) 156 10076.4 11.01 5th SG tube segment to 6th SG tube segment (ruptured) 157 10076.4 11.01 6th SG tube segment to 7th SG tube segment (ruptured) 158 10076.4 11.01 7th SG tube segment to 8th SG tube segment (ruptured) 159 10076.4 11.01 8th SG tube segment to ruptured SG outlet plenum 175 0.0 0.55 SI throttled flow to intact (2 lumped) loop cold leg 176 0.0 0.** SI throttled flow to ruptured loop cold leg 185 0.0 0.28 SI throttled flow to intact (single) loop cold leg 186 0.0 0.01 Pressurizer to containment, (pressurizer PORV) ~9 0.0 5.00 Main steamline ruptured SG to steam dump (N/A) 201 1051.0 4.20 Ruptured SG to Main steamline for ruptured SG 205 0.0 1.00 Main steamline (ruptured) to atmosphere (SG safoty) 210 0.0 1.00 Main steamline (intact) to atmosphere (SG safety) 211 0.0 0.09 Main steamline (intact) to atmosphere (SG PORV) 351 30229.2 33.03 Intact SG inlet ple.2um to ist SG tube segment' 352 30229.2 33.03 1st SG tube seg=ent to 2nd SG tube segment (intact) 353 30229.2 33.03 2nd SG tube segment to 3rd SG tube segment (intact) 354 30229.2 33.03 3rd SG tube segment to 4th SG tube segment (intact) 355 30229.2 33.03 4th SG tube segment to 5th SG tube segment (intact) Page A 17 {

TABLE A 2 (Cont.) Input Parameter Summary (Margin to Overfill Case) JUNCT JUNCT JUNCT JUNCTION f) FLOW FLOW AREA DESCRIPTION (1bm/sec) (sq ft) l I I 356 30229.2 33.03 5th SG tube segment to 6th SG tube segment (intact) 357 30229.2 33.03 6th 3G tube segment to 7th SG tube segment (intact) 358 30229.2 33.03 7th SG tube segment to 8th SG tube segment (intact) 359 30229.2 33.03 8th SG tube segment to intact SG outlet plenum 399 0.0 15.00 Main steamline intact SG to steam dump (N/A) J 401 3153.1 12.60 Intact SG to Main steamline for Intact SG 501 0.0 1.00 Auxiliary feedwater for ruptured steam generator 503 0.0 1.00 Auxiliary feedwater for intact steam generator 711 0.0 1.00 Main steamline (ruptured) to atmos. vol.(SG PORV) 811 0.0 1.00 Main steamline (intact) to atmosphere (SG PORV) 900 0.0 0.002 Ruptured SG inlet plenum to long end of ruptured tube ( 901 0.0 0.002 Long and of ruptured tube to ruptured SG l 902 0.0 0.002 Ruptured SG outlet plen. to short and of rupt. tube 903 0.0 0.002 Short end of ruptured tube to ruptured SG 904 0.0 2.5E-5 8th SG tube segment to intact SG (for 1 GPM leakage) i ABBREVIATIONS: PDV - reactor pressure vessel 4<CP - reactor coolant pump SG - steam generator PORV - power operated relief valve LOCA - loss of coolant accident N/A not applicable to steam generator tube rupture analysis GPM - gallons per minute SI - safety injection o Page A IS

A.6 FIGURES FIGURE A 1 f B/B RETRAN Model Ul s't al 5 k h si}} =a c,in =z ,m

"'7 T-l g h(M0 [/d 0

i ~ 'I iii j j 8 3'

l@

t r o kMe@ m [ O L Me@ @ 3 k l c/'8tr (~

f - g v

5 - 2C-lfi$ P +m# m s 4._ .i> [! 9- @-r O - cqg y d-m.'e m 'e_ h -Q4-@ s J* 1 'N ( x 4 @J.'-D-@

b. t a

.f.I g O r g 7 I ia GN NM D i ) g 5 y JD g q '} { NA a 9 13 Page A-19

Appendix B. RUPTURED TUBE FLOW MODEL l B.1 Introduction One of the most critical parameters in a SGTR transient is the ruptured tube now. To calculate the ruptured tube Dow, the model is required to conservatively simulate the now characterist:cs (choked or friction limited) and to effectively predict results for a long transient, in t his analysis, a control system was developed to control the Dow through the 011 junctions (for both long and short sections of the tube), as a function of RCS (primary) to steam generator (secondary) differential pressure. This is necessary due to the limitation of the RETRAN code to effectively model the ruptured tube Gow explicitly. A friction limited correlation was implemented to calculate the ruptured tube now, for both the long and short sections of the ruptured tube. 3.2 Ruptured Tube Flow Characteristics The break now resulting from the rupture of a steam generator tube is a function of three elements : I) pressure differential,2) tube geometric characteristics (L/D, ) surface roughness, etc), and 3) initial subcooled nature of RCS fluid (in the tube). The break Dow is largely dependent on the tube wall friction (friction limited now). However, given the range of primary to secondary pressure differential j (5001500 psid) during a typical SGTR event, the break now may experience ei-ther single phase (sonic) or two phase choking. This is true for both the long and short sections of the ruptured tube, it.hould be noted, that the friction limited correlation would predict more conservative Dow rates than those by a choke Dow correlation. This is due to to the restriction and limitation placed on a "choked Dow". Further comparison studies of existing critical now correlations, that may be ap-plicable to the SGTR break Dow, showed these critical Dow correlations would provide a fairly accurate prediction for the break Dow. Therefore, it was con-cluded the friction limited correlation would be more conservative. It was concluded, that based on the range of the primary and secondary condi-tions during a SGTR esent and ruptured tube L/D's, a friction limited corre-lation would provide a conservative prediction of,he ruptured tube Dow rate and would be used for this analysis. B.3 Friction-Limited Equations The Darcyi correlation for the ruptured tube Dow calculation is given as follows: G = ( 2g x Rho x DP x 144/(Kent + Kexit + fL/D))**0.5 I Page B-1

