ML20211C891
| ML20211C891 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 09/23/1997 |
| From: | ENTERGY OPERATIONS, INC. |
| To: | |
| Shared Package | |
| ML20211C886 | List: |
| References | |
| NUDOCS 9709260343 | |
| Download: ML20211C891 (141) | |
Text
{{#Wiki_filter:1 i l 1 PROPOSED TECHNICAL SPECIFICATION CHANGES 7 9709260343-970923 PDR ADOCK 05000368 PDR , P
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POWER DISTdIBUTION LIMITS RCS FLOW RATE
- LIMITING CONDITION FOR OPERATION
- 3.2.5 The actual Reactor Coolant System total flow rate shall be greater l than or equal to 108.4 x 10' lbm/hr (Note 1) . l
~ , APPLICABILITY: MODE 1. ACTION: With the actual Reactor Coolant System total flow rate determined to be less than the above limit, reduce THERMAL POWER to less than 5% of RATED i THERMAL POWER within the next 4 hours. i SURVEILLANCE REQUIREMENTS . . , 4.2.5 The actual Reactor Coolant System total flow rate *$all be determined to be within its limit at least once per 17 sura. Note 1: The value of -120.4 x 10' lbm/hr has been reduced to 108.4 x 10' lbm/hr until the steam generators are replaced. After the steam generators are replaced, this value returns to 120.4 x 10' lbm/hr. ARKANSAS - UNIT 2 3/4 2-7 Amendment No. 24,4M,
1 MARKUP OF CURRENT ANO-2 TECHNICAL SPECIFICATIONS (FORINFO ONLY)
t ] q M ER DISTRtBUTION LIMITS i RCS FLOW RATE I ' i ' LIMITING CGNDITION FOR OPERATION
?.2.5 The actual Reactor Coolant System total flow rate shall be greater chan or equal to 43012),.f x 10' lbm/hr_(Note 11. l APPLICABILITY: MODE 1.
ACTION: I With the actual Reactor Coolant system total flow rate determined to be less than the above limit, reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 4 hours. i SURVEILLANCE REQUIREMENTS i 4.2.5 The actual Reactor Coolant system total flow rate shall be determined to be within its limit at least once per 12 hours. ' l ggle 1: The_value of 120. 4 x 10' 1kmL).: r as been reduced to 108.- d Abm/hr until the_sttam centrat9Is are rapia.ctd . Af ter the__ steam aenerptprJ mte_recla_ced... thi_s value_re.tv. ggt to 120. 4 x 10' lkm/hr. ARKANSAS - UNIT 2 3/4 2-7 Amendment No. 34,4M,
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l l ATTACliMENT I DESCRIPTION AND EVALUATION OF THE ANALYSES IN SUPPORT OF REDUCING THE RCS PLOW REOUIREMENTS BY 10% AND INCREASING TiiE STEAM GENERATOR TUBE PLUGGING LIMIT TO 30%
Attachment I ts l 2CAN099701 Page1of138 ATTACHMENT 1 DESCRIPTION AND EVALUATION OF THE ANALYSES IN SUPPORT OF REDUCING THE RCS FLOW REQUIREMENTS BY 10% AND INCREASING THE STEAM OENERATOR TUBE PLUGGING LIMIT TO 30% The following is a listing of the events presented in the ANO 2 Safety Analysis Report (SAR). In the right hand column a note has been placed delineating the level of effort in addressing a reduction in Reactor Coolant System (RCS) flow. A summary of the effort for each event which is affected by a lower RCS flow is provided in this attachment. The reduction in RCS flow is attributed to steam generator tube plugging. Consideration for up to 30% steam generator tube plugging has been accounted for in the analyses described below. Occas! anally, the analyses presented are unaffected by RCS flow reductior, but, are affected by tube plugging. These events are providui for information and are notect in the text for the respective event. Notes in the right hind column indicate: Evaluated, Reanalyzed, Not Roanalyzed, and Not Applicable. An evem which is impacted by a redaction in RCS flow or tube plugging yet the impmet can be addressed qualitatively : e Indicated as Evaluated. These events are addressed by qualitative arguments and ioine simple quantitative efforts. Events in which the effects of reducing RCS flow and plugging steam generator tubes are more involved and necessitated a new analysis have been indicated u Roanalyzed. Not Reanalyzed has been used to note events which are not impacted by a reduction in RCS flow or steam generator , tube plugging Finally, all of the events presented in Chapter 15 of the ANO 2 SAR are listed in the following table, some of which are not applicable to ANO 2 as indicated in the SAR. These events are denoted with a Not Applicable note. SAR Section Title Analysis Effort-Section 6.2.1 Containment Functional Design Evaluated 6.3.3.2.2 Large Break Analysis Reanalyzed 6.3.3.2.3 SmallBreak Analysis Reanalyzed 15.1.1 Uncontrolled CEA Withdrawal from a Subcritical Condition Reanalyzed 15.1.2 Uncontrolled CEA Withdrawal from Critical Conditions Hot Zero Power (HZP) Reanalyzed Hot Full Power (HFP) Evaluated 15.1.3 CEA Misoperation Not Reanalyzed 15.1.4 Uncontrolled Boron Dilution incident Modes 1 and 2 Reanalyzed Modes 3,4, 5, and 6 Not Reanalyzed 15.1.5 Total aml Partial Loss of RCS Forced Flow Four Pump Loss ofFlow Reanalyzed Seized Rotor Evaluated
'15.1.6 Idle Loop Startup Not Reanalyzed 15.1.7 Loss of External Load and/or Turbine Trip Reanalyzed 15.1.8 Loss ofNormal Feedwater Flow Reanalyzed
Attachment i 13 2CAN099701 Pape 2 of138 15.1.9 Loss of All Normal and Preferred AC Power to the Station Not Resnalyzed Auxillaries 15.1.10 Excess Heat Removal Due to Secondary System Malfunction Evaluated 15.1.11 Failure of the Regulating Instrumentation Not Applicable 15.1.12 Internal and External Events including Major and Minor Fires, Not Reanalyzed Floods, Storms, and Earthquakes 15.1.13 Major Rupture of Pipes Containing Reactor Coolant up to and Not Reanalyzed including Double-Ended Rupture of Largest Pipe in the Reactor Coolant System (LOCA) 15.1.14 Major Secondary System Pipe Breaks with or without a Concurrent Loss of AC Power Main Steam Line Break (MSLB) Reanalyzed Feedwater Line Break (FWLB) Reanalyzed 15.1.15 Inadvertent Loading of a Fuel Assembly into the Improper Not Reanalyzed Position 15.1.16 Waste Oas Decay Tank Leakage or Rupture Not Reare.lyzed 15.1.17 Failure of Air Ejector Lines (BWR) Not Applicable 15.1.18 Steam Generator Tube Rupture with or without a Concurrent Evaluated Loss of AC Power (SGTR) 15.1.19 Failure of Charcoal of Cryogenic System (BWR) Not Applicable 15.1.20 CEA Ejection HZP Reanalyzed HFP Reanalyzed 15.1.21 The Spectmm of Rod Drop Accidents (BWR) Not Applicable 15.1.22 Break in Instrument Line or Other Lines from Reactor Coolant Not Reanalyzed Pressure Boundary that Peaetrate Containment 15.1.23 Fuel Handling Accident Not Reanalyzed 15.1.24 Small Spills or Leaks - of Radioactive Material- Outside Not Reanalyzed Containment 15.1.25 Fuel Cladding Failure Combined with Steam Generator Leak Not Reanalyzed
-15.1.26 Control Room Uninhabitability Not Roanalyzed 15.1.27 Failure or Over presssurization of Low Pressure Residual Heat Not Reanalyzed Removal System 15.1.28 Loss of Condenser Vacuum (LOCV) Not Reanalyzed (See 15.1.7) 15.1.29 Turbine Trip with Coincident Failure of Turbine Bypass Valves Not Reanalyzed to Open (See 15.1.7) 15.1.30 Loss of Service Water System Not Reanalyzed 15.1.31 Loss ofone DC System _
Not Reanalyzed 15.1.32 Inadvertent Operation of ECCS During Power Operation Not Reanalyzed 15.1.33_ Turbine Trip with Failure of Generator Breaker to Open Not Reanalyzed 15.1.34 Loss ofinstrument Air System Not Reanalyzed 15.1.35 Malfunction ofTurbine Gland Scaling System Not Reanalyzed 15.1.36 Transients Resulting from the Instantaneous Closure of a Single Reanalyzed MSIV
Attachment I ts 2CAN099701 ! Page 3 of138 Many of the analysis presented below were performed for Cycle 13 which include the core physics data for Cycle 13. Modwator temperature coefficient, fbel temperature coefficient (Doppler curve), delayed neutron firactions, eftbetive neutron lifetime, and control element assembly (CEA) reactivity insertion curves are core physics parameters that are typically considwed on a cycle specinc basis and are inputs to many of the analyses discussed below. The Cycle 13 set of physics data will be presented Arst, allowing the respective analyses to refer to this data as it is applied. Detailed core physics data that aftbets a particular analysis will be discussed for that analysis. l Figure 2 represents the Cycle 13 lbel tempwature reactivity curves for Beginning of Cycle (BOC) and End of Cycle (EOC). These curves include a 0.85 multiplier for uncertainty on BOC reactivity and a 1.4 multiplier for uncertainty on EOC reactivity. This curve has been used as specined in the specific analysis. A modwator temperature coefficient within the ranges denned in Figure I was assumed in the following analyses. A new CEA reactivity insertion curve was developed for the Cycle 13 analyses. This new curve is presented in Figure 3. The scram curve is based on an Axial Shape Index (ASI) of + 0.3. A CEA insertion curve consistent with Figure 4 utilizing a 0.6 second holding coil delay time and a 3.2 second arithmetic average drop time to 90% inserted was assumed. A shutdown worth of 5% Ap is incorporated into Figure 3. Figure 3 has been used as specified in the following analyses. The following effbetive neutron lifetime and delayed neutron fraction wwe established for the Cycle 13 analyses, These parameters are used as indicated in the respective analyses. Neutron Lifetime Delayed Neutton 4 (10 sec.) Fraction Begimdng of Cycle 13 0.007252 End of Cycle 36 0.004341 The largest impact that a decrease in RCS flow has on plant operation is the reduction in operating margin to the DNBR and LHR limits. ANO 2 is a Core Operating Limits Supervisory System (COLSS) / Core Protection Calculator (CPC) plant that uses these systems to monitor the DNDR and LHR margins. The reduction in RCS flow that occurs as a result of additional steam generator tube plugging producci a reduction in the operating margin to the DNBR and LHR limits as calculated by the CPCs and COLSS. In the recent past, operating margin has been gained by reducing the cold and hot leg RCS temperatures and implementation of CEN 356(V)-P A, Revision 01 P A, " Modified Statistical Combinations of Uncertainty." The fuel reloads will be modified as additional margin is needed to account for future flow reductions from steam generator tube plugging. The fuel peaking factors can be controlled in the fuel reloads to ensure that adequate operating margin is maintained in the future.
Attachment I ts 2CAN099701 Page 4 of138 CONTAINMENT FUNCTIONAL DESIGN. SAR SECTION 6.1.1 Reducing RCS flow by 10% will result in an increase in the hot leg temperature for a given cold leg temperature. Increasing the hot leg temperature may result in an increase in the energy within the RCS liqui /. The energy increase in the RCS liquid is minimized due to the density decrease and resulting RCS mass reduction. Increasing the energy in the RCS could l impact the containment peak pressure analysis associated with a large break LOCA. A small increase in temperature due to a reduction in RCS flow results in a small increase in the RCS system energy and a decrease in the RCS system mass. A 10% reduction in RCS flow is attributed to 30% steam generator tube plugging. Currently, the ANO-2 steam generators are approximately 14% plugged. Mass and energy reductions due to the associated RCS volume decrease from steam generator tube plugging more than offset the effects of a small increase in hot leg temperature. Based on this assessment, the current large break LOCA peak containment pressure analysis remains bounding. LARGE BREAK ANALYSIS. SAR SECTION 6.3.3.2.2 An analysis for Cycle 13 has been performed to support an increase in the number of plugged steam generator tubes and a decrease in the RCS flow rate. The analysis was performed using the NRC approved June 1985 version of the ABB CE large break LOCA evaluation mod <l (Reference 13, Supplement 3 P A). This is the same version used in the analysis of record. The analysis was performed for the equivalent of up to 30% steam generator tube plugging per steam generator and an RCS flow rate of 107.8 x 10' lbm/hr. Table 1 lists the significant core and system parameters used in the analysia. The analysis was performed for the 0.6 Double Ended Guillotine / Pump Discharge (DEG/PD) break which is the limiting break from the previous analysis. This analysis was performed at a hot rod average burnup of 40,000 MWD /MTU. Results of the analysis are presented in Tables 2 and 3 and Figures 5a through Sr. Table 3 lists
- the peak cladding temperature and oxidation percentages for the analysis. Times ofinterest are listed in Table 2. The figures present the transient results for the variables listed in Table 5. The results demonstrate conformance to- the ECCS acceptance criteria as summarized below.
Parameter Criterion Result Peak Cladding Temperature s 2200*F 21SC'F Maximum Cladding Oxidation s 17 % 7.2% Maximum Core-Wide Oxidation s1% < 0.99%
. Based on the results of the analysis, it is concluded that the ANO-2 ECCS design satisfies the acceptance criteria of 10 CFR 50.46 for large break LOCA for the conditions analyzed in this =
analysis. These include the equivalent of up to 30% steam generator tube plugging per steam generator and a minimum RCS flow rate of 107.8 x 10' lbm/hr.
Attachment I to 2CAN099701 Page 5 of138 SMALL BREAK ANALYSIS. SAR SECTION 6.3.3.2.3 The following Small Break LOCA analysis was presented in the Amendment No.179 submittal. This submittal requested approval for the use of CENPD 137 Supplement 1 P (Reference 6) for performing the LOCA analysis. Included in the submittal was the application of the nsodel to ANO 2 accounting for a 10% reduction in RCS flow and 30% steam generator tube plugging. Evaluation Model The small break LOCA analysis was performed using the ABB CE small break LOCA evaluation model (Reference 6, Supplement 1 P). The evaluation model was approved by the NRC in Reference 11. In the ABB CE small break LOCA evaluation model, the CEFLASH-l 4AS computer program (Reference 12) is used to perform the hydraulic analysis of the RCS until the time the Safety Injection Tanks (SITS) begin to inject. After injection from the SITS begins, the COMPERC-Il computer program (Reference 8) is used to perform the hydraulic analysis. The hot rod cladding temperature and maximum cladding oxidation are calculated by the STRIKIN-Il computer program (Reference 10) during the initial period of forced convection heat transfer and by the PARCH computer program (Reference 9) during the subsequent period of pool boiling heat transfer. Core-wide cladding - oxidation is conservatively represented as the rod average cladding oxidstion of the hot rod. The initial steady state fuel rod conditions used in the analysis are determbed using the FATES 3B computer program (Reference 7). Safety injection System Parameten I i The ANO 2 ECCS consists of three High Pressure Safety Injection (HPSI) pumps, two Low Pressure Safety Irjection (LPSI) pumps, and four SITS. Each HPSI pump injects into one of the two high pressure triection headers which feed each cold leg. Throttle valves in each of the ,old legs are used for flow balancing. The LPSI pumps inject to a common header which feeds each cold leg Each SIT injects to a single cold leg. Two HPSI pumps and the LPSI pumps are automatically actuated by a safety infection actuation signal that is generated by either low pressurizer pressure or high containment pressure. The SIT automatically discharge when the RCS pressure decreases below the SIT pres ,ure. In the small break LOCA analysis it is assumed that offsite power is lost coincident with reactor trip and, therefo.e, the HPSI and LPSI pumps must await emergency diesel generator startup and load sequencing before they start. The total delay time assumed is 40 seconds from the time the pressurizer pressure reaches the Safety injection Actuation Signal (SIAS) setpoint to the time that the HPSI pumps are at speed and aligned to the RCS, For breaks in the reactor coolant pump discharge leg all safety injection flow delivered to the broken discharge leg is modeled to spill out the break. An analysis of the possible single failures that can occur within the ECCS has shown that the most damaging single failure of ECCS equipment is the failure of an emergency diesel
Attachment I t3 2CAN099701 Page 6 of 138 generator to start (Reference 6). This failure causes the loss of both a llPSI and LPSI pump and results in a minimum of safety injection water being available to cool the core. Based on the above, the following safety injection flows are credited in the small break LOCA analysis for a break in the reactor coolant pump discharge leg: 75% of the flow from one IIPSI pump,50% of the flow from one LPSI pump and 100% of the flow from three SITS. Table 6 presents the HPSI pump flow rate versus RCS pressure used in the small break LOCA analysis. Core and System Parameters The significant core and system parameters used in the small break LOCA analysis are presented in Table 7. For the 0.05 82 and the 0.06 ft' break sizes, the Main Steam Safety 2 Valve 0.04 ft(MSSV) break sizes,first bankfirst the MSSV opening pressure bank opening was pressure wasassumed assumed toto bebe 1125 1103.5 psia. For the psia. The low pressurizer pressure reactor trip and SIAS setpoints were assumed to be 1400 psia 2 for the 0.02 A2,0.05 A , and 0.06 A' break sizes. The low pressurizer pressure reactor trip was assumed to be 1625 psia, and the low pressurizer pressure SIAS setpoint was assumed to be 1578 psia for the 0.04 ft' break size. The fuel rod initial conditions were taken at the burnup that produced the maximum initial stored energy. The analysis accounts for up to 30% steam generator tube plugging per steam generator. Containment Parameten The small break LOCA analysis does not use a detailed containment model. Therefore, other than the containment volume and the initial containment pressure, which are assumed to be 5 1,820,000 R and 14.7 psia, respectively, no containment parameters are employed in the analysis. Break Spectrum The2 break sptmm consisted of four reactor coolant pump breaks ranging in size from 0.02 R to 0.06 A . Table 8 lists the specific break sizes that were analyzed. The reactor coolant pump dischkrge leg was previously determined to be the limiting break location (Reference 6). It h limiting because it maximizes the amount of spillage from the safety injection system. The break size range of 0.02 n2 to 0.06 A' encompasses the break sizes for which hot rod cladding heatup is terminated solely by injection from the HPSI pump. It is within this range that the limiting small break LOCA, the 0.05 R 2break, resides. Breaks outside this range are either too small to experience any significant core uncovery or are sufliciently large such that injection from the SITS will recover the core and terminate cladding heatup before the cladding temperature approaches the peak cladding temperature calculated for the limiting small break LOCA.
