L-2011-311, ANP-3019NP, Revision 0, St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Tube Rupture, Attachment 2
| ML11231A947 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 08/31/2011 |
| From: | AREVA, AREVA NP |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| L-2011-311 ANP-3019(NP), Rev 0 | |
| Download: ML11231A947 (54) | |
Text
St. Lucie Unit 1 L-2011-311 Docket No. 5-335 Attachment 2 ATTACHMENT 2 Response to NRC Reactor Systems Branch Request for Additional Information Regarding Extended Power Uprate License Amendment Request NON-PROPRIETARY VERSION (Cover page plus 49 pages)
L-2011-311 Attachment 2 ANP-3019(NP)
Revision 0 St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Tube Rupture August 2011 A
AREVA NP Inc. AREVA
L-2011-311 Attachment 2 AREVA NP Inc.
ANP-3019(NP)
Revision 0 St. Lucie Unit I EPU - Information to Support NRC Review of Steam Generator Tube Rupture Copyright © 2011 AREVA NP Inc.
All Rights Reserved
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Ruoture Paae 1 Nature of Changes Item Page Description and Justification
- 1. All Initial Release
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 2 Table of Contents Nature of Changes ........................................................................................................................ 1 Table of Contents .......................................................................................................................... 2 List of Tables ................................................................................................................................. 2 List of Figures ............................................................................................................................... 3 Nom enclature ................................................................................................................................ 4 1.0 Introduction ....................................................................................................................... 6 2.0 SGTR Overfill .................................................................................................................... 7 2.1 Sum m ary of Analysis ......................................................................................... 7 2.2 Responses to Inform ation Request ................................................................ 11 3.0 SGTR Steam Release .................................................................................................. 29 3.1 Sum m ary of Analysis ...................................................................................... 29 3.2 Responses to Inform ation Request ................................................................ 30 4.0 References ...................................................................................................................... 47 List of Tables Table 1 Sequence of Events for SGTR Overfill Case ..................................................... 9 Table 2 Input Parameter Biasing for the SGTR Overfill Analysis ................................ 17 Table 3 Maximum HPSI Flow Rates for the SGTR Overfill Analysis ............................ 21 Table 4 Auxiliary Feedwater Flow Rates ...................................................................... 21 Table 5 SGTR O perator Actions .................................................................................. 23 Table 6 Supporting Evaluations Case Definitions ...................................................... 34 Table 7 Summary of Results for Supporting Evaluations of Input Param eter Biasing .......................................................................................... 35 Table 8 Input Parameter Biasing for the SGTR Steam Release Thermal-Hydraulic Analysis .......................................................................................... 36 Table 9 Maximum HPSI Flow Rates for Steam Release Thermal-Hydraulic Analysis ............................................................................................................... 40 Table 10 Assessment of EOP Actions for SGTR Steam Releases ................................ 42
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Paqe 3 List of Figures Figure 1 SGTR Overfill - Ruptured SG Liquid Volume ................................................ 10 Figure 2 Non-LOCA Reactor Vessel Nodalization ......................................................... 13 Figure 3 Non-LOCA Reactor Coolant System Nodalization ......................................... 14 Figure 4 Non-LOCA Secondary System Nodalization .................................................. 15
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 4 Nomenclature Acronym Definition ADV Atmospheric Dump Valve AFAS Auxiliary Feedwater Actuation Setpoint AFW Auxiliary Feedwater ANS American Nuclear Society EOP Emergency Operating Procedure EPU Extended Power Uprate ESF Engineered Safety Feature ESFAS Engineered Safety Feature Actuation System FF Feed Flow FPL Florida Power & Light FSAR Final Safety Analysis Report HPSI High Pressure Safety Injection LAR License Amendment Request LOCA Loss of Coolant Accident LOOP Loss of Offsite Power LR Licensing Report MD AFW Motor-Driven Auxiliary Feedwater MFW Main Feedwater MSIV Main Steam Isolation Valve MSSV Main Steam Safety Valve MTO Margin to Overfill NR Narrow Range NRC Nuclear Regulatory Commission PORV Power Operated Relief Valve PT Pressure Temperature RCGVS Reactor Coolant Gas Vent System RCP Reactor Coolant Pump RCS Reactor Coolant System RPS Reactor Protection System RTP Rated Thermal Power
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 5 Nomenclature (Continued)
Acronym Definition SBCS Steam Dump and Bypass Control System SDC Shutdown Cooling SE Safety Evaluation SF Steam Flow SG Steam Generator SGTP Steam Generator Tube Plugging SGTR Steam Generator Tube Rupture SI Safety Injection SIAS Safety Injection Actuation Signal TD AFW Turbine-Driven Auxiliary Feedwater TM/LP Thermal Margin/Low Pressure
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 6 1.0 Introduction The Nuclear Regulatory Commission (NRC) staff requested additional information to support the review of the steam generator tube rupture (SGTR) section of the St. Lucie Unit 1 extended power uprate (EPU) license amendment request (LAR). The questions were received as "draft" questions specifically related to steam generator (SG) overfill. However, the NRC subsequently requested similar information for the SGTR steam release analysis. The questions for SG overfill were modified to adapt them accordingly to steam releases.