where: G = mass velocity, Ibe/ft**2-sac g = gravitational constant = 32.2 ft/sec**2 Rho = fluid density, Ibm /ft**3 DP = pressure differential (RCS to SG), psi 144 = conversion constant, in**2/ft**2 Kent = entrance resistance coefficient (form loss) = 0.5 Kexit = exit resistance coefficient (form loss) = 1.0 f = friction factor (of tube) = 0.0118 L = tube length, L-Short = 21 in; L-Long = 577.57 in D = tube internal diameter = 0.664 in L/D = 31.63 for short tube L/D = 869.83 for long tube f h f Page B 2

( Appendix C. OFFSITE DOSE ASSESSMENT i C.1 Objective The purpose of this appendix is to describe the techniques used to determine thyroid inhalation and whole body exposure doses at the Exclusion Area Bound-ary (EAB) and the Low Population Zone (LPZ) distance from radionuclides re-leased during a postulated steam generator tube rupture accident at the Byron and Braidwood sites. C.2 Method ilnd ilssumptions Tu analysis of the radionuclide release during a postulated steam generator tube ruptore accident is based on the guidance given in section 15.6.3 "Radiological Consequences of Steam Generator Tube Failure (PWR)" of the U.S. Nuclear Regulatory Commission's Standard Review Plan (SRP), NUREG 0800 (Ref.1). As indicated in the SRP, two distinct accident scensrios are considered : 1) the preaccident iodine spike case where it is assumed that an lodine spike has occured l sometime prior to the steam generator tube rupture, and 2) the cor. current iodine ) spike case where it is assumed that the tube rupture causes an iodine spike. Here an iodine spike is deGned as a temporary increase in the iodine primary coolant activity caused by pressure and temperature transients in the primary coolant. ) The analytical models and assumptions used for these two cases are discussed below. Preaccident Iodine Spike Case :

1) For the preaccident lodine spike case, the initial primary coolant iodine activity concentration is based on the maximum technical speciGcatior. limit of 60 uci/gm 1131 equivalent as per section Ill.6.(a) of the SRP. Primary coolant concen-tration values derived using this assumption are given in Byron /Braidwood Final Safety Analysis Report (Ref. 2) Table 15.0-10, Amendment 46, January 1985.

Note that this table contains both iodine and noble gas concentrations. These are / l both used in the preaccident iodine spike release analysis.

2) Prior to the accident, the iodine concentration in the secondary coolant is based on the design basis assumption of 0.1 uci/gm 1131 equivalent. Concentration values for this assumption are given in FSAR Table 15.0-9, Amendment 47 April 1986. Note that no noble gas nuclides are entrained in the secondary coolant during normal operat.'on.

3) A diagram of the model used to analyze the radionuclide release for the pre-accident iodine spike case is shown in Figure C-1. Here the Grst compartment represents the primary coolant, whici; is assumed to leak into the ruptured steam generator at a rate mi and into the intact steam generators at a rate m2. Fo!-

lowing the steam generator tube rupture, the total leak rate to the intact steam ( generators is assumed to be the maximum technical speciGcation Hak rate of 1 Page C 1

1 l l 1 gpm. The time dependent mass flow rates derived from thermal hydraulic ana-lyses are presented in Figures 4 20. A fraction, Ff, of the primary coolant that Dows through the ruptured tube Dashes to steam. The remainder is assumed to be uniformly mixed in the sec-ondary coolant mass in the ruptured steam generator. Of the primary liquid that Dashes to steam, some fraction may immediately be exhausted with the main steam Dow, while the remainder is somehow entrained in the secondary coolant mass. Since the fraction of the Dashed primary coolant that is immediately ex. hausted cannot be easily quantined, this parameter, Ffr is treated as a free var-lable, it is ahu a:sumed there is no additional radionucilde removalin the steam space above the liquid level in the steam generator. The redlonuclide release rate from the ruptured steam generator consists of ac-tivity that is immediately released and activity that is carried from the steam generator water in the remaining steam exhausted through the safety relief valves. Noble gas radionuclides, and the iodines in the primary coolant mass that Dashes J to steam are assumed to be exhausted immediately. For lodines mixed in the steam generator liquid, the ratio of the activity concentration in the exhaust steam to that in the secondary coolant is the partition factor, PFI which is as-sumed to be 1/100 per section 111.10 of the SRP. This is consistent with the carry over of iodine from the steam generator water to the steam under normal operating conditions. The steam now rate from and the liquid mass in the rup-tured steam generator during the course of the accident and the fraction ofleaked primary liquid that Dashes to steam are given in Figures 4 5,4 9, and 4 21 re-l spectively. For the intact steam generators, it is assumed that the leaked primary coolant is completely mixed in the secondary liquid with no immediate release of any Cashed steam. Radionuclides released from these generators are carried with the l normal steam now at a concentration determined by the partition factor, PF2. For iodine radionuclides the partition factor is assumed to be 1/100. For noble gas radionuclides a partition factor of 1.0 is used. The steam Dow rate and the i liquid mass of the intact steam generators during the course of the accident are determined by thermal hydraulic analyses. These parameters are shown in Fig-i I urcs 4 6 and 4 22. The differential equations describing the activity changes in the primary coolant and the steam generator liquid masses are given following this text. These equations are couched in terms of activity concentrations to simplify the release j rate expressions, if it is assumed that the mass now rates and liquid masses can be approximated by constant average values over a Unite time interval, then the differential equations can be solved using Laplace Transforms. The time de-pendent release rates are then integrated to determine the radionuclide release over the interval. Summing these over the course of the accident gives the total release for each radionuclide. Page C-2 l