Attachment 1 to - 2CAN099701 Page 7 of138 Results and Conclusloss The peak cladding temperatures and cladding oxidation percentages for the small break LOCA analysis are summarized in Table 9. Table 10 lists times of interest for the breaks analyzed. As noted in Table 8, results for the variables listed in Table 11 are plotted as a function of time in Figures 6a through 9h for the breaks analyzed. Peak cladding temperature versus break size is presented in Figure 10. Based on the results of the analysis, it is concluded that the ANO 2 ECCS design satisfies the Acceptance Criteria of 10CFR50.46 for a spectrum of small break LOCAs. Energy Redtstributies Factor Part 21 Issue l l On July 11,1997, ABB-CE lasued Infobulletin 97-04, Revision I which reported the initiation of a 10 CFR 21 evaluation of the Energy Redistribution Factors (ERF)_used in the ECCS performance analyses using ABB-CE's Large and Small Break LOCA ECCS performance models. ERF represents thr fraction of the total energy generated by a fuel rod which is actually deposited in the rod it was determined that the ERF used by ABB-CE in the LOCA analyses did not directly reflect the effects of moderator voiding during a LOCA and such effects have recently been calculated to be somewhat higher than previously thought. This error affects only the Large Break LOCA analysis significantly, since the Small Break LOCA analysis is insensitive to the ERF. On August 14,1997, ABB-CE issued a Part 21 report to the NRC (LD 97-024) concerning this issue. i ABB-CE is currently working to recalculate the ERF. Once this is completed, an assessment on a plant specific basis will be made on the impact on the peak clad temperature calculated in the LOCA analysis. Due to the timing of this submittal, the LBLOCA and SBLOCA assessments presented above have not accounted for this lasue. The impacts of the identified issue will be addressed consistent with the requirements of 10 CFR 50.46. UNCONTROLLED CONTROL ELEMENT ASSEMBLY (CEA) WITHDRAWAL FROM A SUBCRITICAL CONDITION. S4R SECTION 15.1.1 Considerations for the CEA withdrawal event from suberitical conditions include minimum DNBR and fuel centerline melt. The reduction in RCS flow will have an impact on these considerations; hence, this event was reanalyzed. This event was reassessed for Cycle 13 with reduced RCS flow. The results of this effort are presented below. The withdrawal of CEAs from subcritical conditions (less than 10" percent power) adds reactivity to the reactor core, causing both the core power level and the core heat flux to increase. Since the transient is initiated at low power levels, the normal reactor feedback
' mechanisms, moderator feedback, and Doppler feedback do not occur until power generation in the core is large enough to cause changes in the fuel and moderator temperatures. The Reactor Protection System (RPS) is designed to prevent such a transient from resulting in a minimum DNBR less than 1.25 by a high logarithmic power level reactor trip. The high linear _
Attachment I to 2CAN099701 l- Page 8 of138 power level, and the Core Protection Calculator (CPC) variable overpower trip (VOPT) high l local power density and low DNBR trips provide backup protection while the high pressurizer pressure trip provides protection for the Reactor Coolant Pressure Boundary.
- A continuous withdrawal of CEAs could result from a malfunction in the Control Element Drive Mechanism Control Tystem (CEDMCS) or by operator error.
Startup of the reactor involves a planned sequence of events during which cenain CEA groups l are withdrawn, at a controlled rate and in a prescribed order, to increase the core reactivity gradually from subcritical to critical. To ensure that rapid shutdown by CEA: is always possible when the reactor is critical or near critical, Technical Specifications require that specified group of CEAs be withdrawn before reaching caiticality. These groups of assemblies combined with soluble boron concentration will have a total negative reactivity worth that is sufficient to provide at least the Technical Specification required shutdown margin at the hot standby condition, with the most reactive CEA assumed to remain in the fully withdrawn position. The CEA Withdrawal from Subcritical conditions was analyzed using CENTS and CETOP computer codes. CENTS is described in Reference 2, Two reactivity addition rates were considered,0.00025 Ap/sec and 0.0002 Ap/sec as Case 1 and 2 respectively. These reactivity addition rates are consistent with the maximum addition rates expected for bank withdrawals near critical conditions. Due to the planned sequence or , vents for a controlled startup, boron concentrations are maintained at levels which pro ents criticality for most CEA bank withdrawals. Under certain conditions criticality can be attained with the right combination of CEA bank withdrawal and boron concentration. Only bank withdrawals which will result in critical conditions are considered for this event. The inputs used in these analyses are provided in Table 12, the Cycle 13 physics data above, and the following assumptions: A. A steam generator tube plugging limit of 30% was considered. B. CEA scram worth was not credited on trip, rather a CEA coil decay time of 0.6 seconds was assumed followed by negative reactivity proportional to the CEA position post tiip. Reactivity is held constant for the 0.6 second delay time. After the 0.6 second delay, negative reactivity equivalent to the positive reactisity added prior to the trip is inserted, at a rate consistent with the CEA position versus time curve of Figure 4, C. The BOC- Doppler curve of Figure 2, which includes a 0.85 multiplier, is conservatively used. D. The Cycle 13 delayed neutron fraction and effective neutron lifetime consistent with the above was assumed. The sequence of events for these two reactivity insertion rate transients is provided in Tables 13 and 14. The maximum predicted fuel centerline temperature is less than 2800'F and the
Attachment I ts 2CAN099701 Page 9 of138 minimum DNBR is greater than 1.25. Based on these results the specified acceptable fuel design limits (SAFDLs) and the RCS pressure boundary limits are not violated. UNCONTROLLED CEA WITIIDRAWAL FROM CRITICAL CONDITIONS. SAE SECTION 15.1.2 Similar to the suberitical CEA withdrawal, considerations for the CEA withdrawal event from critical conditions include minimum DNBR and fuel centerline melt. Reducing RCS flow has a minimal impact on these considerations for this event. This event was reassessed for Cycle 13 with reduced RCS flow. The results of this effort are presented below. l The withdrawal of CEAs from a critical condition (greater than lod percent power) adds reactivity to the reactor core, causing the core power level to increase. A continuous withdrawal of CEAs could result from a malfunction in the Reactor Regulating System (RRS), the CEDMCS or by operator error. No failure which can cause CEA withdrawal or insertion can prevent the insertion of CEA banks upon receipt of any protective system reactor trip signal. Analyses have shown that the most adverse results for the CEA withdrawal events occur with the maximum reactivity addition rates. The analysis of the CEA withdrawal from critical conditions therefore utilizes the maximum reactivity addition rate with the CEA withdrawal speed of 30 in/ minute. The CEA withdrawal event from critical conditions is considered from hot zero power (IIZP) and hot full power (IIFP) conditions. An assessment of the IIZP case will be presented first followed by an evaluation of the IIFP condition. CEA Withdrawal froniIlZP A CEA withdrawal from IlZP conditions was analyzed using CENTS and CETOP computer codes. The inputs used in this analysis are provided in Table 15, the Cycle 13 physics data above, and the following assumptions: A. A steam generator tube plugging limit of 30% was modeled. B. The worth of the CEAs at trip was assumed to be 2%. The CEA drop time is consistent with Figure 4 with the 0.6 second holding coil delay time; however, a more conservative normalized reactivity insertion versus CEA position for a +0.6 ASI curve was assumed. C. The BOC Doppler curve of Figure 2, which includes a 0.85 multiplier, is conservatively used. D. The Cycle 13 delayed neutron fraction and effective neutron lifetime consistent with the above information was assumed.
Attachment I to 2CAN099701 Page 10 of138 The sequence of events for this transient is provided in Table 16. The maximum fuel centerline temperature is less than 3330 'F and the minimum DNBR is s. eater than 1.25. Based on these results the specified acceptable fuel design limits (SAFDLs) are not violated. CEA Withdrawal from HFP The CEA bank withdrawal event was examined as the fastest rate ofincreasing power with respect to the anticipated operational occunences (AOOs) for which the CPCs ensures that the SAFDL: would not be violated. An evaluation was performed to validate that the response of the CPC compensated neutron flux power for a CEA withdrawal event is l conservative with respect to the actual rates for both the core power and core heat flux increase given this event. By ensuring the CPC protective calculations are conservative, the SAFDLs would not be violated. As the purpose of this assessment is to ensure CPCs perform their protective function, the l dynamic effects of a CEA withdrawal event that result in the most challenging rate of power l increase needs to be considered. A sensitivity study was performed on RCS flow validating that high initial RCS flow rates are the most challenging; hence, the reduction in RCS flow does not have a significant impact on this event. CEA MISOPERATION. SAR SECTION 15,1,3 The CEA drops are considered as part of the required overpower margin (ROPM) events. The analyses calculating the ROPM: are co c'4ered for each reload cycle in the determination of COLSS inputs and operating limits v* gare that the DNDR SAFDL would not be exceeded. The ROPM: for CEA withdrawak, .oss of RCS flow events, asymmetric steam generator transient, fulllength CEA drops, and other anticipated operational occurrences are determined to find the most limiting value. The full length CEA drop events produce reductions in power, relatively alow changes to the core power distribution, and are much less significant for the purposes of determining COLSS inputs and operating limits. Although the reduced RCS flow would have a slight impact on DNBR following a CEA drop, the COLSS inputs and operating limits established with each reload will assure that the DNBR SAFDL will not be exceeded in the event of a dropped CEA. A specific reanalysis of the event to account for RCS flow reduction effects is unnecessary as other anticipated operational occurrences remain bounding. The power distortion factors resulting from a dropped rod, which are a measure of the power distribution upset, and thus the relative significance of the transient, are compared to bounding values for each reload. This assures that the CEA drop event would be reanalyzed if required. UNCONTROLI ED BORON DILUTION INCIDENT. SAR SECTION 15.1.4 The Uncontrolled Boron Dilution incident is unaffected by the proposed reduction in RCS flow. Although flow is qualitatively assumed to exist to promote mixing, it is not a quantitative input to the analyses. The plugging of steam generator tubes, which causes the ) b
Attachment I to 2CAN099701 Page 11 of138 flow reduction, also reduces the RCS volume. For the more limitir.g dilution events in Modes 3,4, 5 and 6, the reactor coolant pumps are assumed to be off and the stagnant volume of the steam generators is conservatively not included in the dilution volume. Thus the volume reduction has no impact in these operational modes. Since the reactor coolant pumps are running for the events in Modes 1 and 2, the full volume of the RCS (less the pressurizer and surge line) is included in the dilution volume. Ilowever, the uncontrolled borun dilution incidents in Modes 1 and 2 are much less limiting because of the large dilution volume which reduces the rate of boron dilution and a boron dilution event in Modes 1 or 2 will result in a rapid reactor shutdown by the reactor protection system. Consequently, the volume reduction does not significantly impact the events in Modes 1 and 2. For purposes of comparison, the time of 93 minutes from the start of the event to the loss of shutdown margin, included in l Reference 4 for Mode 2, is decreased to 86 minutes with 30% of the steam generator tubes plugged. l TOTAL AND PARTIAL LOSS OF REACTOR COOLANT SYSTEM (RCS) FORCED FLOW. SAR SECTION 15.1.5 A loss of reactor coolant forced flow can result from the occurrence of a mechanical or electrical failure. A partial loss of flow can occur as the result of a mechanical or electrical failure in a reactor coolant pump or from a loss of power to the pump bus. A complete loss of coolant flow results from a simultaneous loss of electrical power to all operating reactor coolant pumps. A four pump loss of flow event due to a simultaneous loss of electrical power and a seized rotor event are considered separately below. Due to the Technical Specification Limiting Conditions for Operation (LCOs) on DNBR margin, by the response of the RPS which provides an automatic reactor trip as calculated by the CPCs, and Core Operating Limits Supervisory System (COLSS) calculating the power operating limit to ensure adequate thermal margin to DNB, the effects of a reduction in initial RCS flow for these events does not have a significant impact. Consideration of these events relates more to the potential impact of 30% steam generator tube plugging, as the increased system resistance could affect the post event RCS flow. FOUR PUMP LOSS OF COOLANT FLOW ANALYSIS To determine the impacts of a 10 percent reduction in RCS design flow and 30 percent steam generator tube plugging on the Four Pump Loss of Flow analysis, the following evaluation was performed. This evaluation has employed the HERMITE computer code (Reference 1) instead of the CESEC code used previously for this event. The CENTS computer code (Reference 2) has replaced the COAST program for calculating the RCS flow coastdown. For a loss of flow at any power operating condition, a reactor trip will be initiated when any one of four Reactor Coolant Pump (RCP) shaft speeds drops to 95 percent ofits nominal speed, in this method, the partial loss of flow resulting from a loss of electrical power to three or less RCPs is less limiting than a four pump loss of flow. This is because the reactor will trip at the same time for both cases but the partial loss of flow has a slower flow coastdowm. Therefore, only the four pump loss of flow event is presented herein.
Attachment I to 1CAN099701 Page 12 of138 Method of Analysis The analysis was carried out in the following steps: A. N RCP coastdown data for the loss of flow event was generated using the CENTS code. W use of the CENTS code is a change from the original coastdown analysis which used the COAST code. Coastdown data to account for 30% steam generator tube plugging was determined by Arst benchmarking h CENTS coastdown results against the original coastdown data from the COAST code and plant specinc coastdown data. W CENTS basedeck was then adjusted to account for the 30% steam generator tube plugging. The CENTS coastdown analysis considered the affects of both symmetric and asymmetric steam generator tube plugging (up to 1000 tube asymetry). The coastdown analysis also considered the effects of initial RCS pressure, temperature, and flow. W resulting coastdown data generated kom CENTS was used as input to the HERMITE code. B. The HERMITE code is used to determine the reactor core response during the postulated loss of Aow event. The HERMITE code solves the few group, space and tbne dependent neutron difhasion equation including the feedback effects of fuel temperature, coolant temperature, coolant density, and c.ontrol rod motion for a one-dimensional average fuel bundle. C. The time dependent thermal hydraulic information generated from the HERMITE code is transferred directly to the CETOP computer code (Reference 3) for thermal margin and DNBR evaluation. The CETOP method wu used to calculate both the time of occerrence :.nd value of the minimum DNBR during the transient. Input Parameters and Initial Conditions The four pump loss of flow event used the conservative assumptions provided in Table 17 including the Cycle 13 physics data and the following assumptions: A. A CEA insonion curve consistent with the CEA position versus time presented in Figure 4 was assumed. This curve accounts for a 0.6 second holding coil delay. B. A BOC delayed neutron & action of 0.0072546 was assumed. C. A BOC fuel temperature coefficient of-0.0013 Apl@K was assumed. D. For this analysis, a trip on low RCP speed is the primary trip for the loss of flow event, replacing the trip on low flow projected DNBR. A CPC trip is initiated when the RCP shaR speed drops to 95 percent ofits normal speed. The four pump loss of coolant flow produces an approach to the DNBR limit due to the decrease in the core coolant flow. Protection against the DNBR limit for this transient is
Attachment I ts 2CAN099701 Page 13 of138 provided by the initial steady state thermal margin which is maintained by adhering to tlw Technical Speci6 cation LCOs on DNBR margin and by the response of the RPS which provides an automatic reactor trip as calculated by the CPCs. The principal process variables that determine thermal margin to DNB in the core are monitored by the COLSS. The COLSS computu a power operating limit which ensures that the thermal margin available in the core is equal to or greater than that needed to cause the minimum DNBR to remain greater than the DNBR limit. The minimum thermal margin required (reserved) in COLSS for the loss of flow event is set equal to the maximum thermal margin degradation observed during a loss of flow event. The initial conditions are selected such that the system is at a very subcooled state. Initiating the event from such a state results in the least amount of negative reactivity inserted due to generation of voids in the RCS. In this manner the system undergoes the greatest amount of thermal margin degradation due to the RCP coastdown. To demonstrate explicitly that the DNBR SAFDL is not violated during a loss of flow event, a sample case is provided in which the initial conditions are chosen such that at the onset of the event the minimum thermal margin required by the COLSS power operating limit is presened. This analysis has used an RCS flow of 108.36 Mlbm/hr which is 90 percent of the minimum design flow corresponding to 30 percent tube-plugging. Figure 11 provides a graph of the RCS flow coastdown used for the loss of flow event with 30% steam generator tube plugging. The consequences following a total loss of forced reactor coolant flow, with respect to approaching the DNBR SAFDL, initiated firom any
- ofinitial conditions which preserve the minimum COLSS margin would be no more adverse than those presented herein.