The information contained herein is specific to the analyses supporting the St. Lucie Unit 1 EPU LAR submittal.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 7 2.0 SGTR Overfill 2.1 Summary of Analysis A conservative SGTR overfill analysis was performed to address the NRC questions concerning SG overfill.
A single case was analyzed. Parameter biasing, assumptions, and an assumed single failure were designed to produce a conservatively high break flow rate, maximize Auxiliary Feedwater (AFW) flow to the ruptured SG, and minimize the Margin to Overfill (MTO) at the time operators terminate AFW flow to the ruptured SG. Assumptions regarding operator actions and mitigating systems and functions, along with a limiting single failure, produce the most challenging scenario regarding SG overfill. The case analyzed is described below.
The SGTR event is initiated by a double-ended break of a single steam generator tube (shortest tube) on the top side of the tubesheet. The break is assumed to be at the cold-side of the U-tube at the top surface of the tube sheet above the SG outlet plenum. A cold-side break is analyzed because it produces a higher total break flow rate than a hot-side break, which is in the conservative direction for the overfill analysis.
Loss of Offsite Power (LOOP) is assumed at reactor trip in this analysis. The assumption of LOOP at reactor trip is conservative relative to offsite power being available, as safety grade overfill protection for Main Feedwater (MFW) would be available and would prevent SG overfill in a no-LOOP case.
There are no operator actions or mitigating systems or functions simulated directly in this analysis to cooldown and depressurize the Reactor Coolant System (RCS) to equilibrate RCS and ruptured SG pressures and terminate break flow. Therefore, the calculated integrated break flow will bound an actual integrated break flow (out to the time that operators terminate AFW flow to the ruptured SG) that would occur when operators take mitigating steps in accordance with the Emergency Operating Procedures (EOPs). The only operator action directly accounted for in the analysis is termination of Turbine-Driven (TD) AFW flow to the ruptured SG following Auxiliary Feedwater Actuation Setpoint (AFAS) reset when the ruptured SG Narrow Range (NR) level reaches 35%, plus a 15 minute delay time for operator action.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 8 Along with no operator actions or mitigating systems or functions being directly simulated to terminate break flow, the most challenging single failure to overfill of the ruptured SG is a failed open TD AFW flow control valve on AFAS reset. This produces the largest AFW flow to the ruptured SG, which reduces the ruptured SG pressure and tends to increase the break flow rate. Without this single failure, the AFAS reset logic will prevent AFW flow to the ruptured SG when the nominal SG level is above 29% NR (analysis value 35% NR).