L Differential Eaustions For Preaccident Iodine Soike Mode) (tidtit2) f

0) Primary Coolant Activity Concentration :

j dNo/dt = -El(No/Mo) - E2(No/Mo) - A No cor.t)

No(t)/Mo esco/dt = -(($1,Mo) + (E2/Mo) + A ) Co = - OC Co kpply Laplace transforms -

a $o(s) - Co(t's) = - of. Co(s) $o(s)=Co(t1)/(s+M) Apply inverse transforms to obtain solution - Co(t)'= Co(ti) exp(-o((t-tl))

1) Ruptured Steam Generator Liquid Activity Concentration dN1/dt = (1-Ff Tfr)El Co(t) - 51 PF1(N1/M1) - A N1

) Cl(t) = N1(t)/M1 dC1/dt = (1-Ff Fir)(51/M1)Co - (51 PF1/M1 + A )C1 e 2 As Apply Laplace transforms - A A A s Cl(s) - Cl(tl) = (1-Ff Fir)(E1/M1) Co(s) - 4, C1(s) ACl(s) = C1(ti)/(s+p,) + (1-Ff Fir)(il/M1) Co(ti) / ((s+d)(s+ ge)) Apply inverse transforms to obtain solution - Cl(t)=Cl(ti)exp(-g,(t-t1))+ (1-Ff Fir)(E1/M1) Co(ti) x ( exp(-#,(t-tl)) - exp(-o((t-ti)))/( M - #,)

2) Intact Steam Generator Liquid Activity Concentration :

dN2/dt = A2 Co(t) - 52 PF2(N2/M2) - A N2 C2(t) = N2(t)/M2 Page C-3

f \\ dC2/dt=(m2/M2)Co-($2PF2/M2+A)C2 Apply Laplace transforms - 4 4 a l s C2(s) - C2(ti) = (s2/M2) Co(s) - 4a C2(s) C2(s) = C2(t1)/(s+ 4) (52/M2) Co(ti) / ((s+M)(s+ g,)) C2(t) = C2(tl) exp(-((t-ti)) + (m2/M2) Co(tl) x ( exp(- ((t-ti)) - exp(- A(t-ti)))/( n - ga) Release Rates : $1(t)=TfFfralCo(t)+$1'PF1C1(t) d2(t)=$2PF2C2(t) i Intearated Release : ) P. R1(tl,t2) = R1(t) dt 2 2 Ff Ffr $1 Co(t) dt + S1 PF1 C1(t) dt = Il tl t R2(tl,t2) = R2(t) dt I att S2 PF2 (C2(t) dt = itt Total Release for the Time Period t1 to t2 : RTot(tl t2) = R1(tl.t2) + R2(tl,t2)

2

= Ff Ffr il Co(ti) I exp(-A(t-ti)) dt + Jif 51PF1Cl(t!) xp(-g,(t-t1)) dt + Ytl 51PF1Co(tl)(1-FfFit)(51/M1)/(K-4)x 62 (exp(-/,(t-tl))-exp(-0((t-ti))) dt f I Page C 4

l [ f %3 l 52PF2C2(t!) exp(-4(t-t1))dt+ Att 52PF2Co(t!)(E2/M2)/(A-p,)x 4 etz(exp(-&(t-ti))-exp(-o((t-ti))) dt Atl = Ff Ffr El Co(ti) (1 - exp(-o((t2-tl)))/M + il PF1 C1(tl) (1 - exp(- g,(t2-ti)))/4, + t $1 PF1 Co(t1) (1-Ff Fir)(E1/M1)/(o(-A,) x (((1 - exp(-$,(t2-ti)))/p,) - ((1 - exp(- e((t2-ti)))/g )) + ) 52 PF2 C2(ti) (1 - exp(-g,(t2-ti)))/g, + $2PF2Co(t!)($2/M2)/(el-g,) x 1 (((1 - exp(-p,(t2-ti)))/4,) - ((1 - exp(-o((t2-ti)))/o()) l [ 1 Page C-5

Concurrent lodine Spike Case :

1) For the concurrent lodine spike case, it is assumed that the iodine release rate from the fuel rods increases to a value 500 times greater than the assumed normal operation release rate. Normal operation Ossion product escape rate coefficients (1/sec) are shown in B/B FSAR Table 11.1 1, Amendment 21, July 1979 and the initial core activity inventories (Curies) are listed in B/B FSAR Table 15.0 8 Amendment 49, October 1987. Note that the enhanced release rate only applies to the lodines, not to the noble gases.