Results The results of this analysis is the calculation of minimum thermal margin required to be reserved in COLSS to prevent the violation of the DNBR SAFDL during a loss of flow event. With a minimum thermal margin reserved in COLSS, the minimum DNBR observed during this event is 1,29 at 2.8 seconds. The sequence of events for the four pump loss of flow assuming 30% steam generator tube plugging is provided in Table 18. Figure 12 provides a graph of DNBR versus time for the event. For the loss of flow event, the CPC trip on pump low speed in conjunction with the initial margin reserved in COLSS is sufficient to prevent the violation of the DNBR SAFDL from any set ofinitial conditions. SEIZED ROTOR When analyzing the seized rotor event, the event is initiated from a power operating limit with the minimal acceptable thermal margin to the DNBR limit. Based on this consideration, the initial RCS flow does not have a significant impact on the analysis results. Rather, the change in flow rate from the initial value to the final flow rate is a critical parameter. Due to the potential that increased tube plugging may affect the change in flow rate, an evaluation was
Attachment I to 2CAN099701 Page 14 of138 performed to determine the effective change in flow rate due to 30% steam generator tube Pl ugging. This analysis concluded that the Anal" steady state" flow fraction for the 30% steam generator tube plugging case is essentially equal to the " steady state" flow fraction used in the analysis of record. The coastdown data for the seized rotor event was generated using the CENTS code. The une of the CENTS code is a change from the original coastdown analysis which used the COAST code. The analysis of record seized rotor event assumes an instantaneous drop from the initial flow rate to the reduced " steady state" flow fisction. Based on the above, this assumption remains valld; therefore, a reanalysis of the seized rotor event was not required. IDLE LOOP STARTUP. SAR SECTION 15.1.6 Idle loop startup b denned as the startup of a reactor coolant pump, without observance of prescribed operating procedures, assuming that both reactor coolant pumps in that loop were idle. ANO 2 was originally designed to permit continued operation with one or two reactor coolant pumps idle. The Technical Specifications for ANO 2, however, precluded critical operation with any inoperative pumps. As the conditions leading to this event are not allowed by the Technical Specifications no consideration was given for a reduction in RCS flow. LOSS OF EXTERNAL LOAD AND/OR TURBINE TRIP. SAR SECTION 15.1.7 Loss of external load and/or tuibine trip results in a reduction of steam flow from the steam generators to the turbine generator. Cessation of steam flow to the turbine generator occurs - because of closure of the turbine stop valves or turbine control valves. The cause ofloss of load may be abnormal events in the electrical distribution network or turbine trip. The bounding event considered is a loss ofload event initiated by a turbine trip without a simultaneous reactor trip and assuming the Steam Dump and Bypan system is inoperable, if the turbine trip were caused by a Loss of Condenser Vacuum, the main feedwater pump steam turbines would trip at the same time. Therefore, a loss ofload concurrent with loss of feed was analyzed to cover these events. The loss of load causes steam generator pressure to increase to the opening pressure of the main steam safety valves. The reduced secondary heat sink leads to a heatup of the RCS, The transient is terminated by a reactor trip on high pressurizer pressure. The loss of extemal load and/or turbine trip was undertaken for Cycle 13 to account for Cycle 13 input parameter variations and considering the effects of 30% tube plugging and a reduction in RCS flow, For the analysis presented herein, the CENTS computer code described in Reference 2 was utilized.
Attachment I to 2CAN099701 Page 15 of138
-Sensitivity studies wwe conducted on the effects of steam generator tube plugging and reductions in RCS Sow. The results of these sensitivity studies indicated that RCS flow has a very minor impact on the analysis results with higher RCS flows resulting in slightly higher peak primary pressures and lower RCS Rows resulting in higher peak secondary pressures.
The effects of steam generator tube plugging indicated that no steam generator tube plugging was slightly more conservative for both primary and secondary peak pressures. i Input parameters from Table 19 and the Cycle 13 physics parameters above have boon incorporated in the following peak RCS pressure analysis. A summary of the principal results for the loss of external load / loss of condenser vacuum are given in Table 20. These results Indicate that the peak primary pressure is 2683 psia and the peak secondary pressure is 1162 psia. A separate analysis was performed to determine a conservative peak secondary pressure, as the input assumptions described above and denoted in Table 19 are established to ensure a peak primary pressure. This second analysis is effectively the same as the peak primary analysis except the input assumptions delineated above are adjusted to ensure a conservative peak secondary pressure. The results of this second effort indicate a peak secondary pressure of 1195 pala. The results of these analyses shows that the peak RCS and secondary side pressures are maintained less than 110% of design values. LOSS OF NORMAL FEEDWATER FLOW. SAR SECTION 15.1.8 The lou of normal feedwater flow is defined as a reduction in feedwater flow to the steam generators when operating at power, without a corresponding reduction in steam flow from the steam generators. The result of this mismatch is a reduction in the water inventory in the steam generators. The Emergency Foodwater (EFW) system is available to automatically provide sufHclent feedwater flow to remove residual heat generation from the RCS following a reactor trip from rated power. This system consists of one motor-driven and one turbine-driven emergency foodwater pump, and a non safety Auxiliary Feedwater pump. A complete loss of both main feedwater pumps or all four condensate pumps and the turbine driven pump results in the loss of all normal feedwater. In manual feedwater control, closing the feedwater regulating or isolation valves also results in lou of normal feed flow. The Plant Protection System provides protection against loss of the secondary heat sink by the steam generator low water level trip and automatic initiation of the EFW system. The high pressurizer pressure trip provides protection in the event that the RCS pressure limit is approached. The impacts of reducing RCS flow on this event were considered. Based on a sensitivity study performed on RCS flow, lower RCS flow rates resulted in lower post trip steam -
Attachment I ts 2CAN099701 i Page 16 of138 generator inventories. The following analysis was performed for Cycle 13 with reduced RCS flow. This evaluation has utilized the CENTS computer code described in Reference 2. Inputs from Table 21 and Cycle 13 physics data presented above were used in this analysis with the following clari6 cations: A. An EFW response time of 97.4 seconds was assumed. EFW Aow was l determined based on steam generator pressure. Prior analysis efforts assumed a constant flow rate regardless of steam generator pressure. B. The EOC Doppler curve in Figure 2 which includes a 1.4 multiplier is-conservatively used. C. The Cycle 13 delayed neutron fraction and neutron lifetime consistent with the data presented above was assumed. D. The Cycle 13 CEA insestion curve in Figure 3 was utilized. This curve
, accounts for a 0.6 second holding coil delay.
E. An MSSV tolerance of 3% is conservatively assumed. A summary of the principal results for the loss of normal feedwater flow is given in Table 22. These results support the conclusion that the steam generator heat removal capability is maintained. LOSS OF ALL NORMAL AND PREFERRED AC POWER TO THE STATION AUXILIARIES. SAR SECTION 15.1.9 The loss of AC power is defmed as a complete loss of preferred (off site) AC electrical power and a concurrent turbine generator trip. As a result, electrical power would be unavailable for the station auxiliaries such as the reactor coolant pumps, the main feedwater pumps and the main circulating water pumps. Undw such circumstances, the plant would experience a simultaneous loss orload, feedwater flow, and forced reactor coolant flow. This event was not reanalyzed for the reduction in RCS flow rate. As indicated above for the four pump loss of flow, lou of external load, and loss of normal feedwater events, reducing RCS flow has minimal impact on these events. Additionally, tlw minimum DNBR considerations for this event are bounded by the consideration made in the four pump loss of flow event; hence, reducing RCS flow rate has been determined not to have a significant impact on the loss of all AC event.
Attaciunent I ts 2CAN099701 Page 17 of138 EXCESS HEAT REMOVAL DUE TO SECONDARY SYSTEM MALFUNCTION. SAR SECTION 15.1.10 The excess heat removal events include several different transients that place an increased heat demand on the primary system. Steam and feedwater system malfunctions were considered for their potential impact on the fuel design limits. Various valve failures in both systems were evaluated to determine those that would cause the greatest increase in secondary heat removal. With the assumption of a negative moderator temperature coefficient, these events produce an increase in core power and a reduction in DNDR. Depending on the extent of the cooldown, the event may be ended by a trip, or a new equilibrium condition, at a higher power level could result. As overcooling events, the dynamic impact of the transient on the primary system is directly dependent on the rate of heat transfer through the steam generators. The reduced heat transfer resulting from tube plugging will slow the cooling of the primary system. The reduced RCS flow will tend to increase the rate of primary cooldown for a given rate of heat transfer. These changes will affect the dynamics of the transients which will impact those events that lead to a reactor trip. The CPCs and RPS assure that a reactor trip will occur before the SAFDLs are exceeded by an excess heat removal event. To assure that the CPCs can accurately sense the cooldown associated with an excess heat removal event, even with the change in transient dynamics due to tube plugging and RCS flow reductions, a CPC transient filters analysis was performed for Cycle 13. The CPC transient filters analysis verifles the CPC adjusted process parameters are conservative with respect to the expected values for a given transient event. The CPC coefficients are adjusted as necessary to assure the CPC action prevents SAFDL violation during the transient. This analysis included parametric studies on RCS flow and tube plugging to determine the limiting values of these inputs. The design minimum RCS flow reduced by 10%, and 0% tube plugging were limiting assumptions to a CENTS analysis of an excess heat removal event. The results of the analysis verifies proper detection of significant overcooling transients and conservative CPC actions. Consequently, the effects of tube plugging and reduced flow on the significant excess heat removal events have been evaluated. This evaluation ensures that the CPCs and RPS will provide the necessary trip functions to prevent the SAFDL: from bcNg violated. FAILURE OF Tile REGULATING INSTRUMENTATION. SAR SECTION 15.1,11 A reactor coolant flow controlled malfunction is not possible. ANO.2 does not have conlant flow controllers. Therefore, a reduction in the RCS flow will not affect this event.
Attachtnent I ts 2CAN099701 Page 18 of138 INTERNAL AND EXTERNAL EVENTS INCL,UDING MAJOR AND MINOR FIRES. FLOODS. STORMS. AND EARTilOUAKE. SAR SECTION 15,1,12 RCS flow is not a consideration in these events as such no evaluation is necessary for a reduction in RCS flow. MAJOR RUPTURE OF PIPES CONTAINING REACTOR COOI. ANT UP TO AND INCLUDING DOUBLE-ENDED RUPTURE OF LARGEST PIPE IN TIIE REACTOR COOLANT SYSTEM (LOCA). SAR SECTION 15,1,13 This section of the SAR, Section 15,1,13, relates only to the consequences of a LOCA. RCS flow is not a consideration with respect to the offsite releases from a LOCA. The lirniting doses to the control room operator, which result from LOCA releases, are similarly unaffected by RCS flow considerations. The requirements with respect to 10CFR50.46 are covered in Section 6.3.3 of the SAR. RCS flow is a parameter for consideration in this event which is discussed above. MAJOR SECONDARY SYSTEM PIPE BREAKS WITil OR WITilOUT A CONCURRENT LOSS OF AC POWER - MAIN STEAM LINE BREAK (MSLB) AND FEEDWATER LINE BREAK (FWLB). SAk SNION 15,1,14 STEAM LINE BREAK A reduction in RCS flow will result in an increase in the RCS energy due to an increase in the hot leg temperature for a given cold leg temperature. Tids increase in energy results in a slightly larger cooldown following a MSLB, As a result, the MSLB has been evaluated. The Cycle 13 analysis accounts l'or a 10% reduction in RCS flow in addition to the affects of a low steam generator pressure setpoint of 620 psia. The following is a sununary of the Cycle 13 analysis wideh includes the reduced RCS flow and various other conservative assumptions. The no moisture carryover steam line break events were reanalyzed to account for a 10% reduction in the RCS design flow, a small increase in feedwater flow, a lower low steam generator pressure setpoint, and to address Cycle 13 physics data. CENTS was used to model the Nuclear Steam Supply System (NSSS) response, RCP coastdown and natural circulation, RELAPS was used to model the feedwater system response for the hot full power (l!FP or full load) cases, HRISE was used to calculate thermal margin on DNBR, and ROCS /IIERMITE were used to assess reactivity feedback and peaking. The analytical basis for the liFP and hot zero power (IlZP) simulations are discussed below. A. A double-ended guillotine break (6.357 ff) causes the greatest cooldown of the RCS and the most severe degradation of shutdown margin,
3 l
- Attachment i 13 -
2CAN099701
' j
- Page 19 of138 1
~
B. A break inside the containment building, upstream of the Main Steam Isolation Valves (MSIVs) and flow measuring venturis causes a non Isolable condition in the affected ! steam generator, i C. A SIAS is actuated when the pressurlzer pressure drops below 1400 pala. Time delays associated with the safety injection pump acceleration and valve opening are taken into 4 account. A 40 second HPSI response time was assumed to account for these delays.
- . Additionally, the event was initiated from the highest pre sure allowed by the Technical Specifications to delay the effect of the safety injection boron.
D. The cooldown of the RCS is terminated when the affected steam generator blows dry. As the coolant temperatures begin increasing, positive reactivity insertion from moderator reactivity feedback decreases. The decrease in moderator reactivity l combined with the negative reactivity insened via boron injection cause the total l reactivity to become more negative. ! E. CENTS is used to model the RCP coast down on a loss of offsite power. The CPC low DNBR (based on pump speed) trip la credited in this analysis following a loss of offdte power. A CPC low DNBR trip setpoint based on 96.5% of RCP speed with a 1,0 second response time is assumed. F. A low steam generator pressure reactor trip setpoint of 620 psia was assumed with a 1.3 second response time. 3 O. Main Steam Isolation Signal (MSIS) is actuated on a low steam generator pressure setpoint of 620 psia. The MSIVs, Main Feedwater leolation Valves (MFIVs) and Back-up MFIVs all receive an MSIS signal to close. A response time of 4.3 seconds l was assumed for the MSIVs. The MFIVs and Back-up MFIVs were assumed to close in 36.4 seconds and 31.8 seconds with a loss of offsite power, and 21.4 seconds and 16.8 seconds with offsite power available, respectively. H. The HERMITE code was used to calculate the reactivity for the post trip return to power portion of the analysis. This was done sinco the HERMITE code, which is a
~
l three-dimensional coupled neutronics-open channel thermal hydraulics code, can more ! - accurately model the effects of moderator temperature feedback on tim power distribution and reactivity for the critical configuration existing during the return to power. The HERMITE results used in the ANO-2 analysis were actually obtained from a parametric study performed for Calvert Cliffs Unit 1 Cycle 7. ANO 2 specific - ROCS calculations were used to confirm the applicability of these parametric results to ANO-2, , l.. Three-dimensional power distribution peaks (Fq) were determined with the above mentioned ROCS and HERMITE evaluations. Axial profiles consistent with these conservative power distribution peaks were utilized in the analysis.
=
war,r-+,e-g n-=7 %,t--e$.----~--=res o p.e ,m.rg-.iw-,.w,9 r,,,,-,,-r- e + 9 w--w wr e w+--ww,w -m--'s - e e -e + sr e r- + ~9 +v== me---- v=e'-&w- -r-~w-- ---r-,' -" =
Attachment I to 2CAN099701 Page 20 of138 J. The power produced by the decay of the initial condition delayed neutron precursors and by nominal decay power is distributed according to the nominal power distribution. K. The thermal margin on DNDR in the reactor core was simulated using the IIRISE computer program. RCS conditions from CENTS (RCS temperature, pressure, flow, and power) are used in the IIRISE thermal margin calculations. The conservative assumptions included in the IIZP and IIFP simulations are discussed below. The MTC assumed in the analysis corresponds to the most negative value. This negative MTC results in the greatest positive reactivity addition during the RCS cooldown caused by the steam line break. Since the coemcient of reactivity associated with moderator feedback varies significantly over the range of moderator density covered in the analysis, a curve of
- reactivity inserdon versus moderator density rather than a single value of MTC is assumed in the analysis. The moderator cooldown curve used in the analysis (Figure 13) was conservatively calculated assuming that on reactor trip, the highest wonh control element assembly is stuck in the ibily withdrawn position. The effect of uneven temperature l distribution on the moderator reactivity is accounted for by assuming that the moderator reactivity is a function of the lowest cold leg temperature.
For conservatism, the full steam generator heat transfer surface area is assumed to always be covered by the 2-phase level until a steam generritor becomes essentially empty. The reactivity defect associated with fuel temperature decrease is based on the most negative t Fuel Temperature Coeflicient (FTC). Figure 14 represents the ITC curve used in the analysis. Tha rTC, in conjunction with the decreasing fuel temperatures, causes the greatest positive reactivity insertion during the steam line break event. The delayed neutron fraction assumed is the maximum value including uncertainties for end oflife conditions (total delayed neutron fraction, p, 0.005994). This too maximizes suberitical multiplication and thus increases the potential for return to power. The minimum CEA worth assumed to be available for shutdown at the time of reactor trip at the maximum allowed power level is -7.5144 % Ap. For the IIZP cases a shutdown CEA worth of 5.0 % Ap was used. The scrun worths used are consistent with the moderator cooldown curve and stuck rod assumed in the analysis. The CEA reactivity addition curve of Figure 3 adjusted to a worth of 7.5144 was used in the llFP cases. The IIZP cases assumed a CEA drop time consistent with Figure 4 with the 0.6 second holding coil delay time; however, a more conservative normalized reactivity insertion versus CEA positica for a +0.6 ASI curve was used. The EFW system is conservatively modeled to initiate early with both EFW pumps available, this maximizes the potential cooling that could occui. System response times, flows and setpoints are assumed based on increasing the cooling potential of the EFW system.