The maximum ruptured SG liquid volume at the time operators terminate TD AFW flow to the ruptured SG was calculated to be 5879.1 ft 3 . The total secondary side volume of the SG is 7733.7 ft3 . Thus, the MTO is 1854.6 ft3 at the time of -28 minutes when operators terminate AFW flow to the ruptured SG. This MTO of greater than 1850 ft3, calculated with conservative break flow, would be sufficient to prevent SG overfill considering the fact that operators will be taking action to reduce the SG level and reduce the pressure difference between the RCS and the ruptured SG, which would result in reduced break flow. The conservative break flow at the time of termination of AFW flow was -42 Ibm/sec. Even assuming continuation of this break flow up to 45 minutes into the transient with no other operator action, the MTO will remain greater than 1000 ft 3.
The sequence of events for the SGTR overfill analysis is shown in Table 1.
Figure 1 shows the liquid volume in the ruptured SG versus time relative to the total geometric volume of the SG. The MTO is 1854.6 ft3 at the time the operators terminate AFW flow to the ruptured SG (28.7 minutes).
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube RuDture Paae 9 Table 1 Sequence of Events for SGTR Overfill Case Time (s) Event 0.0 Event initiation - Double-ended rupture of SG tube occurs above tubesheet on cold plenum side 0.0 Charging flow begins 229.1 Thermal Margin/Low Pressure (TM/LP) Reactor Protection System (RPS) setpoint reached (including delay time) 229.1 Turbine trips on reactor trip - offsite power is assumed lost 229.1 Reactor Coolant Pumps (RCPs) coastdown due to LOOP 229.1 MFW lost due to LOOP 232 Main Steam Safety Valves (MSSVs) open on ruptured SG (SG-1) 232 MSSVs open on intact SG (SG-2) 241.1 AFAS signal on SG-1 and SG-2 421.1 AFW flow begins to SG-1 and SG-2 772.0 Safety Injection Actuation Signal (SIAS) 794 Pressurizer empties 1098 High Pressure Safety Injection (HPSI) flow begins 821.4 SG-1 NR level reaches 35% following reactor trip 1721.4 TD AFW to SG-1 is terminated
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Ruoture Paae 10 SG-1 Liquid Volume 8500 8000 7500 7000 6500 6000 5500 0~
5000 4500 4000 3500 3000 2500 2000 0 500 1000 1500 Time (s)
Figure 1 SGTR Overfill - Ruptured SG Liquid Volume
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 11 2.2 Responses to Information Request SRXB-1: Discuss the methodologies and computer codes used for the SGTR overfill analysis.
If the methods were previously approved by U. S. NRC, list the NRC safety evaluations (SEs) approving the methods and address the compliance with the restrictions listed in the SEs. If the methods were not reviewed and approved by NRC, address acceptability of the methods.
Discuss the mitigation strategies used in the SGTR analysis to the conditions that the break flow is terminated or the shutdown cooling system can be used for decay heat removal.
Response: The purpose of the SGTR overfill analysis was to conservatively calculate the MTO for the ruptured SG at the time operators terminate AFW flow to the ruptured SG. A detailed analysis was performed with the approved methodology using the S-RELAP5 code (Reference 1). The S-RELAP5 code was used to model the key primary and secondary system components, RPS and engineered safety features (ESF) actuation trips and core kinetics. The nodalization, chosen parameters, conservative input and sensitivity studies were reviewed for applicability to this event in compliance with the SE for the Reference 1 topical report.
The nodalization used for the SGTR calculations supporting the EPU was specific to St.
Lucie Unit 1 and was consistent with the Reference 1 methodology. Nodalization diagrams used for the non-Loss of Coolant Accident (LOCA) event analyses for the EPU are given in Figure 2 to Figure 4. The normal non-LOCA model lumps all of the tubes in a SG together. The SGTR model has one SG tube modeled explicitly, with the remainder lumped. The rupture model is a double-ended guillotine break in this tube just above the tube sheet. Critical flow is modeled using the Moody model, which provides a conservative model for choked flow.
The parameters and equipment states were chosen to provide a conservative estimate of the MTO for the ruptured SG at the time operators terminate AFW flow to the ruptured SG. The biasing and assumptions for key input parameters are discussed in response to SRXB-2.