2) Prior to the accident, the lodine and noble gas activity concentrations in the primary coolant are assumed to be those given in B/B FSAR Table 12.2 2 Amendment 40, November 1982.

3) Prior to the accident, the iodine concentration in the secondary coolant is based on the design basis assumption of 0.1 ucl/gm 1131 equivalent. Concentration values for this assumption are given in Table 15.0-9, Amendment 47, April 1936.

Note that no noble gas nuclides are entrained in the secondary coolant during normal operation.

4) A diagram of the model used to analyze the radionuclide release for the con-current lodins spike case is shown in Figure C 2. Here, the core is shown sur-rounded by the first compartment which represents the primary coolant. The 1

radionuclides released from the design basis 1% failed fuel in the core are as-sumed to be instantaneously mixed in the primary coolant before leaking into the l ruptured steam generator, at a rate ml, and into the intact steam generators, at a rate m2. Following the steam generator tube rupture, the totalleakrate to the intact steam generators is assumed to be the maximum technical speci0 cation leak rate of I gpm. The time dependent mass now rates derived from thermal hydraulic analyses are presented in Figures 4 20. A fraction, Ff, of the primary coolant that Dows through the ruptured tube Dashes to steam. The remainder is assumed to be uniformly mixed in the sec-ondary coolant mass in the ruptured steam generator. Of the primary liquid that Dashes to steam, some fraction may immediately be exhausted with the main steam now, while the remainder is somehow entrained in the secondary coolant mass. Since the fraction of the flashed primary coolant that is immediately ex-hausted cannot be easily quantined, this parameter, Ffr, is treated as a free var-iable, it is also assumed there is no additional radionuclide removalin the steam space above the liquid level in the steam generator. The radionuclide release rate from the ruptured steam generator consists of ac-tivity that is imrediately released and activity that is carried from the steam generator water in the remaining steam exhausted through the safety relief valves. Noble gas radionuclides, and the iodines in the primary coolant mass that Dashes to steam, are assumed to be exhausted immediately. For iodines mixed in the steam generator liquid, the ratio of the activity concentration in the exhaust steam to that in the secondary coolant is the partition factor, PFI which is as-sumed to be 1/100 per section 111.10 of the SRP. This is consistent with the carry over of iodine from the steam generator water to the steam under normal Page C 6 s

operating conditions. The steam now rate and the liquid mass of the ruptured steam generator during the course of the accident and the fraction ofleaked pn-mary liquid that flashes to steam are given in Figures 4 5,4 9, and 4 21 respec-tively. For the intact steam generators, it is assumed that the leaked primary coolant is completely mixed in the secondary liquid with no immediate release of any Gashed steam R dionuclides released from these generators are carried with the normal steam now at a concentration determined by the partition factor. For lodine radionuclides the partition factor is assumed to be 1/100. For noble gas radionuclides a partition factor of 1.0 is used. The steam now rate from and the liquid mass in the intact steam generator are determined by thermal hydraulic analyses. These parameters are shown in Figures 4 6 and 4 22. The differential equations describing the activity changes in the primary coolant and the steam generator liquid masses are given following this text. These equations are couched in terms of activity concentrations to simplify the release rate expressions, ifit is assumed that the mass now rates and liquid masses can be approximated by constant average values over a finite time interval, then the differential equations can be solved using Laplace Transforms. The time de-4 pendent release rates are then integrated to determine the radionuclide release over the interval. Summing these over the course of the accident gives the total i release for each radionuclide. l 1 t l Page C 7

Differential Equations for Concurrent Iodine Spike Model (tli t $t2)

0) Primary Coolant Activity Concentration :

dNo/dt = $o - al(No/Mo) - s2(No/Mo) - A No Co(t) = No(t)/Mo dCo/dt = $o/Mo - ((il/Mo) + (m2/Mo) + A) Co .at Apply Laplace transforms - aCo(s)-Co(t1)=($o/Mo)/s-MCo(s) A Co(s) = Co(t!)/(s+o() + (Bo/Mo)/(s(s+o()) Apply inverse transforms to obtain solution - Co(t) = Co(t!) exp( aK(t ti)) + ($o/Mo)(1-exp(-M(t-tl)))/oc

1) Ruptured Steam Cenerator Liquid Activity Concentration i dN1/dt = (1-Ff F.fr)i1 Co(t) - S1 PF1(N1/M1) - A N1 Cl(t) = N1(t)/M1 dC1/dt=(1FfFfr)($1/M1)Co-($1PF1/M1+A)C1 u

As Apply Laplace transforms - A A 4 sC1(s)-C1(tl)=(1-FfFfr)(E1/M1)Co(s)-p,C1(s) Cl(s) = C1(ti)/(s+/.) + (1-Ff Fir)($1/M1) x (Co(ti)/((s+d)(s+#4))+($o/Mo)/(s(s+st)(s+g,))) Apply inverse transforms to obtain solution - Cl(t)=Cl(tt)exp(-/,(t-ti))+(1FfFfr)($1/M1)x ( Co(ti)( exp(- A,(t-ti)) - exp(- o((t-t1)))/(o(,$,)

l

($o/Mo)(1/A$,)x (1 + (p.exp(-M(t-ti)) o( exp(-4,(t-tl)))/( o4 - d ))) i l Page C 8 I I