Attachtnent I ta 2CAN099701 Page 21 of138 The analysis assumed that, for the loss of AC power cases, one EDG failed to start. The failure of an EDG results in the failure of one IIPSI pump and one of the main feedwater isolation valves to close. The faster closing back-up main feedwater isolation valves were assumed to remain open. For the llFP case with AC available, a bus fast transfer failure is the most limiting single failure as this failure is modeled as the failure of the back-up main feedwater isolation valves and a IIPSI pump. A fast transfer failure would only result in the delayed actuation of the back up main feedwater isolation valves and IIPSI purnp. These components would be actuated once the EDO has started. Therefore, the modeling of the fast transfer failure is conservative. This conservative modeling of a fast transfer failure is slightly more limiting than the single failure of a main feedwater pump to trip, which was determined to be more litniting 'n the Cycle 12 analysis. A single failure of a !! PSI pump to start was assumed for the '.fzP case with AC available. The boration from the Safety injection Tanks was not credite9 in this analysis. The liFP feejwater addition to the steam generator assumed in this analysis is taken from the Cycle 12 analysis which used a REl AP5 model of the feedwater system. The steam generator pressure profiles and time of MSIS were verified to be consistent with respect to this analysis, l thereby allow' m g the application of the feedwater data generated for CyO 12. ThellFP l feedwater data for Cycle 12 was increased by 1% to account for a small expced increase in feedwater flow due to modifications to the high pressure turbine For the hot zero power (llZP or no load) cases, feedwater flow is modeled by matching the energy input by the core at the start of the event. The key parameters used for the post-trip steam line break analyses are listed in Table 23. Tables 24 through 27 present the sequence of events for the liFP and llZP steam line break cases with and without a concurrent loss of AC power, Figures 15 through 38 show the transient response for key parameters. The results of this analysis indicate that the IIFP cases remain subcritical through out the post trip event. The new maximum post inn reactivity vale s are -0.029 and -0.338 considering a loss of AC and offsite power available, respectively, the peak return to power and minimum DNBR values are 2.61% and 1.81, and 4.98% and 2.46 considering a loss of AC and offsite power available, respectively. The IIZP results of this analysis indicate a slight retum to critical; however, this return to critical is bounded by the FSAR results. The new maximum post trip reactivity values are
+0.252 and %.227 considering a loss of AC and offsite power available, respectively. These values are bounded by the FSAR analysis results of +0.43 and +0.34. The peak return to power and minimum DNBR values are 0.41% and 12.3, and 1.275% and 11.2 considering a loss of AC and offsite power available, respectively.
As these results indicate acceptable DNDR values, no fuel failure is predicted. The results of the steam line break analyses demonstrated that there was no calculated fuel failure, thus the coolable geometry is maintained.
Attachment I t3 2CAN099701 Page 22 of138 FEEDWATER LINE BREAK The FWLB event was assessed for a lower low steam generator trip setpoint of 620 psia. During this effort the effects of a 10% reduction in RCS flow and 30% steam generator tube plugging were considered. The results of sensitivity studies on RCS how indicated minimal effects on the analysis results due to changes in RCS flow. Steam generator tube plugging effects indicated that 0% tube plugging resulted in alightly higher peak RCS pressures. Steam generator tube plugging results in a slightly slower RCP coastdown due to the increased system resistance which allows for improved heat transfer to the secondary system; thereby, producing slightly lower peak primary pressures As the limiting case for peak RCS pressure is not affected by RCS flow and steam generator tube plugging, the analysis results are not presented here. INADVERTENT I,OADING OF A FilEl; AS5iEMUIN INTO TIIE IMPROPER POSITION. SAR SECTION 15,1,15 l Two accidents are considered in this section: 1) the erroneous loading of fuel pellets or fuel rods of different enrichment in a fuel assembly; and, 2) the erroneous placement or orientation ofIbel assemblies. Neither of these events consider RCS flow as a parameter; hence, reducing RCS flow will not affect this event. WASTE GAS DECAY TANK 1.EAKAGE OR HliPTi1RE. SAR SECTION 15.1.16 The most limiting waste gas accident is an unerpected and uncontrolled release to the atmosphere of the radioactive xenon and krypton fission gases that are stored in one waste gas decay tank. This event is unalrected by RCS flow. FAII,IIRE OF AIR EJECTOR I,1NES (BWR), SAR SECTION 15.1.17 This event is not applicable to ANO 2. STEAM GENERATOR TUSE RtiPTilRE WITil OR WITIIOllT A CONCtfRRENT 1,OSS OF AC POWER (SGTR), SAR SECTION 15.1.18 The steam generator tube rupture accident with or without a loss of AC power is a penetration of the barrier between the RCS and the main steam system. Integrity of this barrier is significant from a radiological standpoint, since a leaking steam generator tube would allow transport of reactor coolant into the main steam system. Radioactivity contained in the reactor coolant would mix with shell side water in the atrected steam generator. This radioactivity would be transported through the turbine to tne condenser, where the non-condensable radioactive materials would be released to the auxiliary building ventilation system via the condenser vacuum pumps if AC power is available.
~ l l l Attachment I to 2CAN099701 Page 23 of138 Reducing RCS flow by 10% and plugging 30% of the steam generator tubes will result in slightly higher hot leg temperatures for a given cold leg temperature, and lower steam generator pressures. Increased hot leg temperatures will result in a greater flashing fraction for the primary system fluid entering the steam generator. The increased hot leg temperatures will also result in more energy being stored in the RC3. Both of these factors will slightly increase the radioactivity released to the environment during a steam generator tube rupture. Lower steam generator pressures at the start of the event, due to tube plugging and RCS flow reductions, will allow for an increase in the break flow prior to reactor trip. All of these factors have been evaluated with respect the radioactivity released for a SGTR event. The offsite dose could increase by as much as 30%, but the result would remain well within 10 CFR 100 limits. FAILURE OF CHARCOAL OF CRYOGENIC SYSTEM (BWHL SAR SECTION 15,1,19 This event is not applicable to ANO-2. CEA EJECTION. SAR SECTION 15,1,20 The CEA Ejection Event at both IIFP and IlZP conditions were reanalyzed in Cycle 13 accounting for a 10% reduction in the RCS design flow. RCS flow reduction has an adverse effect on the deposited energy during the event. Methods consistent with those identified in Reference 5 were employed in this analysis. The IIFP and IIZP analyses were performed based on the parameters in Table 28, the Cycle 13 core physics data provided above, and the following input assumptions. A. A Doppler curve consistent with Figure 2 (BOC) was assumed in both the liFP and IIZP analyses. B. A CEA insertion curve consistent with Figure 3 with a 0.6 holding coil delay time was assumed for the liFP case. For the ll2P case, the CEA position versus time of Figure 4 is consistent with the analysis assumption; however, a more conservative normalized reactivity insertion versus CEA position for a +0.6 ASI curve was used. C. The axial power distribution provided in Table 29 was assumed in both cases. D. A CPC DNBR trip (based on VOPT) setpoint of 47% and 134% (of 2815 MWt) with a response time of 0.59 seconds was assumed in the IIZP and HFP analyses, respectively. E. A minimum EOC delayed neutron fraction was assumed.
Attachment I ts 2CAN099701 Page 24 of138 Table 30 lists the acceptable 3D peak F,s versus ejected CEA worth that was generated based on the above parameters and the following acceptance criteria. Clad Damage Threshold: Total Average Enthalpy s 200 cal /gm Fully Molten Centerline Threshold: Total Centerline Enthalpy s 310 cal /gm Cycle specific calculations of the maximum ejected Fq and ejected worth are performed and verifled to fall within the limits calculated above. Based on the above, the maximum total energy deposited during the event is less than the criterion for clad damage and molten centerline temperature. Therefore, results of thlt. I analysis are bounded by the prior analyses. i TIIE SPECTRilM OF ROD DROP ACCIDENTS (HWR), SAR SECTION 15.1.21 This event is not applicable to ANO 2. BREAK IN INSTRUMENT LINE OR OTiiER 1,1NES FROM REACTOR COOIANT PRESSLIRE BOUNDARY TIIAT PENETRATE CONTAINMENT. SAR SECTION f 15.1.22 There are no instrument lines from the RCS which penetrate the containment. FUEI,IIANDLING ACCIDENT. SAR SECTION 15.1.23 This analysis assumes that a fuel assembly is dropped during fuel handling. RCS flow has no etTect on this event. SM Al,1, SPILI S OR LEAKS OF RADIOACTIVE MATERIAL OUTSIDE CONTAINMENT. SAR SECTION 15.1.24 RCS flow is not & consideration for small spills or leaks of radioactive material outside containment. FUEL CLADDING FAILURE COMBINED WITil STEAM GENERATOR LEAK. SAR SECTION 15.1.25
Attachment I ts 1 I 2CAN099701 Page 25 of138 Relear,es resulting from operation with leaking steam generator tubes and defective cladding are not affected by RCS flow. CONTROL ROOM LININil ABITABILITY. SAR SEC'IION 15.1.26 RCS flow is not consideration in the control room uninhabitability event. FAH&BERADYIEPJESSStJRIZATION OF LOW PRESSlfRE RESIDUAL,11 EAT REMOVAL SYSTEM. SAM SECTION 15.1.27 RCS flow is not a consideration for a failure or overpressurization oflow pressure residual heat removal system. LOSS OF CONDENSER VAClitIM (1,0CV). SAR SECTION 15.1.28 Loss of condenser vacuum is sensed by the turbine emergency trip system and results in a turbine-generator trip. An analysis of the effects and consequences of a turbine-generator trip is provided in Section 15.1.7. TilRBINE TRIP WITil COINCIDENT FAIL 11RE OF TtIRBINE BYPASS VALVES TO OPEN, SAR SECTION 15.1.29 This event is described and analyzed in Section 15.1.7. LOSS OF SERVICE WATER SYSTEM. SAR SECTION 15.1.30 RCS flow is not a consideration in a loss of service water system. LOSS OF ONE DC SYSTEM SAR SECTION 15.1.31 RCS flow is not a consideration in a loss of one DC system. INADVERTENT OPERATION OF ECCS DtIRING POWER OPERATION. SAR SECTION 15.l.32 RCS flow is not a consideration for an inadvertent operation of ECCS during power operation.
Attachment I to 2CAN099701 Page 26 of138 TtfRBINE TRIP WITil FAILilRE OF Gt:NERATOR BREAKER TO OPEN. SAR SECIION 15.1.33 RCS flow is not a consideration for a turbine trip with failure of generator breaker to open. LOSS OF INSTRLIMENT AIR SYSTEM. SAR SECTIUm 15.l.34 RCS flow is not a consideration for a loss ofinstrument air system. MALFilNCTION OF TtfRBINE GLAND SEALING SYSTEM. SAR SECTION 15.1.35 RCS flow is not a consideration for a malfunction of turbine gland sealing system. TRANSIENTS REStiLTING FROM TIIE INSTANTANEOliS CLOStIRE OF A SINGLE MSIV. SAR SECTION 15.1.36 The Cycle 13 evaluation of the Asymmetric Steam Generator Transient (ASGT) event has been performed considening a 10% reduction in RCS flow. Assuming minimum RCS flow is not necessarily bounding for consideration in the ASGT event when determining the required overpower margin (ROPM). However, an ASGT event is typically not limiting with respect to ROPM requirements. The following event was assessed to demonstrate that acceptable results are expected when considering a 10% reduction in RCS flow and the ASGT event is non limiting with respect to ROPM. This evaluation has utilized the CENTS computer code described in Reference 2. Input parameters from Table 31 and the Cycle 13 physics data presennd above have been incorporated in this analysis with these following clarifications: A. The BOC Doppler curve in Figure 2 which includes a 0.85 multiplier is conservatively used. B. The Cycle 13 delayed neutron fraction and neutron lifetime consistent with those defined above were assumed. C. The Cycle 13 CEA insertion curve in Figure 3 was utilized. This curve accounts for a 0.6 second holding coil delay and a CEA worth of 5%. D. A CPC asymmetric steam generator trip setpoint of II*F was assumed. Cold and hot leg RTD response times of 8 seconds and 13 seconds, respectively, were accounted for along with a CPC trip delay time of 0.59 seconds. E. The Cycle 13 analysis was performed at 90% power and assumed a nominal RCS pressure of 2250 psia.
. . . . _ _ _ . _ _ _ _ =. _ _ _ _ _ _ _ . _ _ _ _ . _ _. . . . _ . _ _ _ _ _ _
Attachment I to 2CAN099701 Page 27 of138 A summary of the principal results for the ASGT are g:ven in Table 32. The combined effects of the input modifications and the improved models utilized in the CENTS codes have shown that there are no adverse impacts due to the reduced RCS flow and other changes (ASGT remains non-limiting with respect to ROPM requirements). Thus the ASGT trip setpoint incorporated in the CPCs ensures that acceptable DNBR limits will not be exceeded during an , ASGT event. 4
REFERENCES:
4
- 1) "A Multi-Dimensional Space-Time Kinetics Code for PWR Transients", CENPD-188-A, July 1976.
- 2) " Technical Manual for the CENTS Code," CENPD 282-P-A, February 1991.
1
- 3) "CETOP D Code Structures and Modeling Methods for Arkansas Nuclear One - Unit 2, CEN-214(A)-P, July 1982.
- 4) 2CAN108705, T. G. Campbell of AP&L to J. Calvo of the NRC, " Technical
, Specification Change Request, Refueling Water Tank and Safety Injection Tank Boron Concentration lacrease," dated October 28,1987,
- 5) "CEA Ejection, C-E Method for Control Element Assembly Ejection Analysis",
, CENPD-190-A, July 1976.
- 6) CENPD-137-P, " Calculative Methods for the C-E Small Break LOCA Evaluation
, Model," August 1974, CENPD-137, Supplement 1-P, " Calculative Methods for the C-E Small Break LOCA Evaluation Model," January 197'i,
- 7) CENPD 139-P-A, "C-E Fuel Evaluation Model Topical Report," July 1974.
CEN-161(B)-P-A, " Improvements to Fuel Evaluation Model," August 1989. CEN-161(B)-P, Supplement 1-P-A, "lu_provements to Fuel Evaluation Model," January lo92.
- 8) CENPD-134P, "COMPERC-II, A Program for Emergency Refill-Reflood of the Core," August 1974.
CENPD-134P, Supplement -1, "COMPERC-II, A Program for Emergency Refill-Reflood of the Core (Modifications)," T:bruary 1975. CENPD-134, Supplement 2, "COMPERC-II, A Program for Emergency Refill-Reflood of the Core," June 1985.
- Attachment I to 2CAN099701 Page 28 of 138
- 9) CENPD-138P, " PARCH, A FORTRAN IV Digital Program to Evaluate Pool Boiling, Axial Rod and Coolant Heatup," August 1974.
CENPD 138P, Supplement 1, " PARCH, A FORTRAN-IV Digital Program to Evaluate Pool Boiling, Axial Rod and Coolant Heatup (Modifications)," February 1975. CENPD-138, Supplement 2-P, " PARCH, A FORTRAN-IV Digital Program to Evaluate Pool Boiling, Axial Rod and Coolant Heatup," January 1977.
- 10) CENPD 135P, "STRIKIN II, A Cylindrical Geometry Fuel Rod Heat Transfer Program," August 1974.
CENi D-135P, Supplement 2, "STRIKIN II, A Cylindrical Geometry Fuel Rod Heat Transfer Program (Modifications)," February 1975. CENPD-135, Supplement 4-P, "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program," August 1976. CENPD-135P, Supplement 5, "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program," April 1977. I1) Letter from K, Kniel (NRC) to A. E. Scherer (CE), " Evaluation of Topical Reports CENPD-133, Supplement 3-P and CENPD-137, Supplement IP," September 27, 1977.
- 12) CENPD-133P, Supplement 2. "CEFLAS'H-4AS, A Computer Program for the Reactor Blowdown Analysis of the Small Break Loss of Coolant Accident," August 1974.
CENPD-133, Supplement 3-P, "CEFLASH-4AS, A Computer Program for the Reactor Blowdown Analysis of the Small Break Loss of Coolant Accident," Januaiy 1977,
- 13) CENPD-132P, " Calculative Methods for the C-E Large Break LOCA Evaluation Model," August 1974.