The S-RELAP5 code assessments documented in Reference 1 validated the ability of the code to predict the response of the primary and secondary systems during transient events. The assessments included the non-LOCA LOFT test suite. No additional code assessments were performed.
The analysis did not model specific operator actions to cooldown and depressurize the RCS, equilibrate RCS and ruptured SG pressures, and terminate break flow. Thus, the calculation predicted a conservative break flow rate out to the time that operators terminate AFW flow to the
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 12 ruptured SG, based on a much larger pressure difference between the RCS and ruptured SG than would occur when operators initiate EOP actions to cooldown and depressurize the RCS, equilibrate RCS and ruptured SG pressures, and terminate the break flow. Thus, a conservative MTO at the time operators terminate AFW flow to the ruptured SG was calculated.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 13
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I Figure 2 Non-LOCA Reactor Vessel Nodalization
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(
'K Figure 3 Non-LOCA Reactor Coolant System Nodalization
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 15
(
J Figure 4 Non-LOCA Secondary System Nodalization
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 16 SRXB-2: List the nominal values with measurement uncertainties and the corresponding values used in the SGTR overfill analysis for the following plant parameters:
- Initial power level
- Initial SG water inventory
- Initial pressurizer water volume
- Safety injection actuation pressure setpoint
- Safety injection flow versus RCS pressure
- Safety injection system pump delay time
- SG relief valve pressure setpoint
- AFAS and delay time
- AFW temperature and flow rate per SG
- MSSV lift setpoints and steam flow rate of each MSSV
- Time of loss of offsite power
- Atmospheric dump valve (ADV) steam flow rate from intact and affected SGs
- Decay heat model and initial value in percentage of the rated power level This discussion should include rationale to show that the value of each of the above parameters used in the SGTR overfill analysis is conservative, resulting in a minimum margin to SG overfill.
In addition, provide a basis for the target cooldown temperature used in the analysis.
Response: Table 1 provides the requested information for the SGTR overfill analysis. The key parameters were biased to maximize the break flow, maximize AFW flow to the ruptured SG, and produce a conservative MTO at the time operators terminate AFW flow to the ruptured SG.
Since specific operator actions to cooldown and depressurize the RCS were not used in the analysis, there was no specific target cooldown temperature in the analysis. The cooldown of the RCS that did occur was a result of AFW flow to both SGs with its associated cooldown and depressurization of the SGs. The RCS hot leg temperature was reduced to 505°F at the end of the calculation due to cooling from AFW.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Paqe 17 Table 2 Input Parameter Biasing for the SGTR Overfill Analysis C
'44w
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 18 Table 2 Input Parameter Biasing for the SGTR Overfill Analysis (Continued)
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube RuDture Paqe 19 Table 2 Input Parameter Biasing for the SGTR Overfill Analysis (Continued)
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 20 Table 2 Input Parameter Biasing for the SGTR Overfill Analysis (Continued)
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 21 Table 3 Maximum HPSI Flow Rates for the SGTR Overfill Analysis RCS Loop 1A Loop lB Loop 2A Loop 2B Pressure Flow Rate Flow Rate Flow Rate Flow Rate (psia) (gpm) Wgm (gpm) gm) 15 296 395 395 395 324 259 346 346 346 633 216 288 288 288 839 182 243 243 243 1045 140 187 187 187 1148 114 153 153 153 1158 112 149 149 149 1162 110 147 147 147 1251 80 107 107 107 1303 55 74 74 74 Table 4 Auxiliary Feedwater Flow Rates SG Pressure MD AFW Flow Rate TD AFW Flow Rate MD AFW Flow Rate (psia) to Ruptured SG to Ruptured SG to Intact SG (gpm) (gpm) (gpm) 115 725.55 738.15 691 515 581.70 599.55 554 815 457.80 474.60 436 915 411.60 425.25 392 1000 368.55 379.05 351 (Note: MD and TD AFW flow rates to the ruptured SG include a 5% bias high)
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 22 SRXB-3: Identify operator actions and associated action times credited in the analysis. Where an operator action is credited, confirm that such action is consistent with station procedure and action times are conservative, resulting in a minimum SG MTO.