2) Intact Steam Generator Liquid Activity Concentration dN2/dt = 12 Co(t) - 82 PF2(N2/M2) - A N2 C2(t) = N2(t)/M2 dC2/dt = ($2/M2)Co - (82 PF2/M2 + A )C2 f'

Apply Laplace transforms - sC2(s)-C2(t1)=($2/M2)ho(s)-g,C2(s) C2(s)=C2(t1)/(s+4)+(m2/M2)x ( Co(t!)/((s+4)(s+ #s)) + ($o/Mo)/(s(s+eO(s+4))) Apply inverse transforms to <>btain solution - C2(t)=C2(ti)exp(-g,(t-ti))+($2/M2)x ( Co(ti)( exp(-/,(t-ti)) - exp(- e((t ti)))/(e( -4) t ($o/Mo)(1/q)x (1+(p,exp(-et(t-ti))-v(exp(-A,(t-ti)))/(M-4))) i Release Rate r $1(t)=FfFfrAlCo(t)+S1PF1Cl(t) $2(t)=52PF2C2(t) Intemrated Release : f ',' R1(tl t2) = R1(t) dt l 't: 43 l Ff Ffr mi Co(t)dt+51PF1 C1(t) dt = I 41 ts R2(tiet2) = R2(t) dt il $2 PF2 C2(t) dt = il Total Release t RTot(tl.t2) = R1(tl,t2) + R2(tl t2) Page C 9

(ss = Ff Tfr mi Co(ti) exp(-o((t-tl)) dt + All gg FfFfr$1($o/Mo)(1/4) (1 - exp(-o((t-ti))) dt + .o 51 PF1 C1(t!) exp(-8,(t-tl)) dt + tl 51 PF1 Co(ti) (1-Ff Ffr)(k1/M1)/(a( p,) x gt1 (exp(-g,(t-ti))-exp(- M(t tl))) dt t Att 81PF1($o/Mo)(1-FfFir)($1/M1)/(d4,)x (U( 1 + (p,exp(- W(t-tl))- Mexp(-4,(t ti)))/(a(-4) ) dt t ett (U $2PF2C2(ti) exp(-g,(t-ti)) dt + dtt S2PF2Co(ti)($2/M2)/(M-p,)x f(42exp(-6(t-tl))-exp(- M(t-ti))) dt + d ie 52PF2($o/Mo)(E2/M2)/(WA)x (t2 ( 1 + (g,exp(- M(t-ti))-Mexp(-g,(t-t!)))/( A-p,) ) dt 'h = Ff Ffr El Co(ti) (1 'exp(- A(t2-ti)))/M + Ff Ffr al ($o/Mo) (t2-tl)/d - Ff Ffr al ($o/Mo) (1/g )(1 - exp(-M(t2 ti)))k + S1PF1Cl(t!)(1-exp(-/a(t2-tl)))//, t h1PF1Co(ti)(1-FfFir)(al/M1)/(X-fs)x l Page C 10

( (1 - exp(-/,(t2 ti)))/p, - (1 - exp( #(t2 ti)))/g ) 4 51PF1($o/Mo)(1-FfFfr)(E1/M1)(t2-t1)/(d7,) + 51PF1($o/Mo)(1-FfFfr)(E1/M1)(1/d$,)/(aC-p,)x (p, (1 exp(-d (t2 tl)))/d - M(1 - exp(-/,(t2 tl)))/g, ) + 52 PF2 C2(ti) (1 - exp(-g,(t2 ti)))/4 + h2PF2Co(ti)($2/M2)/(st.-g,) x ( (1 - exp(-p,(t2-tt)))/p, - (1 - exp(- m(t2-ti)))/ 8 ) + 52 PF2 ($o/Mo) (m2/M2)(t2-t1)/(Wp.) + 52PF2(io/Ho)(m2/M2)(1/d$,)/(85.-A)x ( $,(1 - exp(-g(t2-ti)))/4 -M(1-exp(-p,(t2-ti)))/4) l 1 l l Page C-Il

Dose Calculation Technique : Thyroid inhalation and whole body exposure doses at the Exclusion Area Boundary (EAB) and the Low Population Zone (LPZ) distances are calculated using the expression given in ATTACHh1ENT 15A, Amendment 30, hlarch 1981 of the B/B FSAR. Radionuclide decay data, thyroid inhalation dose con-version factors, and breathing rates are taken from Table 15A 1 of ATTACH-h1ENT 15A. Accident X/Q values at the Byron and Braidwood site EAB's and LPZ's are taken from FSAR Tables 15.013 and 15.014, Amendment 30, h1 arch 1981, respectively. Cumulative radionuclide releases (Curies) over the course of the Steam Generator Tube Rupture accident are determined as explained in the preceding sections of this appendix. Computer Program Implementation : Because of the transient nature of the Steam Generator Tube Rupture accident, the thermal hydraulic parameters can vary greatly over relatively short time in-tervals. Consequently, the solutions to the constant coef0clent differential equations used to model radionuclide transport during the accident must be evaluated many times to accurately determine the EAB and LPZ doses. Since the differential equation solutions are themselves somewhat complicated, it was decided that a computer program implementation would be the best way to handle the entire dose analysis. In addition, since the flash fraction released, Ffr, ( is a free variable, this would provide a convenient means of doing a parametric study on the importance of this quantity. A computer program written in Fortran is used for this analysis. The code uses a combination of time independent radionuclide data and time dependent thermal hydraulic data to do the preaccident and concurrent iodine spike dose calculations. All of the thermal hydraulle data are provided by Commonwealth Edison (Ref. 3) as explained elsewhere in this report. To insure that the computer program functions properly, it is validated by com-paring the results of a sample problem execution with independently performed hand calculations. A program listing and the results of the validation comparison are included in Sargent & Lundy Byron /Braidwood calculation B7 RC 01, Re-vision 3 (Ref. 4). l C.3 Results The methodology and data described in section C.2 have been used to evaluate EAB and LPZ doses for the Byron and Braidwood sites. The results with the factor Ffr (fraction of flashed steam that is immediately released) as a parameter are presented in Tables C-1 and C 2. The most conservative results are obtained when Ffr is 1.0. Page C-12 d