CENPD-132P, Supplement 1, " Calculational Methods for the C-E Large Break LOCA Evaluation Model," February 1975. CENPD-132P, Supplement 2-P, " Calculational Methods for the C-E Large Break LOCA Evaluation Model," July 1975. CENPD-132, Supplement 3-P-A, "Culculative Mcthods for the C-E Large Break LOCA Evaluation Model for the Analysis of C-E and W Designed NSSS," June 1985. I l
Attachment I to 2CAN099701 Page 29 of138 Table i SYSTEM PARAMETERS AND INITIAL CONDITIONS FOR TIIE LARGE BREAK LOCA ECCS PERFORMANCE EVALUATION WITH INCREASED TUDE PLUGGING AND REDUCED RCS FLOW RATE Onnjily Valu_s Uniu Reactor power level (103% of rated power ) 2900 MWt Peak linear heat generation rate (PLHGR) of the hot rod 13.5 kW/R PLHGR of the average rod in assembly with hot rod 12.73 kW/R Gap conductance at the PLHGR") 2136 BTU /hr-ft2 ,.p Fuel centerline temperature at the PLHGR") 3204 'F Fuel average temperature at the PLHGR(" 1984 F Hot rod gas pressure") 2647 psia Moderator temperature coefficbt at initial density +0.5x10" Ap/ F RCS flow rate 107.8x10' lbm/hr Core flow rate 104.0x10' lbm/hr RCS pressure 2250 psia Cold leg temperature 556.7 'F Hot leg temperature 622.7 *F Safety injection tank pressure 550 psia Safety injection tank water volume (min / max) 1350/1600 ff Low pressure safety injection pump flow rate (min / max) 3222/5000 gpm High pressure safety injection pump flow rate (min / max) 678/825 gpm
")
These quantities correspond to the rod average burnup of the hot rod (40,000 MWD /MTU) that yields the highest peak cladding temperature. J
Attachment I to 2CAN099701 Page 30 of138 Table 2 TIMES OF INTEREST FOR TIIE LARGE BREAK LOCA ECCS PERFORMANCE EVALUATION (Seconds after Break) End of Start of SITS Hot Rod Evaluation SITS On Bvoass Reflood Empty Ruoture 0.6 DEG/PD 11.6 17.5 29.3 57.2 23.5 Increased tube plugging and reduced RCS flow rate Table 3 PEAK CLADDING TEMPERATURES AND OXIDATION PERCENTAGES FOR TIIE LARGE BREAK LOCA ECCS PERFORMANCE EVALUATION Maximum Core-Wide Peak Cladding Cladding Cladding Evaluation Temperature ('F) Oxidation (%) Oxidation (%) 0.6 DEG/PD 2158 7.2 <0.99 Increased tube plugging and reduced RCS flow rate Table 4 (not used)
Attachment I to 2CAN099701 Page 31 of138 Table 5 VARIABLES PLOTTED AS A FUNCTION OF TIME FOR TIIE LIMITING BREAK OF THE LARGE BREAK LOCA ECCS PERFORMANCE EVALUATION Yariable Eigurs Core Power Sa Pressure in Center Hot Assembly Node 5b Leak Flow Rate Sc Hot Assembly Fiow Rate (Below Hot Spot) 5d.1 Hot Assembly Flow Rate (Above Hot Spot) 5d.2 Hot Assembly Quality Se Containment Pressure 5f Mass Added to Core During Reflood Sg Peak Cladding Temperature and Temperature of the Rupture Node Sh Mid Annulus Flow Rate' Si Quality Above and Below the Core Sj Core Pressure Drop 5k Safety Injection Flow Rate into Intact Discharge Legs 51 Water Level in Downcomer During Reflood 5m Hot Spot Gap Conductance Sn Local Cladding Oxidation Percentage So Fuel Centerline, Fuel Average, Cladding and Coolant Temperature at the Hot Spot 5p Hot Spot Heat Transfer Coefficient Sq Hot Pin Pressure Sr
Attachment I to 2CAN099701 Page 32 of138 Table 6 HIGH PRESSURE SAFETY INJECTION PUMP MINIMUM DELIVERED FLOW TO RCS (ASSUMING ONE EMERGENCY GENERATOR FAILED) RCS Pressure. osia Flow Rate. gpm 1348 0.0 1321 82.6 1284 138.6 1248 186.5 1142 264A 1071 314.1 990 361.5 899 407.6 800 458.5 692 507.7 577 554.7 456 602.6 327 651.6 191 702.3 46 750.6 31 755.1 22 757.8 14.7 760.0 Notes:
- 1. The flow is assumed to be split equally to each of the four discharge legs.
- 2. The flow to the broken discharge leg is assumed to spill out the break.
j
Attachment I to 2CAN099701 Page 33 of138 Table 7 SYSTEM PARAMETERS AND INITIAL CONDITIONS FOR Tile SMALL BREAK LOCA ECCS PERFORMANCE EVALUATION Ouantity Value UDils Reactor power level (103% of rated power) 2900 MWt Peak linear heat generation rate (PLHGR) 13.5 kW/ft Axial shape index -0.3 asiu Gap conductance at PLHGR 1582 BTU /hr-ft' *F Fuel centerline temperature at PLHGR 3334 'F Fuel average temperature at PLHGR 2115 F Ilot rod gas pressure 1123 psia Moderator temperature coefficient at initial density 0.0x10" Ap/ F RCS flow rate 108.4x10' lbm/hr Core flow rate 104.6x10' lbm/hr RCS pressure 2250 psia Cold leg temperature 556.7 'F Hot leg temperature 622.7 'F Plugged tubes per steam generator 30 % MSSV first bank opening pressure 1103.5 psia Low pressurizer pressure reactor trip setpoint 1625* psia Low pressurizer pressure SIAS setpoint 1578' psia Safety injection tank pressure 550 psia
- Various values were assumed for these setpoints as noted in the text. These values are the bounding assumptions.
Attachment I ts 2CAN099701 Page 34 of 138 Table 8 BREAK SPECTRUM FOR THE SMALL BREAK LOCA ECCS PERFORMANCE EVALUATION Break Sig_snd Location Abbreviation Figure No. 2 0.06 ft' Break in Pump Discharge Leg 0.06 ft /PD 6 2 0.05 ft Break in Pump Dixharge Leg 0.05 ft'/PD 7 2 0.04 ft Break in Pump Discharge Leg 0.04 ff/PD 8 0.02 ft: Break in Pump Discharge Leg 0.02 ff/PD 9 Table 9 PEAK CLADDING TEMPERATURES AND OXIDATION PERCENTAGES FOR THE SMALL BREAK LOCA ECCS PERFORMANCE EVALUATION Peak Cladding Maximum Cladding Hot Rod Break Temperature (*FP) Oxidation (%f) _ Oxidation (%f) 1 0.06 ff/PD 2003 4.78 < 0.726 i 0.05 ft'/PD 2011 5.47 < 0.83 5 2 0.04 ft /PD 1870 3.37 < 0.567 0.02 fl'/PD 1671 1.73 < 0.318 l (a) Acceptance criterion is s 2200'F. (b) Acceptance criterion is s 17% 1 (c) Acceptance criterion is s 1.0% core-wide cladding oxidation. Rod-average oxidation of the hot rod is given as a conservative representation of the core-wide cladding oxidation.
Attachment I to 2CAN099701 Page 35 of138 Table 10 TIMES OF INTEREST FOR TIIE SMALL BREAK LOCA ECCS PERFORMANCE EVALUATION (Seconds after Break) HPSI Flow LPSI Flow SIT Flow Peak Cladding Delivered to Delivered to Delivered to Temperature Bgik RCS (sec) RCS (sec) RCS (sec) Occurs (sec) 0,06 ft /PD 2 169 (a) 1290") 1541 0.05 n'/PD 192 (a) 1592*) 1624 0.04 ft'/FD 179 (a) (c) 1943 0.02 n'/PD 389 (a) (c) 3411 (a) Calculation completed before LPSI flow delivery to RCS begins. (b) SIT injection calculated to begin but not credited in analysis. (c) Calculation completed before SIT injection begins. Table 11 VARIABLES PLOTTED AS A FUNCTION OF TIME FOR EACH BREAK OF THE SMALL BREAK LOCA ECCS PERFORMANCE EVALUATION Variable Figure 6 Through 9 Designation Normalized Total Core Power a Inner Vessel Pressure b Break Flow Rate c Inner VesselInlet Flow Rate d Inner Vessel Two-Phase Mixture Level e Heat Transfer Coeflicient at Hot Spot f Coolant Temperature at Hot Spot g Cladding Temperature at Hot Spot h
Attachment 1 to 2CAN099701 Page 36 of138 Table 12 A'3SUMPTIONS FOR TIIE UNCONTPOLLED CEA WITilDRAWAL FROM A SUBCRITICAL CONDITION Assumptions Assumptions Parameter lh1113 Case 1 Case 2 Initial Core Power (MWt) 896 x 10* 896 x 10* RCP Heat (MWt) 18 18 Core Inlet Temperature (*F) 552 552 l Reactor Coolant System Pressure (psia) 2000 2000 Steam Generator Pressure (psia) 1055 1055 Reactor Coolant System Flow (lbm/hr) 108.36 x 10' 108.36 x 10' TotalNuclear Heat Flux Factor - 6.8 9 Moderator Temperature Coeflicient (10" Ap/'F) A0.5 +0.5 Doppler Multiplier - 0.85 0.85 CEA Maximum Reactivity Addition (10" Ap/sec) 2.5 2.0 Rate Steam Bypass System - Manual Manual Feedwater Regulating System - Manual Manual
Attachment I to 2CAN099701 Page 37 of138 Table 13 SEQUENCE OF EVENTS FOR Tile UNCONTROLLED CEA WITIIDRAWAL FROM SUBCRITICAL CONDITIONS CASE 1 Time (gg) Eysnt Eetpoint or Value 0.0 Initiation ofwithdrawal - 256.6 High Logarithmic power level trip condition 4% of full power 257.0 Trip breakers open, and Rod withdrawal stops - 257.4 Maximum Power occurs 97.4% of full power 257.6 CEAs begin to drop - 257.7 Maximum heat flux, and 34.5% of full power Minimum DNBR 1.27 261.2 Maximum RCS Pressure 2119.6 psia 300 End of transient -
'(
Attachment I to 2CAN099701 Page 38 of138 Table 14 SEQUENCE OF EVENTS FOR THE UNCONTROLLED CEA WITIIDRAWAL FROM SUBCRITICAL CONDITIONS CASE 2 Time (Jy!) Rygnt Setooint or Value 0.0 Initiation of withdrawal - 320.2 High Logarithmic power level trip condition 4% of full power 320.6 Trip breakers open, and - Rod withdrawal stops 321.2 CEAs begin to drop, and Maximum Power occurs 77.7% of full power 321.3 Maximum heat flux, and 24.84% of full power l Minimum DNBR 1,42 324.7 Maximum RCS Pressure 2099.4 psia 350 End of transient - r
Attachment I to 2CAN099701 Page 39 of138 Table 15 ASSUMPTIONS FOR THE UNCONTROLLED CEA WITHDRAWAL FROM HOT ZERO POWER Parameter Wiu Assumptions initial Core Power (MWt) 0.002815 RCP Heat (MWt) 18 Core inlet Temperature (*F) 552 Reactor Coolant System Pressure (psia) 2000 Steam Generator Pressure (psia) 1055 Reactor Coolant System Flow (lbm/hr) 108.36 x 10' Total Nuclear Heat Flux Factor - 7.5 Moderator Temperature Coeflicient (104 Ap/ F) +0.5 Doppler Multiplier - 0.85 CEA Worth on Trip (% Ap) -2 CEA Maximum Reactivity Addition Rate (10" Ap/sec) 1,8 Steam Bypass System - Manual Feedwater Regulating System - Manual Automatic Withdrawal Prohibit - Inoperative
Attachment I to 2CAN099701 Page 40 of138 Table 16 SEQUENCE OF EVENTS FOR Tile UNCONTROLLED CEA WITIIDRAWAL FROM llOT ZERO POWER Time (acc) Event Setpoint or Value 0.0 Initiation of withdrawal - 22.2 VOPT trip conditions occurs 41% of full power 22.8 Trip breakers open, and - Rod withdrawal stops 23.1 Maximum power occurs 71.3% of full power 23.4 CEAs begin to drop -
'23.5 Maximum beat flux, and 38% offull power Minimum DNBR (see values below) 27.2 Maximum RCS Pressure 2174.2 psia Minimum DNBR Results for Various Power Shapes ASI Fr DNBR 0 3.95 1.31
-0.3 3.52 1.33
-0.6 3.26 1.34
-0.75 2.97 1.34
-0.9 2.90 1.33 1
0
Attachment I ts 2CAN099701 Page 41 of 138 Table 17 ASSUMPTIONS FOR Tile LOSS OF COOLANT FLOW ANALYSIS ASSUMING 30% STEAM GENERATOR TUBE PLUGGING Conservative Parameter bits AssumplipJ13 4 Initial Core power (MWt) 2900 Level Core Inlet Coolant ('F) 556.7 Temperature Core Mass Flow Rate (106lbm/hr) 104.57 RCS Pressure (psia) 2200 Radial Peaking Factor, Fr ----- 1,71 Axial Shape Index 0.3 Moderator Temperature (104 AprF) 0.0 Coefficient Scram Worth (% Ap) -5.0
Attachment I to 2CAN099701 Page 42 of138 Table 18 SEQUENCE OF EVENTS l FOR TflE 4-PUMP LOSS OF COOLANT FLOW ANALYSIS ASSUMING 30% STEAM GENERATOR TUBE PLUGGING Setpoint . Time (sec) Event _ or Value O.0 Loss ofpower to all four ------ reactor coolant pumps 0.8 CPC Low RCP Speed Trip (95%) 95% nominal speed 1.1 Trip breakers open - - - - - - 1,7 Shutdown CEAs begin to drop into core ------- 2.8 Minimum CE-1 DNBR 1.29
1 Attachment I ts 2CAN099701 Page 43 of138 Table 19 ASSUMPTIONS FOR Tile LOSS OF EXTERNAL LOAD / LOSS OF CONDENSER VACUUM Conservative f.EADit1H UDila Assumotions initial Core Power Level (MWt) 2900 RCP Ileat (MWt) 18 Core Inlet Cnolant Temperature (*F) 540 Reactor Coolant System Flow (10'lbm/hr) 135.3 . Reactor Coolant System Pressure (psia) 2000 Steam Generator Pressure (psia) 795 Moderator Temperature Coefficient (10" Ap/ F) 0 Doppler Multiplier - 0.85 CEA Worth on Trip (% Ap) -5.0 Steam Generator tube Plugging % 0 Tolerance on MSSV Setpoint % 3 Tolerance on PSV Setpoint % 3 Steam Bypass System - Inoperative Feedwater Regulating System - Manual 1 l
Attachment I to 2CAN099701 Page 44 of138 Table 20 SEQUENCE OF EVENTS FOR THE LOSS OF EXTERNAL LOAD / LOSS OF CONDENSER VACUUM Time Setooint (gs) Eyfat or Value 0.0 Loss of Condenser Vacuum, Turbine Stop Valves Close, - and Main Feedwater Valves Close 8.1 liigh Pressurizer Pressure Trip Condition Occurs 2422 psia 9.0 Trip Breakers Open - 9.6 CEAs Begin to Drop - 9.9 Pressurizer Safety Valves Open 2575 psia 10.5 Maximum RCS Pressure Occurs 2683 psia 11.4 Main Steam Safety Valves Open 1125.5 psia 13.6 Peak Secondary Pressure Occurs 1162 psia 13.9 Pressurizer Safety Valves Close 2472 psia
' Attachment I to l 2CAN09970)
Page 45 of138 Table 21 ASSUMPTIONS FOR Tile CYCLE 13 LOSS OF NORMAL FEEDWATER FLOW Conservative Parameter Md13 Assumptions Initial Core Power Level (MWt) 2900 RCP Heat (MWt) 18 Core Inlet Coolant Temperature ('F) 556.7 Reactor Coolant System Flow (10'lbm/hr) 108.4 Reactor Coolant System Pressure (psia) 2000 Steam Generator Pressure (psia) 922 Moderator Temperature Coefficient (104 Ap/or j -3.5 Doppler Multiplier - 1.4 CEA Worth On Trip (% Ap) -5.0 Steam Bypass System - Automatic Feedwater Regulating System - Malfunction , i
Attachment I to 2CAN099701 - Page 46 of138 Table 22 PRINCIPAL RESULTS FOR THE LOSS OF NORMAL FEEDWATER FLOW Time (aq) liysnt Setpoint or Value 0.0 Loss ofFeedwater Flow - 18.5 Steam Dump and Bypass Begins to Open Variable 47.2 Low Steam Generator Water Level Trip Condition 5% 48.5 Trip Breakers Open - 49.1 CEAs Begin to Drop - 51.9 Peak RCS Pressure Occurs 2229 psia 53.0 MSSVs Open 1059.9 psia 57.1 Peak Steam Generator Pressure Occurs 1084.5 psia 68.5- MSSVs Close 1006.9 psia 144.6 EFW Begins to Inject - 203 Minimum Liquid Inventory in Steam Generator A - 260.5 Minimum Liquid Inventory in Steam Generator B -