Response: Specific operator actions to cooldown and depressurize the RCS, equilibrate RCS and ruptured SG pressures, and terminate break flow were not modeled in the analysis. Thus, the calculation predicted a conservative break flow rate relative to the break flow rate that would occur when operators initiate EOP actions to equilibrate RCS and ruptured SG pressures to terminate the break flow to the ruptured SG. This produces a conservative MTO at the time operators terminate AFW flow to the ruptured SG. The only operator action directly credited in the analysis was to terminate TD AFW flow to the ruptured SG after the NR level reached 35%,
plus a 15 minute delay time for operator action. Per EOPs, operators will continue to equilibrate RCS and ruptured SG pressures using ADVs, PORVs, and pressurizer auxiliary spray to terminate the break flow and isolate the ruptured SG by 45 minutes. Table 5 contains an assessment of the. operator actions relative to SGTR MTO.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 23 Table 5 SGTR Operator Actions Key EOP Operator Actions Impact Comment If turbine not tripped, then operator trips it locally and closes MSIV isolation increases pressure in SG, so None.
both main steam isolation valves (MSIVs). level goes down.
Operator verifies at least one SG level is being restored to SG level restored by AFW. None.
between 60% to 70% by feedwater or AFW.
Operator maintains RCS Tave between 525 and 535°F and For LOOP, ADVs can be locally opened.
S/G pressure between 835 and 915 psig by using the steam SG pressure may go down and level go up Single failure of valve failing open is not dump and bypass control system (SBCS) or opening the based on AFW flow. credible. For no LOOP, the SBCS is used.
ADVs. With failure of SBCS, ADVs will be used.
Operator/Shift Technical Advisor verifies every 15 minutes:
unisolated SG level is being restored to 60% to 70% NR. Level is controlled to be within this band. This Maintains heat sink. action applies to both SGs before isolating the For high SG level, the level is reduced by controlling/stopping affected SG. The actions for high level will AFW, lowering RCS pressure, SG blowdown, steaming to prevent the SG level from rising further.
condenser or steaming with ADVs.
SG level goes down as the steam flow (SF) is Operator cools down RCS to less than 510°F using SBCS, all increased to cooldown [SF > feed flow (FF)].
ADVs, AFW motor pumps, or AFW steam driven pump taking None.
steam from least affected SG. SG pressure goes down, and level goes up again as SG is cooled with AFW.
Operator maintains RCS below 930 psia and within 50 psia of most affected SG. Operator depressurizes RCS using Primary to secondary leakage is minimized. This action is performed continuously before pressurizer sprays, power operated relief valves (PORVs) or isolating the affected SG.
reactor coolant gas vent system (RCGVS).
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 24 Table 5 SGTR Operator Actions (Continued)
Key EOP Operator Actions Impact Comment (EOP-01 and EOP-04) ImpactComment Operator isolates most affected SG and maintains pressure less than 915 psig using MSIV bypass if vacuum (minimize Release from affected SG stops. This action is supposed to occur before or at release), control room operation of ADVs, or local operation of (radiological impact) the analysis assumed time limit (45 minutes).
ADV if no instrument air.
As RCS Temperature is lowered, cooling the Operator cools down to shutdown cooling (SDC) using SBCS Unisolated SG pressure goes down. isolated SG, the isolated SG pressure will or ADVs. lower.
Operator maintains isolated SG level less than 90% NR by lowering RCS pressure, SG blowdown, steaming to Stops SG level increase. None.
condenser or steaming with ADVs.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 25 SRXB-4: Under the assumed LOOP conditions, address the functionality of each ADV.
Discuss what, if any, mitigating function of the ADV provides, and its capability to perform that function under assumed LOOP conditions. If the valve's actuation must be manual, provide information to show that the operator is capable of actuating the valve within the analytical assumed time.