C.4 Conclusions Calculated thyroid and whole body doses from lodine and noble gas radionuclides released during a postulated Steam Generator Tube Rupture accident at the By-ron and Braidwood sites are summarized in Table C-1 and C 2 for various Dashed fraction release assumptions. As can be seen, the doses for both the pre-accident and concurrent lodine spike models are well within the SRP 15.6.3 ac-ceptance criteria of 100% and 10% of the 10 CFR 100 limits, respectively. The variation of the EAB thyroid dose with Dashed fraction release assumption is about a factor of six from the most (1.00) to the least (0.00) conservative case. Since the noble gas radionuclides are assumed to be immediately released from the ruptured steam generator, regardless of the Dashed fraction release assump-tion, the whole body doses change very little. Note that the doses at the Braid-wood site are higher than those at Byron because of the larger X/Q's for Braidwood. Examination of the output listing from the computer run for Byron and Braid-wood shows that most of the radionuclide release comes from the ruptured steam generator with only a few percent coming from the intact generators. For times when the relief valve on the ruptured steam generator is closed, radionuclides are assumed to buildup in the generator. When the relief valve is opened, the accu-mulated noble gas radionuclides are assumed to be instantaneously released. This gas bubble mechanism is not considered for the intact generators; instead, a complete mixing assumption is used for all radionticlide in these generators. From the foregoing discussion, it can be concluded that the EAB and LPZ thyroid and whole body doses, caused by radionuclides released during a postu-lated Steam Generator Tube Rupture accident at the Byron and Braidwood sites, do not exceed 10 CFR 100 limits or the acceptance criteria of SRP 15.6.3. This is true even for the most conservative Dashed fraction release assumption. References :

1. U.S. Nuclear Regulatory Commission, Standard Review Plan, NUREG 0800, Rev. 2 July 1981.

2. Commonwealth Edison Company, Byron /Braidwood Stations Final Safety Analysis Report, U.S. NRC Docket No 's 50-454,50 455,50 456, and 50-457.

f

3. Commonwealth Edison Company, Letter from H.E. Bliss, Nuclear Fuel Services Ntanager to B.R. Shelton, "Plots and Digitized Data for Byron /Braidwood SGTR Analysis," Ntarch 16,1988.

4. Pichursk;, D.J., "Steam Generator Tube Rupture Accident,* Sargent &

Lundy, Byron /Braidwood Calculation B7 RC 01, Revision 3,03t23,SS. i Page C-13 i

C.5 TABLES TABLE C 1 Preaccident lodine Spike Doses (Rem) Ffr Byron EAB Byron LPZ Thyroid Body Thyroid Body l 1.00 13.72 0.1727 0.4093 0.0051 1 0.75 11.15 0.1695 0.3327 0.0050 0.50 8.58 0.1663 0.2560 0.0049 0.25 6.01 0.1631 0.1793 0.0048 0.00 3.44 0.1599 0.1027 0.0047 Ffr Braidwood EAB Braidwood LPZ Thyroid Body Thyroid Body 1.00 18.54 0.2333 1.710 0.0215 0.75 15.07 0.2290 1.389 0.0211 0.50 11.60 0.2247 1.069 0.0207 0.25 8.12 0.2203 0.749 0.0203 0.00 4.65 0.2160 0.429 0.0199 10 CFR 100 Dose Limits EAB LPZ Thyroid Body Thyroid Body Limit 300. 25. 300. 25. Accept. 30. 2.5 30. 2.5 EAD - Exclusion Area Boundary LPZ - Low Population Zone 1 ) ) Page C-14 i

TABLE C 2 Concurrent lodine Spike Doses (Rem) Ffr Byron EAB Byron LPZ Thyroid Body nyroid Body 1.00 13.73 0.1687-0.4095 0.0050 0.75 10.81 0.1583 0.3223 0.0047 0.50 7.88 0.1479 0.2531 0.0044 0.25 4.96 0.1374 0.1479 0.0041 0.00 2.03 0.1270 0.0606 0.0038 Ffr Braiawood EAB Braidwood LPZ Thyroid Body Thyroid Body 1.00 18.55 0.2279 1.710 0.0210 0.75 14.60 0.2138 1.346 0.0197 0.50 10.65 0.1997 0.982 0.0184 0.25 6.70 0.1857 0.618 0.0171 0.00 2.75 0.1716 0.253 0.0158 10 CFR 100 Dose Limits EAB LPZ nyroid Body Thyroid Body Liait 300. 25. 300. 25. Accept. 30. 2.5 30. 2.5 EAB - Exclusion Area Boundary LPZ - Low Population Zone Page C 15