Attachment I to 2CAN099701 Page 47 of138 Table 23 ASSUMPTIONS FOR Tile STEAM LINE BREAK ANALYSIS FROM IlOT FULL POWER AND IlOT ZERO POWER Assumptions Parameter Units llot Full Power llot Zero Power InitialIncore Power Level MWt 2900 1 RCP Heat MWt 10 10 Initial Core Inlet Temperature *F 556.7 552 Initial Reactor Coolant Flow 10' lbm/hr 108.36 108.36 Initial RCS Pressure psia 2300 2300 CEA Worth at Trip % op -7.5144 -5.0 Initial Steam Generator Pressure psia 922 1058 Doppler Coefficient 1.22 1.22 Moderator Temperature Coeflicient 104 Ap/'F -3.4 -3.4 Feedwater Control System - Automatic Manual
Attachment 1 *o 2CAN099701 Page 48 of138 Table 24 SEQUENCE OF EVENTS FOR Tile STEAM LINE BREAK llOT FULL POWER WITil LOSS OF AC Time Setpoint Seconds Event or Value 0 Steam line break occurs, Loss of AC power occurs, RCPs begin ---- coasting down 0.31 CPC Low pump speed trip signal, fraction 0.965 1.31 Trip breakers open - 1.91 CEAs begin to drop ---- 2 MSIS setpoint has been reached, psia 620 3.3 MSIV begin to close ---- 3.4 MFIV begin to close ---- 6.3 Complete Closure of the MSIV ---- 7.2 SG delta pressure isolation reached, psid 220 12.5 Intact SG level reaches EFW actuation setpoint, % of narrow range 35.0 21 Pressurizer empties --- 24,9 SIAS setpoint is reached, psia 1400 37.6 EFW enters intact SG (steam pump) ---- 38.4 Complete closure of the MFIV --- 64.9 SIAS pumps reach full speed and begin injecting --- 100.9 EFW to intact SG is increased (electric pump) ---- 106.6 Boron reaches RCS -- 204 Maximum post-trip fission power, % of 2815 MWt 2.61 210 Minimum DNBR 1.81 302 Maximum post trip reactivity, %Ap -0.029 325 Ruptured steam generator empties, Ibm <2510 390 Cooldown ends, Minimum inlet temperature, 'F 387.1 500 End of calculation ---- 1800 Operator initiates cooldown (not simulated) ----
)
- Attachment 1 to 2CAN099701 Page 49 of138 Table 25 SEQUENCE OF EVENTS FOR THE STEAM LINE BREAK llOT FULL POWER WITil AC AVAILABLE Time Setpoint Seconds Event or Value 0 Steam line break occurs ---
2.07 SG low pressure trip condition and MSIS 620 setpoint has been reached, psia 3.34 MSIVs begin to close ---- 3.37 Trip breakers open --- 3.47 MFIV begin to close --- 3.97 CEAs begin to drop -- 6.34 Complete Closure of the MSIVs -- 7.1 SG delta pressure isolation reached, psid 220 13.7 Intact SG level reaches EFW actuation setpoint, % ornarrow range 35.0 17.2 Pressurizer empties -- 18.67 SIAS setpoint is reached, psia 1400 23.47 Complete closure of the MFIV ---- 38.8 EFW enters intact SG (steam pump) 58.7 SIAS pumps reach full speed and begin injecting --- 80 Maximum post-trip fission power, % of 2815 MWt 4.98 80 Minimum DNBR 2.46 83 Maximum post trip reactivity, %Ap -0.338 84 Cooldown ends, Minimum inlet temperature, *F 405.1 87.4 Baron reaches RCS 96.5 EFW to intact SG is increased (electric pump) -- 100.6 Ruptured steam generator empties, Ibm <2510 350 End ofcalculation --- 1800 Operator initiates cooldown (not simulated) ---- 1
Attachment I to 2CAN099701 Page 50 of138 Table 26-SEQUENCE OF EVENTS FOR TIIE STEAM LINE BREAK IIOT ZERO POWER WITil LOSS OF AC Time Setpoint Seconds Event or Value 0 Steam line break occurs --- Loss of AC power occurs RCPs begin coasting down 0.32 CPC Low flow trip signal, Fraction of pump speed 0.965 1.32 Trip becakers open ---- 1.92 CEAs begin to drop ---- 3.2 MSIS initiation setpoint has been reached, psia 620 4.47 MSIVs begin to close --- 7.47 Complete Closure of the MSIV ---- 8.8 SG delta pressure isolation reached, psid 220 27.3 Pressurizer empties ---- 28.4 SIAS setpoint is reached, psia 1400 54.5 Emergency Feed valves close --- 68.4 SIAS pumps reach full speed and begin injecting -- 106.7 Boron enters RCS - 159 Maximum post trip reactivity (first peak), %Ap .252 253 Maximum post trip reactivity (second peak), %Ap .126 334 Maximum post-trip fission power, % of 2815 MWt .41 343 Minimum DNBR 12.3 555 Ruptured steam generator empties, Ibm <2520 610 Cooldown ends, Minimum inlet temperature, *F 269.4 650 End of calculation -- 1800 Operator initiates cooldown (not simulated) - s
Attachment I to 2CAN099701 Page 51 of 138 Table 27 SEQUENCE OF EVENTS FOR TIIE STEAM LINE BREAK llOT ZERO POWER WITH AC AVAILABLE Time Setpoint Seconds Event or Value 0 Steam line break occurs -- 3.22 SG low pressure trip condition and 620 htSIS initiation setpoint has been reached, psia 4.49 hiSIVs begin to close --- 4.49 Trip breakers open --- 5.09 CEAs begin to drop -- 7.49 Complete Closure of the MSIV -- 8.8 SG Delta pressure isolation reached, psid 220 20.3 Pressurizer empties -- 20.94 SIAS setpoint is reached, psia 1400 39.52 Emergency Feed Valves close - 61.0 SIAS pumps reach full speed and begin injecting --- 87.3 Boron enters RCS --- 122 Maximum post trip reactivity, %Ap .227 145 Maximum post-trip fission power, % of 2815 MWt 1.275 145 Minimum DNBR 11.2 146 Ruptured steam generator empties, Ibm <2500 146 Cooldown ends, Minimum inlet temperature, *F 348.6 250 End of calculation -- 1800 Operator initiates cooldown (not simulated) -
Attachment I to 2CAN099701 l Page 52 of138 l Table 28 ASSUMPTIONS FOR THE CEA EJECTION ACCIDENT ANALYSIS EarJmdn 11 0111 HZP HFP Initial Core Power (MWt) 29 2900 Core Inlet Temperature ('F) 552 556.7 Reactor Coolant System Pressure (psia) 2000 2000 Reactor Coolant System Flow (10'lbm/hr) 108.36 108.36 Total Delayed Neutron Fraction (p) - 0.0043414 0.0043414 Moderator Temperature Coefficient (104 Ap/ F) +0.5 0.0 CEA Ejection Time (sec) 0.05 0.05 Doppler Multiplier - 0.85 0.85 CEA Worth at Trip % Ap -2 -5 4 W 1 i
Attachment I to 2CAN099701 Page 53 of138 Table 29 AXIAL POWER DISTRIBUTION USED FOR TIIE CEA EJECTION ACCIDENT ANALYSES Fractional Distance from the Bottom of the Reactor Core Power Fraction. Fz 0.025 0.5 0.075 0.8 0.125 1.0 0.175 1.1 0.225 1.1 0.275 1.1 0.325 1.1 0.375 1.1 0.425 1.1 0.475 1.1 0.525 1.1 0.575 1.1 0.625 1.1 0.675 1.1 0.725 1.1 0.775 1.1 0.825 1.1 0.875 1.0 0.925 0.8 0.975 0.5 Table 30 RESULTS FOR THE CEA EJECTION ACCIDENT ANALYSIS Initial Power. Elected CEA Worth
% of 2815 MWt (102 60) Acceptable Eiected 3D Peak. Fe 100 0.30 4.98 0.20 5.94 0.17 6.27 0 0.85 14.7 0.70 15.6
1 Attachment I to , 2CAN099701 I Page 54 of138 l Table 31 ASSUMPTIONS FOR TIIE LOSS OF LOAD TO ONE STEAM GENERATOR Conservative Parameter Rojils Assumptions Initial Core Power Level (MWt) 2534 Core Inlet Coolant Temperature ('F) 556.7 Reactor Coolant System Flow (10' lb./hr) 108.36 Reactor Coolant System Pressure (psia) 2250 Moderator Temperature Coeflicient (10" Ap/ F) -3.5 Doppler Multiplier - 0.85 CEA Worth on Trip (% Ap) -5.0 Steam Generator tube Plugging % 30 Tolerance on MSSV lift Setpoint % 3 Axial Shape Index asiu -0.3 Table 32 SEQUENCE OF EVENTS FOR TIIE LOSS OF LOAD TO ONE STEAM GENERATOR Time (sg) Event Setooint or Value 0.0 Spurious closure of a single MSIV - 5.72 ASGT trip setpoint reached 11 F 6.0 Main steam safety valves open on affected steam generator 1125.5 psia 6.31 Trip breakers open - 6.91 CEAs begin to drop into core - 7.90 Time of minimum DNBR 2 1.25 9.8 Maximum steam generator pressure 1160 psia
Attachment I to 2CAN099701 Page 55 of13B Figure 1 Moderator Teamperature Coemelent 5 00E 05
- %, ,. i y: 4 o ,. 7 , r., ,p n #ro, ,g 1, f g p l,; .,t . l ,, s ,
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. . . _ _ . _ _ _ . . _ _ _ _ _ - _ _ _ _ _ . . _ _ _ . _ _ _ _ _ _ . . . __ _ _ ~ ___ _ --. _ _ . _ __ _ _.._ _ _. -
Attachment I to 2CAN099701 Page $6 of'138 Figure 2 , Doppler Reactivity versus Fuel Temperature 4.00 4.08 4.01 g 4.06 E00 4.05 -- 1
/
4.04 4.03 - N 4.0s 4.01 0 . l 0 500 1000 1900 2000 2500 3000 3000 4000 4600 8000 FuelTempersture,(F)
Attachment I to 2CAN099701 Page 57 of138 Figure 3 Reactivity Insation versus CEA Insertion 4.N 4.M - 4.M - N w 4.03 4.02 4.01 0.00 . , . . . 0 06 1 16 2 26 3 36 4 Time (sec) ' I l 6 j l l
Attachment I to 2CAN099701 Page 58 of138 Figure 4 CEA Insertion vs. Time 100 liO - to - 70 - g 00 - 50 - x. 20 - 10 0 , 0 06 1 16 2 26 3 36 nme (e) e
Attachment I to 2CAN099701 Page 59 of138 Figure 5a 0.6 Double Ended Guluottae Break is Pump Discharge les Con Power vs. Time 1.2 . 1.0 . a: y . 3 0.8 . O - O. -
+. -
E 8 , 0.6 . o c* : .
- u. .
af : w - 3 0.4 o a. 0.2 . g g g g g { ( 1 9 I 0 I I ' O.0 0 1 2 3 4 5 TIME, SEC
Attachment I to 2CAN099701 Page 60 of138 Figure $b 0.6 Double Ended Guillottae Break la Pump Discharge Leg Pressure la Center Hot Asseeably Node vs. Time 2400 . 2000 . 1600 '. D5
- c. :
ui -
- 1200 g
u) - w - E *
- a. :
~
800 . N - 2 0 O 5 10 15 20 25 TIME, SEC l
Attachment I to 2CAN099701 Page 61 of138 Figure Sc 0.6 Double Ended Guluotine Break la Pump Discharge 143 Leak vs. Thee 120000 .
- Pump Side Nactor Vessel SWe 100000 .
l l . 80000 . w . .
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. g
=
4 g '. ,, 20000 . e g M
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g , ,,,,,,,,, 0 5 10 15 20 25 TIME, SEC
Attachment I to 2CAN099701 Page 62 of138 Figure 5d.1 0.6 Double Ended Guillotine Break in Pump Discharge Leg Hot asseeably Flow Rate (Below Hot Spot) vs. Time 30 _ 20 : 10 0 - W (/) - m . j
- W \
0 m o 10 m 20
~ ' ' ' ' '''' '''' '''' ''''
30 O 5 10 15 20 25 TIME, SEC
Attachment 1 to 2CAN099701 Page 63 of138 Figure 5d.2 I 0.6 Double Ended Guillotine Break in Pump Discharge Leg Hot assembly Flow Rate (Above Hot Spot) vs. Time 30 20. l 10 0 4
/
( I x 3 3 oJ [ 10 3 20
-30 O 5 10 15 20 25 TIME, SEC
Attachment I to 2CAN099701 Page 64 of138 Figure 5e 0.6 Double Ended Guthetime Break la Pump Discharge 14 Hot assembly Quality vs. Time
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/ VNi
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0.0 O 5 10 15 20 25 TIME, SEC
_ _ - - . . - . . _ . - . _- . _ . . . _ _ _ _ . = _ - _ _ _ _ _ Attachment I to 2CAN099701 Page 65 of138 Vigure 5f 0.6 Double Ended Guillotlee Break la Pump Discharge Leg Containment Pressure vs. Time 60 . 50 . .
- A 40 .i -
D5 c. ul e 8 m N x w Z
- n. :
20 . . . 10 . 0 O 100 200 300 400 500 TIME, SEC l
, . - . - _ - - , ~ . - - _ _ _ _ . _ . . -
Attachment I to 2CAN099701 Page 66 of138 1 i Figure 5g 0.6 Double Ended Gulliotine Break la Pump Discharge Leg Mass Added to Core During Reflood vs. Time 120000 .
, 100000 80000 _
2 - co
'. : /
g 60000 _ 1 : 40000
- / Reflood Rate,
; . Time, sec. In/sec.
- a 0.0 6.6 2.2444
~
6.6 70.10 1.2879 0 O 100 200 300 400 500 TIME (DURING REFLOOD), SEC
Attachment I to 2CAN099701 Page 67 of138 Figure $h 0.6 Double Ended GuWotine Break in Pump Discharge Leg Peak Cladding Temperature vs. Time 2200 . . 1
- c \
1900 .
- u. 1600 . y ., g 0 -
l . w . a . m , c l */ 1300 .. S oc CC W Q. . 2 - W - H - 1000
.L
.}
- . Pl!AK CLADDING TEMPERATURE NODE
--------Cl. ADDING RUPTURE NODE 700 .
400 O 100 200 300 400 500 TIME, SEC
Attachment I to 2CAN099701 Page 65 of138 Figure 51 0.6 Double Ended Guillotine Break in Pump Discharge W Mid Annulus Flow Rate vs. Time 5000 . 1
! f 0' m l
v . ( 5000 . 1 0 . w . .
~
i d 10000 Q : a: - 3: : oJ
- u. .
15000 - i .
-20000 25000 O 5 10 15 20 25 TIME, SEC
Attachment I to 2CAN099701 Page 69 of138 Figure SJ 0.6 Double Ended Guillotine Break la Fump Discharge Leg Quality Above and Below the Cort vs. Time 1.0 . ,.
,, . , . -f
- , , i ,
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l. n Quality Atove the Core l
--* Quality Balow the Core I
0.0 O 5 10 15 20 , 25 TIME, SEC
Attachment 1 to 2CAN099701 Page 70 of138 Figure 5k 0.6 Double Ended Guillotine Break la Pump Discharge Leg i Core Pressure Drop vs. Time 30 .
- 20. .
>{
10 I h
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4 2 10 Q e m M 20 _ 30 O 5 10 15 20 25 TIME, SEC
Attachnent I to 2CAN099701 Page 71 of138 Figure 51 0.6 Double Euded Guluotlee Break la Pump Discharge Leg Safety Injection Flow Rate lato Istact Discharge legs vs. Time
~ '
10000 . 8000 . g .
\
- SAFETYINJE TION
- i TANK!i o
w h 6000 i e
; N ur :
4 m 2 : 3 4000 o : . d : r : 2000 .
- SAFETY INJECTION
- PUMPS 0
O 20 40 60 80 100
, TIME, SEC
Attachment I to 2CAN099701 Page 72 of138 Figure 5m 0.6 Double Ended Guitiotine Break la Pump Discharge Leg Water Imel in Downcomer During Renood vs. Time 30 . 25 :
- 20 .
Y V s w 15 w J 10 , . 4 5 . le is g 9 g g g g l l g l t ( l $ f I l $ I I O ! I ' O O 100 200 300 400 500 TIME (DURING REFLOOD), SEC
. , -_ .re_-. .,. . , . _ , . - , . -,. , - - - - - - ,
Attachment I to 2CAN099701 Page 73 of138 Figure 5m 0.6 Double Ended Guillotine Break la Pump Discharge Leg Hot Spot Gap Conductance vs. Time i 1800 1500 u.
@ 1200 Q
d 900 d 5 0
% 600 0 .
300
./
0 O 100 200 300 400 500 TIME, SEC
Attachment I to 2CAN099701 Page 74 of138 Figure So 0.6 Double Ended Guillotine Break in Pump Discharge 14g Local Claddlag Oxidation Percentage vs. Time 18 . 15 . ge 12 . i : - 9 : 4 O R g O - H : 5 o
/ .
9 . i1 e f f f I l t ( ) f f f f 1 9 f 1 I f I I t I % 0 f f I l I I I I f f I 1 0 100 200 300 400 500 TIME, SEC
Attachment I to 2CAN099701 Page 75 of138 ure 5p 0.6 Double Ended Guth 'ine Break in Pump Discharge Leg Fuel Centertine, Fuel Average, Cladding and Coolant Temperature at the Hot Spot vs. Time 2700 - E E k C ,, . . . ~ ~ ' ~~ ~.. s , 2250- t e
,- , .s
,'s
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450 . 2 N e e IG e I l 1 1 0 f f f 1 l E t t I F 1 1 1 1 f f I t t 0 I 1 I 1 l I I I I 1 I I I I I I O I I I O 100 200 300 400 500 TIME, SEC
Attachment I to 2CAN099701 Page 76 of138 Figure Sq 0.6 Double Ended Guillotine Break in Pump Discharge Leg Hot Spot Heat Transfer Coemclent vs. Time 180 . 3 4 150
- v. 120 D .