Response: Since specific operator actions to cooldown and depressurize the RCS were not used in the analysis, the ADVs were not used.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 26 SRXB-5: One of the key parameters that may significantly affect the results of the SG MTO analysis during an SGTR event is the initial SG water level, which is a function of the initial power level. The MTO analysis should consider the effects of the initial SG water levels corresponding to power levels that capture 95 percent of the operating time during a fuel cycle.
Also, for the range of the power levels that envelop 95 percent of the operating time, provide trending data for the corresponding SG water level to show that conservative initial SG water levels (with inclusion of measurement uncertainty and plant conditions perturbation) have been used in the steam release analysis.
Response: The SG overfill analysis used an initial SG mass corresponding to operation at 85%
of RTP. However, the MTO at the time the operators terminate AFW flow to the ruptured SG is not sensitive the initial SG mass. The only effect the initial SG mass has would be to change the time 35% NR is reached in the ruptured SG, and therefore, the time that operators terminate AFW flow to the ruptured SG.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 27 SRXB-6: List systems, components and instruments that are credited for consequence mitigation of the SGTR MTO analysis in accordance with the St Lucie 1 SGTR EOP. Discuss whether each system and component specified is safety grade. For SG ADVs and control valves, specify the valves motive power and discuss if the motive power and valve controls are safety grade. For non-safety grade systems and components, discuss whether safety grade backups are available that can be expected to function or provide the desired information within a time frame compatible with prevention of SGTR overfill or justify that non-safety grade systems and components can be used for the SGTR overfill analysis. Provide a list of all radiation monitors that could be used for identification of the SGTR event and the affected SG, and specify the quality and reliability of the instrumentation, as appropriate. If the EOP specifies SG sampling as a means of affected SG identification, provide the expected time period for obtaining the sample results and discuss the effects on the duration of the SGTR event.
Response: The systems actuated during the event analysis were the Reactor Protection System, Engineered Safety Feature Actuation System (ESFAS) (HPSI, AFW, and Charging) and steam line MSSVs. The Reactor Protection System, ESFAS and steam line MSSVs are safety grade components and/or systems. No additional systems, components, or instruments, other than ruptured SG NR level, were directly credited for consequence mitigation in the SGTR overfill calculation. The SG NR level feeds into the AFAS logic which is a part of safety grade AFW system.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 28 SRXB-7: List the single failure events considered in the SGTR overfill analysis and identify the worst single failure used in the analysis that resulted in a minimum MTO. Provide justification if single failure event is not considered in the analysis.
Response: Specific operator actions to cooldown and depressurize the RCS, equilibrate RCS and ruptured SG pressures, and terminate break flow (out to the time operators terminate AFW flow to the ruptured SG) were not modeled in the analysis in order to predict a conservative break flow rate. In combination with these assumptions, the limiting single failure is one that produces the highest AFW flow rate. The single failure used in the analysis was an assumed failure to close one AFW flow control valve on the ruptured SG (i.e. valve failed open on TD AFW pump after reaching the AFAS reset). The AFW flow control valves normally open on AFAS and close at the AFAS reset setpoint. The increased AFW flow, after a NR level of 35%
in the ruptured SG is reached, reduces the MTO at the time operators terminate AFW flow to the ruptured SG (i.e. 35% NR plus a 15 minute delay time for operator action to terminate the AFW flow).
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 29 3.0 SGTR Steam Release 3.1 Summary of Analysis The responses contained in this section are relative to the analysis of the steam releases for SGTR dose provided in St. Lucie Unit 1 EPU LAR Attachment 5, LR Section 2.8.5.6.2, Steam Generator Tube Rupture. In this analysis, most of the steam from the unaffected SG was diverted to be released through the MSSVs on theruptured SG steam line by not taking credit for the steam line reverse flow check valves. All the steam released from the MSSVs on the ruptured SG steam line was assumed to be from the ruptured SG resulting in conservative radioactive releases and hence conservative dose.
The SGTR analysis assumes operator action time of 45 minutes to isolate the affected SG.
Specifically, at 45 minutes, operators are assumed to stop the steam releases from the affected SG and are assumed to have taken control of RCS pressure, SG level and SG pressure.