Appendix D. LIST OF EQUIPMENT FOR SGTR MITIGATION D.] List of Equipmentfor SGTR Mitigation To fulfill the NRC requirement of site specific SGTR analysis, Table D 1 pre-sents the equipment referenced in the EOFs for SGTR mitigation along with ra-distion monitors which could be available to the operators. Each piece of equipment has its safety classification listed. Table D 2 presents a list of the valve motive power of the primary / secondary PORVs and control valves and other required information. Page D 1

C.6 FIGURES FIGURE C 1 Preaccident lodine Spike Model p Ff Ffr 61 Co(t) + S1.PFl*Cl(t) Primary M1 Ruptured SG &1 N1(t) p S2* PF2+ C2(t) Mo

Cl(t)

No(t) H2 Co(t) &2 N2(t) Intact SGs y - C2(t) Mo - Primary coolant mass (Ibm). No(t) - Radionuclide activity in the primary coolant (Ci). Co(t) - Radionuclide concentration in the primary coolant (uC1/gm). $1 - Hass flowrate to the ruptured steam generator (1bm/sec). M1 - Ruptured steam generator liquid mass (1bm). N1(t) - Radionuclide activity in the ruptured generator liquid (Ci). Cl(t) - Radionuclide concentration in ths ruptured generator liquid (uci/gm). Ff - Traction of leaked primary coolant that flashed to steam. {f7 - Fraction of flashed steam that is immediately released. S1 - Non-flashed steam flow rate from the ruptured steam generator (1bm/sec). Equal to the total steam flow rate, S1, minus the contribution from flashing, FfFfrm1. PF1 - Partition factor for ruptured steam generator. E2 - Mass flowrate to the intact steam generators (1bm/s). M2 - Intact steam generator liquid mass (1bm). N2(t) - Radionuclide activity in 'e intact genere. tors liquid (Ci) i C2(t) - Radionuclide concentration in the intact generators liquid (uCi/gm). S2 - Steam flow rate from the intact steam generators (1bm/sec). PF2 - Partition factor for the intact steam generators. 1 - Radionuclide decay constant (1/sec). t1 - Interval starting time (sec). t2 - Interval ending time (sec). Initial Conditions : Co(tl) - Primary coolant concentration at start of interval. Cl(ti) - Ruptured steam generator liquid concentration at start the interval. C2(tl) - Intact steam generators liquid concentration at start of the interval. Page C 16

FIGURE C 2 Concurrent lodine Spike Model Primary fFfFir61Co(t)+SlPF1.Cl(t) M1 Ruptured SG Mo 61 N1(t) p S2* PF2* C2(t) Core No(t) Cl(t) Co(t) M2 &2 N2(t) Intact SGs Bo-+ q C2(t) Eo - Release rate from failed fuel to primary coolant (Ci/sec). Ho - Primary coolant mass (1bm). No(t) - Radionuclide activity in the primary coolant (Ci). Co(t) - Radlonuclide concentration in the primary coolant (uci/ge). 61 - Mass flowrate to the ruptured stor,m generator (1bm/sec). M1 - Ruptured steam generator liquid mass (1bm). N1(t) - Radionuclide activity in the ruptured generator liquid (Ci), Cl(t) - Radionuclide concentration in the ruptured generator liquid (Ci/gm). Ff - Fraction of leaked primary coolant that flashed to steam. { f,r - Fraction of flashed steam that is immediately released. S1 - Non-flashed steam flow rate from the ruptured steam generator (Iba/sec). Equal to the total steam flow rate, S1, minus the contribution from flashing FfFfrm1. PF1 - Partition factor for ruptured steam generator. 62 - Mass flowrate to the intact steam generatora (1bm/sec). M2 - Intact steam generator liquid mass (1bm). N2(t) - Radionuclide activity in the intact generators liquid (C1). C2(t) - Radionuclide concentration in the intact generators liquid (uci/gm). S2 - Steam flow rate from the intact steam generators (1bm/sec). PF2 - Partition factor fer the intact steam generators. K - Radionuclide decay constant (1/sec), t! - Interval starting time (sec). t2 - Interval ending time (sec). Initial Conditions l l Cc(tl) - Primary coolant concentration at start of interval. Cl(tl) - Ruptuted steam generator liquid concentration at start of the interval. C2(ti) Intact steam generators liquid concentration at start of the interval. Page C 17