$ 90 R m Y $ 60 i 30 , I 0 O 100 200 300 400 500 TIME, SEC
Attachment I ts 2CAN099701 Page 77 of!?8 Figure Sr 0.6 Double Ended Guluottae Break la Pump Discharge Leg Hot Pin Pressure vs. Time 3000 . N l 2500 . 1 : . t . 4 4 e 2000 [ i3 - Q. d ) 1500 m - LLI C - Q- :
~
1000 . m O 4
~
500 . O m 4 e e 4 0 O 20 40 60 80 100 . TIME, SEC , I
Attachment I to 2CAN099701 Page 78 of138 Figure 6a 0.06 FT' Break la Pump Discharge 14g Normalised Core Power vs. Time 1.50 .......... ......... ......... . . . . . . . . .
- - 4
- 4 l
- 4 E 4 4
- 4
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- 4 1.25 - 4 D g W e 4 E 4 E 4 E 4 4 4 1.00 . .
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n,,.............................................- 0 .100 200 300 400 500' TIME, SEC . .
__._m.-_ ._ _ _ ___ __ . _ _ Attachment I to 2CAN099701 Page 79 of138 Figure 6b 0.06 FT' Break in Pump Discharge Leg Inner Vessel Pressure vs. Time 2400 .......... ......... ......... ......... ......... . 1600 ,, . g . .
- a. ,
E a 55 w 1200 lbq 800 . . w .- 400 . O O 500 1000 1500 2000 2500 TIME, SEC
Attachment I t3 2CAN099701 Page 80 of138 Figure 6c 0.06 FT' Break la Pump Discharge Leg Bresk Flow Rate vs. Time . 1200 . . ....... ......... ......... ......... ......... n I e g4 a
> e
>8 G
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. . g 1000 . .
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. l g
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Attachment I ts 2CAN099701 Page 81 of138 Figure 6d 0.06 FT3 Break la Pump Discharge Leg Inner Vessel Inlet Flow Rate vs. 'thne 50000 (........
......... .. ..r... ......... .........
40000. . . 30000 .
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20000 l
%g :
8 i . e . 10000 . l 0 . . 0 500 1000 1500 2000 2500 TIME, SEC i l l P
- - . . - , - -, , - . . . . . , . . - , ~ -
,--,...~n.,.-. - , , . . . . ~ . . . , - , - - . . - . . - . .
Attachment I to 2CAN099701 fage 82 of138 Figure 6e 0.06 FT' Break la Pump Dlscharge lag Inner Vessel Two. Phase Mixture Level vs. Time 48 .......... ......... ......... . . . . . ... . . . . . . . . . . ., 40 . . 32 . .
~
W 24
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8 . . 1 1 i f a i f R 1 b G G G t B I A t t I t I d t l e t i t A A i l l i t I E 1 8 1 0 E 0 8 0 500 1000 1500 2000 2500 TIME, SEC
Attachment I to 2CAN099701 Page 83 of138 Figure 6f 0.06 FT' Break in Pump Discharge Leg Heat Transfer Coeificient at Hot Spot vs. Time 10 ' : . . . . . . . . . ......t . . ......... ......... . . . . . . . . . a 4 4 5 10 : . t
- , : I N
- 6 4
10 : e : t :
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- 4 I t t B $ 4 I i t t 9 9 9 I i i t t I f f f t t t t t t t t t t t a 1 9 e t i e 9 e g 0 500 1000 1500 2000 2500 TIME, SEC
Attachment I ta 2CAN099701 Page 84 of138 Figure 63 0.06 FT' Break la Pump Discharge Leg Coolant Temperature at Hot Spot vs. Time 2400 ......... ......... ......... . . . . . . . . . . . . . . . . .
. E
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. 8 4 8 2000, .
. 8
. a l
t 1600 . .
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. 8 9 f G 9 R R t 9 9 9 9 9 9 9 9 9 9 9 9 I t 1 i t t 9 0 t I O 9 I I O O I O I I I O O I I E O 500 1000 1500 2000 2500 TIME, SEC
Attachment I to 2CAN099701 Page 85 of138 Figure 6h 0.06 FT Break in Pump Discharge Leg Cladding Temperature at Hot Spot vs. Time 2400 .. . . . . . . . . ......... ......... ......... . . . . . . . . .
. 6 .
- 2000 . g- .
l
. e 1600 . .
% 9 .
tL . . o . . 10 e '. 1200 g g W : :
. N wp.
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/
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e ' . I 1 1 0 t I t 1 1 9 t t t t 9 I D R I t t t t t I t t 1 1 i i t t t t 9 1 1 1 1 0 t t t E O 500 1000 1500 2000 2500 TIME, SEC _a
Attachment I to 2CAN099701 Page 86 of138 Figure 7a 0.05 FT' Break in Pump Discharge Leg Normalized Core Power vs. Time 1.50 ........., ......... ......... .....,,,, ,,,,,,,,, e 4 8 4 e 4 4 n ' 1.25. , G 4 W cc - : w - N 1* SA ' 2 - s . m : . 4 e W q : ! F 0.75 O . H : - O - w - - N "
~
2 0.50 . [ 9
- m e
- G e
W 8 0.25 . , e a E 0.00 ', O 100 200 300 ' 400 500 TIME, SEC
Attachment I to 2CAN099701 Page 87 of138 Figure 7b 0.05 FT' Break in Pump Discharge Leg Inner Vessel Pressure vs. Time 2400 . 4 , a G W 4 2000 - m G 9 S N e ! k 1600 . 5 . .
- a. ; -
1200 % g : m - m - g- - 0- . S 800 . , ; g n W 4 e S
. / :
1 n a
~
4 e e g g g g y y g ii f f i B f 9 I I I I I I I ' I I I I O O 600 1200 1800 2400 3000 TIME, SEC e ' - 3
Attachment I ts 2CAN099701 Page 88 of138 Figure 7c 2 0,05 FT Break in Pump Discharge Leg Break Mow Rate vs. Time 1200 .......... . ........ ......... . . . . . . . . . . . . . . . . . ., O n p S E E d 8 4 8 e G 1000 . G D 1 18 4
> ' N le 4 S W 800 o
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w N 1 & a I f 1 R f f 9 iB $ f I f 9 R R I t 9 9 0 t G B i 9 E I O I & I I I E % 8 I I I I I O ,600 1200 1800 2400 3000 TIME, SEC 1
Attachment I to 2CAN099701 Page 89 of138 4 Figure 7d O.05 FI' Break in Pump Discharge Leg i Inner VesselInlet Flow Rate vs. Time I I 4 5 4 5 6 4 4 4 4 3 5 4 4 4 5 4 4 4 4 5 4 4 4 4 5 5 1 4 4 4 4 4 4 4 4 4 4 I I 4 4 4 I 5 , . 8 e f a a 4 m 4 40000. . . E A .i . m W G 30000 . . o . g a 8 e 4 3 4 2 a
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- a e =
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-10000 0 600 1200 1800 2400 3000 I e j TIME, SEC i
a 4
. . - -. .. . .= - . _ _ _ . - _ . _ _ _ . .- . - -_ - . .
i Attachment I ts 2CAN099701 l Page 90 of138 Figure 7e 0.05 FT' Break in Pump Discharge Leg j i Inner Vessel Two. Phase Mixture Level vs. Time l , 48 .......... , , , , . . . . . , , , , , . . . , , , , , . . . . , . . . . . , , , , 1 = . f a . 40 . .
=
- 32 . .
w . J . . W 24
- g "..TC.P.O.F.C.o.m.e. . . .
g . O ." w . -
/ '
- 18 . .
...SO.T.T.O.M.O.F.C.O.RE. ............ ............ ............ ........... .
8 . . 1
,e t f 9 1 1 % f 1 f E I i I I E I f I f I I 1 I I E I I I I I I I I I I " ' '
' 0 O 600 1200 1800 2<00 3000 TIME, SEC 1
Attachment I ts 2CAN099701 Page 91 of138 Figure 7f 0.05 FT' Break in Pump Discharge Leg Heat Transfer Coemcient at Hot Spot vs. Time a 10 :......... .........: s
- 10. : :
q 4 10 : g : : N . .
$ 3 d* 10 : S :
m - - G . .
$ 10 2
,? -
Q 10 : :
. 0 ,,,,,,,,, ,,,,,,,,, ,,,,,,,,, ........, ,,,.,,,,,,
0 600 1200 1800 2400 !000 TIME, SEC l l l
4 s Attachment I to 2CAN099701 l Page 92 of138 Figure 73 0.05 FT* Break la Pump Discharge Leg Coolant Temperature at Hot Spot vs. Time 4 2400 .......... ........ . ...... . . . ... . '. 9 . . t - 4
, 2%0 . -
4 1600 .
- u. .
O . m . W . o . H 1200 1 1 x - w : -
- c. .
2 . w - - 4 i 800 . t -
\ :
N ( - . 400 . ; 4 g 4 - g g g g g f 3 e t t I t E I 9 9 8 0 0 E E E I I I I I I I I I I ' ' ' O O 600 1200 1800 2400 3000 l TIME, SEC
Attachment I to 2CAN099701 Page 93 of138 1 Figure 7h 0.05 FT' Break in Pump Discharge Leg Cladding Temperature at Hot Spot vs. Time
- 2400 .. . . . . . . . . ......... . . . . . . . . . . . ....... ... .....
5 8 h I y g . < m M 2000 . , 6 4 m
- e S 4 E
IS BB 4 W 4 g l 1600 . 3 1 . y . W 4 ul : : 4 g . 3 4 H 1200 g uJ :
- a. : .
4 2 . L , s : 800 { i e
, G . . -
/
a a e e m m 6 M W 1 . 1 . i k 5 W O I I Y $ I I I I g g if 9 f I 9 R 9 9 9 9 f f I i 1 1 9 9 9 f 9 E $ E $ 0 I I I I I O O O 0 .600 1200 1800 2400 3000 1 . TIME, SEC
Attachment 1 to 2CAN099701 Page 94 of138 Figure 8:a 0.04 FT' Break in Pur,p Discharge Leg % Nonnalized Core Power vs. Time 1.50 .......... ....... ~~......... ......... .........
. G
. 8
. 4 I. e
. 9 1.25 . .
l . t . .
. G
. 8 4 .-
E
- N :
W . . 15 8 O : :
~
H 0.75 . . R : : o .
. 8
. 4
- p. 8 3 0.50 . .
6 z g).
. U
- l. 5 0.25 . .
19 E e *
. U IIB E
~
0.00 O 100 200 300 400 500 TIME, SEC
/ ____m
Attachment I to 2CAN099701 , Page 95 of138 Figure 8b 0.04 Fr* Break in Fump Discharge Leg Inner Vessel Pressure vs. Time 2400 _i. ...... . ........ . ........ . . . . . . . . . . . . . . . . . . G G G S IS E e 2000 - m 9 e n n W 4 4 1600 . 4 5 u} o, - 3,y [ . E *
\v A -
3 1200 _ y , en - u). uj I.
-~
g - g - 4 N . a 4 a S W IG 15 3 M le W IS I I I I I I E I I I I I E I O I I 9 0 $ $ 9 j k l 9 l $ $ j $ 9 9 R 9 $ $ % $ $ f 9 9 9 0 600 1200 1800 2400 3000 TIME, SEC _u
Attachment I to 2CAN099701 Page 96 of138 Figure Sc 0.04 FT' Break in Pump Discharge Leg Break How Rate vs. Time 1200 ..>> .>>>. >> .... ......... >>>> ... ......... - 1000. . 800 600 . 3 : : O g
.~
g . 400 . 1 ,
- L -
- \
Q_ N_ . 0 O 600 1200 1800 2400 3000 TIME, SEC
Attachment I to 2CAN099701 Page 97 of138 Figure 8d 0.04 FT' Break in Pump Discharge Leg Inner VesselInlet Flow Rate vs. Time 50000 7m ,... . .i....... ..... ... ......... .... .... . 40000 . . 30000 0 . : 20000 . . 5 . .
- u. : : -
10000 . . 0 . .
~
-10000 -
O 600 1200 1800 2400 3000 TIME, SEC m
. . . . - - . _a
_. , . _ _ _ . . _ . __ . . _ . . _ . _ _ . _ _ _ _ ~ . _ . . . _ . _ . ._ . _ _ ~ . __ _ _ _ . . Attachment I to
- 2CAN099701 Page 98 of138 Figure 8e l 0.04 FT8 Break la Pump Discharge Leg Inner Vessel Two. Phase Mixture Level vs. Time 4
48 .......... ......... ......... ......... ......... l
. . I 40 ' ).'
s . 32 r . k . s . w . 4 . W 24 l
...........s. ........... ............ ........
- i y -
i 16 . i
- so.n. .e.w.w.
.. .c.o.ns.
,. 8 . - 0 O 600 1200 1800 2400 3000 TIME, SEC i l e-
Attachment I ts 2CAN099701
- Page 99 of138 s
4
- Figure 8f O.04 FT' Break in Pump Discharge Leg l Heat Transfer Coemclent at Hot Spot vs. Time
- a
- i. 10 :........
4 s 10 :. . 4 1 10 . . + 4 . . 8.- .
, 3 at 10 -
E i :
- E
- :
- m .
2 10 . . d 10 1 M 10 O 600 1200 1800 2400 3000 TIME, SEC J
Attachment I to 2CAN099701 Page 100 of138 Figure Sg 0.04 FT' Break la Pump Discharge Leg l Coolant Temperature at Hot Spot vs. Time 1 4 4 5 4 5 5 5 4 1 3 5 E I I B A I 5 4 4 5 5 4 I I 4 4 3 I i 4 5 3 I I B B 4 I I 4 5 g 4
. a
. g
. a
. 4 d . a e a j . a 2000 . .
. e
. e 3
. e
. e i
1600 . . g i h 1200 . . w : :
- n. . .
4 2 . . . p : 4 MO . . a N e i 1 Y , . d e
- , =
) I B 1 e i t i f 6 I t I t i B 1 9 9 9 I f E I I I I ' ' I ' I 0 ' I I I ' ' ' 8 8 ' ' ' ' O O 600 1200 1800 2400 3000 TIME, SEC i a
Attachment 1 to 2CAN099701 Page 101 of138 Figure 8h 3 0.04 FT Break in Pump Discharge Leg Cladding Temperature at Hot Spot vs. Time 2400 . 2000 . - j : 1600 '. -
- u. : :
o . ur : ( : x .
\;
1200 h . E
- a. : -
llE - g! : i 000 '. - kW I i L - 4= ; l t t t t t t t t t t i f R t l E I I 9 9 i R t 3 0 I I I . E I I I I *
- 0 600 1200 1800 2400 3000 TIME, SEC
Attachment I to 2CAN099701 Page 102 of138 Figure 9a . 0.02 FT' Break in Pump Discharge Leg Normalized Core Power vs. Time 1.50 . 1.25 . . l . j . l s 1.00 l Q . m . - q : : H 0.75 . . f2 : : o . 1G E IS 8 2 0.50 . . I. 8
. 4 8
IS Y 0.25 . . g . . 19 O g o_no 0 100 200 300 400 500 TIME, SEC
l Attachment I to 2CAN099701 , Page 103 of138 Figure 9b I 0.02 Fr* Break in Pump Discharge Leg inner Vessel Pressure vs. Time 2400 .... - .. . .... .. .. - - 2000 . [
.d
. l 1600 .
j . a g ui g . 1 p., : 1200 g .
~ u .
m i T : E i Nf 4 800 . . . 400 . . 0 '''f''''''''''''''''''''''''''''''' O 1200 2400 3600 4800 6000 - TIME, SEC
Attachment I to 2CAN099701 , Page 104 of138 , 1
, Figure 9e 0,02 FT' Break in Pump Discharge Leg Break Flow Rate vs. Time 1200 .
a W l g e I 1000 '. . 4 4 ) W m a E a 800 _ ; o o tu . 3 : . m e 3 : : . oJ : g - . 400 - g 4
- e e
e 4 , e g bA 4 4 e .l
# 4 G A e
g g g g g e g t t 1 E a O t 9 9 9 9 9 8 0 Y I I I I I O 6000 O 1200 2400 3600 4800 TIME, SEC 3 1 f
Attachment I to 2CAN099701 Page 105 of138 Figure 9d 0.02 FT' Break la Pump Discharge Leg Inner VesselInlet Flow Rate vs. Time 50000 .......... e G G G 4
- W *
. Y 4 4 8 40000 . .
4 e Q G W E e G 30000 , . W 4 e
- 4 W
G m . y S o : it : : 10003 . 5 . G G
$ g 4
9 3 0 . 4 4 4 e 4 2,........ ,,,,,,,,, ,,,,,,,,, ,,,,,,,,, ......... 0 1200 2400 3600 4800 6000 TIME, SEC i
Attachment I to 2CAN099701 Page 106 of138 Figure 9e 0.0; FT* Break in Pump Discharge Leg Inner Vessel Two-Phase Mixture Level vs. Time 48 . .
. . - - ...... . . >i - .........
40- .~ . 32 k W 24 Q ,_,
. . . . . . . . . 3. . ........... ........................[ .
f' . 16 .
. o.n. .e.w.o.r.e.c.eu.
8 . . 0 O 1200 2400 3600 4800 6000 TIME, SEC
Attachment 113 2CAN099701 Page 107 of138 Figure 9f 0.02 Fr2 Break la Pump Discharge Leg Heat Transfer Coemcient at Hot Spot vs. Time s 10 -......... ......... . ........ .
. e
. 4 G
5 10 : : r . . 4 10 : :
. 4
. 3 g 2 10 -
E : m .
. E q .
10 : :
. 9
. 4 1 1 10 : :
R 4
. 9 I O I I $ I $ $ I I E $ $ 9 9 l 9 t I $ I I I O O $ $ $ . O O O I . O O O I ! I Y $ A $
0 1200 2400 3600 4800 6000 TIME, SEC
4
- Attachment I to 2CAN099701
, Page 108 of138 Figure 93 0.02 FT' Break in Pump Dischage Leg Coolant Temperature at Hot Spot vs. Time 1 2400 .-. n a T e g e 1 i . i 1 .
~
l 1600 .
- ur
- :
m .
< 1200 ~
g . W : :
- a. .
- 2 .
W - 4 ,,
~
e a 4 4 400 . a a e I t t i i 9 I 9 t t 0 9 8 ' ' ' ' ' I ' ' ' ' ' I ' ' t a e e t t t t 9 t t 9 I t I t t 9
- 0 l 0 1200 2400 3600 4800 6000 TIME, SEC i
Attachment I to 2CAN099701 Page 109 of138 i Figure 9h 0.02 FT* Break la Pump Discharge Leg e Cladding Temperature at Hot Spot vs. Time 2400 .-. 2000 . g . i 1600 [ - e 0;
< 1200 .
4 a : 4 lE : d f : if : : 800 t - ( 400
- o 4 0 1200 2400 3600 4800 6000 i
TIME, SEC 4 if
4 Attachment I to 2CAN099701 Page 110 of138 Figure 10 Peak Claddin2 Temperature vs. Break Size for SBLOCAs 2200 2100 0 " 2000 . g 1900 C , E h1800 m n N 1700
/
1600 1500 1400 0.00 0.02 0.04 0.06 0.08 0.10 BREAK AREA, FT2
Attachment I to 2CAN099701 Page 111 of138 Figure 11 RCP FLOW COAST DOWN WITil 30% S/G TUBE PLUGGING 1.10 1 00 0 90 - 0 80 - 0 70 - g Oeo 8 om - 0 40 - 0 30 - 0 20 - 0.10 - og . . . . . . . . . 00 10 20 30 40 60 60 70 80 90 10 0 TIME IN SECONDS
..s
Attachment 1 to 2CAN099701 Page 112 of138 Figure 11 DNBR vs. Time 3 l l 2.75 - 2.5 2.25 2-- 1.75 - - 1.5 - 1.25 - 1 , , , 0 2 4 6 8 10 Time, Seconds
- i. . . . . . . .
Attachment I to 2CAN099701 Page 113 of138 Figure 13 Cooldowi Data for the Cyde 13 MSLB Analysis 0 00 0 os - HFP 0 07 g 00s . > 0 06 - 0 04 - 4 003-0 02 i HZP 0 01 0 , , ; O 100 200 300 400 600 000 ModeratorTemperature(F) i
Attachment I to 2CAN099701 Page 114 of138 Figure 14 Doppler Reactivity versus Fuel Temperature for the Cycle 13 MSLB 0 03 0025-0 02 -
} 0 015 -
0 01 ( a 0 006 - 0-4 01 4015 0 200 400 000 800 1000 1200 1400 1600 Fuel Temperature (F)
, _ _ . . . . . 1
Attachment 1 t3 2CAN099701 Page 115 of138 Figure 15 SLB HFP Loss of AC 1 HPSI Core Power vs. Time 1.20 ..........s ....... 6 .......s... . .' a... ..... O 4 4 4 4 e 6 1.00 . 4 4 4 e G W M 0.80 . D . M : 3 . :
" 0.60 ,g ,
Q . E I
- N u .
- n. 0.40 -
I e 4 4 M e e 0.20 . W e 0.00 O 100 200 300 400 500 Time (Seconds)
Attachment I to 2CAN099701 Page 116 of138 i Figure 16 4 i SLB HFP I.4ss of AC 1 HPSI Heat 11ux vs. Time i 1 1 1.20 . .........s . .
......s.........s.........s..... .. .
1 . . e e - S 1.00 7 . d . .f . M 0.80 '- . 1 va .
- t g '
N .
= .
O 0.60 7 tem LL . w . 5 : E . x 5 0.40 ! . i . le W G 19 IS B 0.20 : . S IG 15 PG IS j { l ) y t t l 0 I $ $ $ I I $ I E l $ I I O I I I 0.00 0 100 200 300 400 500 Time (Seconds)
Attachment I to 2CAN099701 Page 117 of138 Figure 17 SLB IIFP Iass of AC 1 HPSI Pressuriser Pressure vs. Time 2400 .. ....... . .'..... ......... ... ..,.. .... .... ( . 2000 : , 1600 -
.5 .
g, . 1200 - m - Q, - 800 - MO - i
~''''''''''''' ' ''''''''
O O 100 200 300 400 500 Time (Seconds)
Attachment I to 2CAN099701 Page118of138 Figure 18 SLB HFP I4ss of AC 1 HPSI s Steam Generator Pressure vs. Time SG 1
.............SG2 1200 .........., ........s.........,.........s......... .
e 8 l$ pe
- W le 4
1000 7 - e O g
- e #
%g~~
- l .
= $ 6 *
-l . :
800 :: -
~
kg g = .g ., , .
>, =
w -
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600 t , i ,
,4 b %
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g'*e....e*b
@0 : .
m
- le
- a 4
;g 4 IB
- 4 200 7 W
e ' b$ le
- 18 4,,,,,,,,,!,,,,,,,,, , , , , , , , , ,t,, i i 0 100 200 300 400 500 Time (Seconds)
Attachment I to 2CAN099701 Page 119 cf138 Figure 19 SLB HFP IAss of AC 1 HPSI RCS Temperatures vs. Time Thot
. . . . . . . . . . . . . TM av Tin 600 . ........s.........s.........s........ s.....'. .
4
=
J i 1 550 . t. 500 - c . [ : g . 450 - r - - MO - 350 .
. . . . . . .i.........i.........t.........i.........
300 1 l 0 100 200 300 400 500 Time (Seconds)
Attachment I ts 2CAN099701 Page 120 of138 Figure 20 SLB liFP Loss of AC 1 IIPSI Total Reactiviiles vs. Time Moderator
. . . . . . . . . . . . . Do@ler Boron
. Scram.
- Hermho Credit 1
0.09 ... i ... , .i. i 4. 4
- e .
l
%g 0.06 G
- e
- e
- 6
- e
- 0.03 '-
.l, :
o
, ......... .............-.....-------"--~"""""-"-": .
4
~
0 .00 l '--- - J
~ % w: ~.
9 e4
-0.03 -
-0.06 -
pb *
-0.09 O 100 200 300 400 500 Time (Seconds)
Attachment I to 2CAN099701 Page 121 of138 Figure 21 SLB HFP AC Available 1 HPSI Core Power vs. Time
/
1.20 ..........g.........s.........g.........\......... . I 1.00 I
* (
i . . ! n . . ! 5 0.80 : 5 - tn . . e . . IS . : 3 : : 0.60 : u : :
.s .
- n. 0.40 : .
. F 0.20 :
- t :
~
0.00 O 70 140 210 280 350 Time (Seconds) _w
Attachment I to 2CAN099701 Page 122 of138 Figure 22 SLB IIFF AC Available 1 HPSI Heat flux vs. Time 1.20 .
.i . . . i.. ... ..i......... .>>>..... .
1.00 : e PG H 15 e y . g 0.80 : 7 m : . g : . 3 : ; m el 0.60 - m 2
\
E :
~
1 I 0.40 r 2 C.20 7 W m W e M 0.00 O 70 140 210 280 350 Time (Seconds)
i 't Attachment 1 to 2CAN099701 Page 123 of138 I Figure 23 l SLB HFP AC Available 1 HPSI Pressurizer Pressure vs. Time 2400 ..........s.........u.........s.........s.......... _ 2000 : . 3, . 1600 7 1 1200 'r i . W h
- b & "
\ .
a . 4 W 800 7 . 4 N q m 9 O 8 m W 4 W e W
) f I I I . . I - .. '
I I 1 l [ G d jl 1 f I E 1 O 70 140 210 280 350 Time (Seconds)
Attachment I to 2CAN099701 Page 124 of138 Figure 24 SLB HFP AC Available 1 HPSI Steam Generator Pressure vs. Time SG 1
.............SG2 1200 ..........s...... ..s.........n.........u. .
d W G W W G 1000 .
=.
4 t
=.
800 -! '. s -
=
F g a .
* 's
\g 5 "
g) 4 j 4 - 600 ' t I, 4 w = b . g
,t *."
. g
=
. t 9
g - 400 _
--------..............,,,,,,,,j -
p m M M W 200 r 4 W e A W ps O O 70 140 210 280 350 Time (Seconds)
Attachment I to 2CAN099701 Page 125 of138 Figure 25 SLB HFP AC Available 1 HPSI RCS Temperatures vs. Time Thot
. . . . . . . . .. . . . . Tmod av Tin 600 .v ... . . . .
s... .....s.........s.. >
....s ........
i
-{ .
~
550 ., -
.. t. .
1 l . 4 500 - 7 C -
- : i, -
e . . 450 -
- 7
, .' s .
e - H : 's . . MO - 350 - 7 300 O 70 140 210 280 350 Time (Seconds) v
Attachment I ts 2CAN099701 Page 126 of138 Figure 25 SLB HFP AC Available 1 HPSI Total Reactivities vs. Time Moderator
............. % Ier ,
Boron
. Scram Hermite Credit 0.09 ..... .... .........i .. ..... ......... .........
- a l 0.06 - -
N %
- 9
- W
- 4
- a 0.03 -
J -
- e l
e
~
d 0.00 - i- - - --
- - - - -~------------------. .
- g N
Q* - .
- e
-0.03 :
m G
- e
- n 4
- 4
-0.06 -
- W
- I -
ie ,
- M 0.09 O 70 140 210 280 350 Time (Seconds)
Attachment 1 tD 2CAN099701 Page 127 of138 Figure 27 SLB HZP Loss of AC 1 HPSI Core Power vs. Time (Semi Log scale) 0 10 . .........,.........s.........,.... ....,....... . . 4 8
- 18 .
9 10 r I e
- l ~
l l 2 : : m . . w . . N . 1
- a E
C 10 r 1 g g 1,1,_.,, .i b , 10 I a. E 4 is 6 10 r 7 W W E G 4
. I I I O l I l ( l 9 1 1 1 I I E f I I I I I I 1 0 0 I I I - I O I I I I I I E I I O 130 260 390 520 650 Time (Seconds)
Attachment I to 2CAN099701 Page 128 of138 Figure 28 SLB HZP IAss of AC 1 HPSI Heat Flux vs. Time (Semi 143 scale) o 10 : .,.......s.........s.........s.........n........u 1 e - 4 5 4 U e 9 1 10 r 7 e . e 5 e e W 5 2 l g 10 l m
!E -
3 - b
- u. e .
5 c
! 10 r -
I : l : e e 5 - 10 r e 4 e e 5 $ $ I & I f l 1 l 1 l l [ ] I I 1 I l l $ $ I $ $ 0 $ $ I $ E $ - I O 130 260 390 520 650 Time (Seconds)
Attachment I to 2CAN099701 Page 129 of138 Figure 29 SLB HZP Loss of AC 1 HPSI Pressurizer Pressure vs. Time 2400 . . . . . . . . . s.........s.........s.........s........ O 2000 : M $
= a 15 4 l$ W 4 a e
14 5 1600 7 In a
>G W m 4 4 W I 1200 3 : :
g . l g . . 1 1 ~ G G le 800 7 4 se W G G W W IO 4 e H le a
@0 -
W G G G e 4 kW W G W g *
. I I ! O I E I 1 1 l I 1 1 I I l I l I I l l l l l $ $ - ! I I S I I ! I ! A 0 130 260 390 520 650 Time (Seconds)
. . 9
i Attachment I ta 2CAN099701 Page 130 of138 Figure 30 ) SLB 12P Loss of AC 1 HPSI a _ Steam Generator Pressure vs. Time SG 1
.............SG2 2 1200 . .... . . . . . . .. . . . . . . . .........i.. . . . . . .
+
1
~
O e 4 e d - 1000 : . T 4 g W m W e k 800 I 4 1 k , [ : 600 + 7 4 J l b" , e d W MO e G 6 O M - W 200 7 7 O M e IS N a I I I i 1 - I f I f e i t t I 5 I I 8 I 3 iI t i t t t 1 1 0 130 260 390 520 650 Time (Seconds)
Attachment 119 2CAN099701 Page 131 of138 1 Figure 31 i SLB HZP Loss of AC 1 HPSI l l l RCS Temperatures vs. Time < Thot I
- . . . . . . . . . . . . . zg y Tin j 600 . ........ .........i......... ......... ......... .
540 i . MO r c . m : ', : 420 . . .
. s, .
e -
', s F :
- 360 7 \ .
. .~. . .
300 7
' .. ~...~. .
I I I I E E i l . . . .I jI E I . ! . I I $ $ ! 0 130 260 390 520 650 Time (Seconds)
Attachment I to 2CAN099731 Page 132 of138 Figure 32 SLB HIP
- ass of AC 1 HPSI Total Reactivities vs. Time Moderator
. . . . . . . - . - - . . Doppler
' Boron M M M M M .
Scram Hermite credit 0.09 . . . . . . . . . . s.........n........ 6 ....' ' 6.....'... . 4 e G
= 0 4
! 0.06 . e 4 W G W 4 4
~~
0.03 7 .
.-u, G9l 5 ; ...... .........- -
d---- _ _.____._~ 0.00 ~
, ~ ~ ,
-use g "
-uua e.us *"" e-. ,,,:
- t g .
0.03 W M M M M M M M M MMM M M M M M M M M W
-0.06 7 .
W M S 4 W 0.09 O 130 260 390 520 650
. Time (Seconds)
J
Attachment I to 2CAN099701 Page 133 of138 Figure 33 SLB llIP AC Available 1 IIPSI Core Power vs. Time (Semi Log scale) 0 10 . . . . . . . . .
..........i.........i......... .........
1
- 9 10 3-1
- 2 E 10 r 1-3 :
, w .
., N . t l O
- 4 i
i 10 r 9 w -J u. w
\
b . M
$ 10 ?
5 10 r i NB
. i . I I ' ' '
I t l I I O j l i t I j G i l E I $ $ 0 $ $ I I I I I $ O 50 100 150 200 250 Time (Seconds)
- . . - + ce,, . y , --- - - -
_w ,. ,f--y,
4 Attachment I t) 2CAN099701 Page 134 of138 i I Figure 34 l SLB HZP AC Available 1 HFSI Heat Flux vs. Time (Semi Log scale) 0 10 ........i........................i.......j J , PG 4 1 10 r 7
, 4 a
4 . m b . 2
- 10 E 7
> e N '
O 3 . 10
- 1 w .
LL. .
\
me 4 10
- 7 3 :
I : . 8 13 IS 10' 1 O e f 4 -
=
$ $ .I O . . 0 I I 0 0 I l l f $ l t l l j il l 1 1 1 I 10 O 50 100 150 200 250 2
Time (Seconds)
l i Attachment I to j 2CAN099701 Page 135 of138 Figure 35 SLB HZP AC Available 1 HPSI Pressuriser Pressure vs. Time
; 2400 . . .. ....... . ......... ......... .. .... .
{ . BB' $i d 2000 7 1600 7 j . . l 1 . I . 1200 7 I h Q - 1 : l. 800 . e .
.I g .
MO r T pp B. I I $ 0 I $ $ l $ l l l { $ $ I . I I $ $ $ I l I I $ l $ N I ! I Y E O 50 100 150 200 250 Time (Seconds)
,n- , , , , - e , - - , - - - , -. , ._ - -, - - --.
Attachment I to 2CAN099701 Page 136 of133 Figure 36 SLB HIP AC Avallsble 1 HPSI Steam Generator Pressure vs. Time SG1
.............SG2 1200 . .
i ''''i''''i' i'''' 1000 7 . M M0 7 P. - I a
- i!
- 7 i
600 :'.! f a
-t .
l m (1. - m
~
@0 -
9 M e 4 O M 200 7 - e e
. I 0
0 50 100 150 200 250 Time (Seconds)
Attachment I ts 2CAN099701 Page 137 of138 Figure 37 SLB IIZP AC Available 1 HPSI RCS Temperatures vs. Time Thot
. . . . . . . . . . . . . TM av Tin 600 . .
........s..... . . .
s..... ..s ..... s......... . O O e 8 g IS e O
- 0 a 540 _ .
m 19 4 m 9 4 9' e 4 & W e 40 :
~
c . O G G e . . 420 g . . W A G G g3 ' h N _ 360 [- . 4 9 IG G W G W 4 15 4 9 M R$ 4 300 7 IG W W 19 4 e G m u 4 I e G I I I I I I I I I O I I E I 1 0 $ l 1 I i f I I ! O I I E I I I I $ I I O 50 100 150 200 250 Time (Seconds)
. . . . . . _ _ _ _ _ . _ J
Attachment I to 2CAN099701 Page 138 of138 Figure 38 SLB HFP AC Available 1 HPSI Total Reactivities vs. Time Moderator Doppler soron _ _ . Scram Hermite CredM t ...... .......... .,,......... ...... .., . . . . . . . . _ \, . L ( - 0.06 - K : 0.03 -
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