D,2 TABLES TABLEDL1 List of Equipment for SGTR Mitigation Equipment Safety Class / Remarks Grade? STEAM GENERAYORS Steam generator PORV valves Yes Category I, Group B Steam generator PORV isolation valves Yes Category I, Group B Steam generator blowdown isol. valves Yes Category I, Group B Stoam generator safety valves Yet Category I, Group B Steam generator pressure indication Yes Category I, Group B Steam geaerator level indicator Yes Category I, Group B TEEDWATER SYSTEM Main feedwater isolation valves Yes Category I, Group B Feedwater tempering isolation valves Yes Category I, Group B TV prehtr bypass isolation valves Yes Category I, Group B FV bypass isolation valves Yes Category I, Group B AUXILIARY TEEDVATER SYSTEM Mc1or driven AFW pump Yes Category I, Group C Diesul driven Arvi pump Yes Category I, Group C ATV flow control valves Yes Category I, Group C ATV flow indicator Yes Category I, Group C AFV 1:olation valve Yes Category I, Group B Essentist service water (for ATV) Yes Category I, Group C MAlfi STEAM SYSTtH Main steamline isolation valves Yes Category I, Group B MSIV bypass valves Yes Category I, Group B Steamline pressure indication Yes Category I, Group B Turbine stop valves

No Category II, Group D Condenser steam dump valves
No Reheater steam supply valves
No Auxiliary steam supply valves
To Gland st6am supply valves
No i

REACTOR C00th T ShTEM Pressurizer PORY valves Yes Category I, Group A Pressurizer PORY block valves Yes Catesvry I, Group A Pressurizer pressure indication Yes Category I, Group 4 Reactor coolant system temperature Yes Categorv I, Group A i Core exit thermocouple indication Yes Cates.. , Class IE elec i Pressurizer level indication Yes Catege :y Group A i Page DL2

t TABLE D 1 (Continued) List of Equipment for SOTR Mitigation l Equipment Safety Class / Remarks Jrade7 t ECCS { HMSI/ charging pumps Yes Category I, Group B SI pumps Yes Category I, Group B Safety injection reset pushbuttons Yes Category I, class IE e12c ENGINEERED SAFETY TEA 1URES SYSTIM ESF actuation logic Yes Category I, class IE elec Diesel Generators Yes Category I, class IE elec ESP station battery and DC busses Yes Category I, class IE elec Instrument air compressors No Category II, Group D Cross tied to ESF bus. I INSTRUMENTATION Reactor Protection Systes Yes electrical class IE i l RADIATION MONITORS Main steamline area Rad monitor Yes Category I, Class IE elec, GM type, energy range 0.02-3Mev l 0.1 10,000 mR/hr, alarm setpoint G 2 x background Main steam penetration Rad monitor

No Category I, Class IE elec.

IC type, energy range 0.1-3Mov, 0.1-10,000 R/hr, Steam jet air ejector and gland

No Gas channel, boron scintillation, steam exhaust Rad monitor measures gross beta, sensitivity range 10E-6 to 10E 2 uC1/ce, count range 10E0 to 10E7, alarw i

setpoint 0 2 x background Steam generator blowdown and

No Liquid channel, Na! detector, i

sampling Rad monitor measures gamma, sensitivity range 10E 6 to 10E-2 uCi/cc, count range 10E0 to 1CE7, alarm setpoint G 2 x background

items with asterisk are not needed to sitigate SGTR accident with LOOP, but could be helpful if offsite power is restored f

i t 1 I Page D-3 i ( l

~ TABLE D 2. Evaluation of Primary and Secondary Valves i Equipment Safety Motive Peter Grade? STEAM GENERATORS Steam generator PORV valves Yes Hydraulically powered by DC motor driven pump supplied from 480 VAC ESF bus rectified for DC control. Fails closed with N2 accum. Main control room hand switch. Variable position indication from 125 V ESF class 1E bus. Local manual operation also. Steam generator PORV isolation valves Yes Local manual operation with a hand wheel on gate valve. Steam generator blowdown isol. valves Yes Cat. IB instrument air to open, fail closed. Variable control main control room hand switch. YEEDWATER SYSTEM Main feedwater isolation valves Yes Hydraulically operated, ESF logic and water hammer prevent control. Includes open/ closed indication in main control room. Feedwater tempering isolation valves Yes Cat. IID instrument air to open, fail closed. ESF logic actuated. FW prehtr bypass isolation valves Yes Cat. IID instrument air to open, fail closed. ESF logic actuated. l FW bypass isolation valves Yes Cat. IID instrument air to open, l fail closed. ESF logic actuated. AUXILIARY FEEDWATER SYSTEM AFW flow control valves Yes Cat. IID instrument air to operate, fails open. AFV isolation valve Yes Class IE motor operated valve. Includes open/ closed indication l in main control room. l Page D 4 l l l t

TABLE D-2 (Continued) Evaluation of Primary and Secondary Valves Equipment Safety Motive Power Grade? MAIN STEAM SYSTEM Main steamline isolatiun valves Yes Hydraulically operated, ESF logic. Includes open/ closed indication in main control room. MSIV bypass valves Yes Cat. IID instrument air to open, fail closed. Includes open/ closed indication in main control room. Turbine stop valves No Hydraulically operated from EHC non-safety related power, fail closed.Includcs open/ closed indication in main control room. MSIVs serve as safety grade backup valve. REACTOR C00IMF SYSTEM Pressurizer P0hV valves Yes Dedicated air accr 'ator to open, fail close sludes open/ closed indication, main control room. Pressurizer pressure control with automatic or manual switch in main control room. Pressurizer PORV block valves Yes Class IE motor operated valve. Includes open/ closed indication in main control room. l 1 Page D 5 - _ __}}

ML20195B781

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6.0 REFERENCES

1.0 INTRODUCTION

6.0 REFERENCES

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