Prior to 45 minutes, operators will be performing actions per EOPs to cooldown and depressurize the RCS via steam releases from the secondary system. These actions would tend to reduce the break flow and the radioactive releases, which would be beneficial from dose considerations. These actions are not credited in determining the radioactive releases from the affected SG in the EPU LAR analysis.
Prior to 45 minutes, with the offsite power available, operators would perform RCS cooldown using the SBCS, discharging the steam to the condenser. In the event of failure of SBCS, ADVs would be used to cooldown the RCS (instrument air available) with no additional failure assumed. For the case of LOOP, SBCS will not be available and the loss of instrument air will render ADVs inoperational from the control room. In this case, ADVs would be operated locally with manual action, with no assumed failure for local manual operation of ADV.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 30 3.2 Responses to Information Request SRXB-STM-1: Discuss the methodologies and computer codes used for the SGTR steam release analysis. If the methods were previously approved by U. S. NRC, list the NRC SEs approving the methods and address the compliance with the restrictions listed in the SEs. If the methods were not reviewed and approved by NRC, address acceptability of the methods.
Discuss the mitigation strategies used in the SGTR analysis to the conditions that the break flow is terminated or the shutdown cooling system can be used for decay heat removal.
Response: The purpose of the steam release analysis was to conservatively calculate the steam releases to the atmosphere for input to the radiological dose analyses. Detailed analyses were performed with the approved methodology (Reference 1) using the S-RELAP5 code. The S-RELAP5 code was used to model the key primary and secondary system components, RPS and ESF actuation trips and core kinetics. The nodalization, chosen parameters, conservative input and sensitivity studies were reviewed for applicability to this event in compliance with the SE for the Reference 1 topical report.
The nodalization used for the SGTR calculations supporting the EPU was specific to St.
Lucie Unit 1 and was consistent with the Reference 1 methodology. Nodalization diagrams used for the non- LOCA event analyses for the EPU are given in Figure 2 to Figure 4. The normal non-LOCA model lumps all of the tubes in a SG together. The SGTR model has one SG tube modeled explicitly, with the remainder lumped. The rupture model is a double-ended guillotine break in the single tube just above the tube sheet. Critical flow is modeled using the Moody model which provides a conservative model for choked flow.
The parameters and equipment states were chosen to provide a conservative estimate of the steam releases. The biasing and assumptions for key input parameters is discussed in response to SRXB-STM-2.
The S-RELAP5 code assessments documented in Reference 1 validated the ability of the code to predict the response of the primary and secondary systems during transient events. The assessments included the non-LOCA LOFT test suite. No additional code assessments were performed.
Subsequent to the isolation of ruptured SG, a heat balance was performed to determine the steam releases resulting from the cooldown of the plant to a RCS temperature of 212'F. The heat balance considered energy contributions from decay heat, heat structures and the fluid
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 31 within the primary and secondary systems. Steam releases were calculated for various cooldown rates, i.e., 2 0 °F/hr, 25°F/hr, 30°F/hr, 380F/hr and 100*F/hr. The steam releases were subsequently used in the dose analyses.
The analysis did not model specific operator actions prior to 45 minutes. It was assumed in the analysis that the operators would initiate EOP actions to isolate the ruptured SG by 45 minutes after which plant cooldown would commence. In accordance with the plant EOPs, the primary system cooldown to SDC system entry conditions was accomplished by the ADV in the intact SG.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 32 SRXB-STM-2: List the nominal values with measurement uncertainties and the corresponding values used in the SGTR steam release analysis for the following plant parameters:
- Initial power level
- Initial SG water inventory
- Initial pressurizer water volume
- Safety injection actuation pressure setpoint
- Safety injection flow versus RCS pressure
- Safety injection system pump delay time
- SG relief valve pressure setpoint
- AFW actuation setpoint and delay time
- AFW temperature and flow rate per SG
- IMSSV lift setpoints and steam flow rate of each MSSV
- Time of loss of offsite power
- ADV steam flow rate from intact and affected SGs
- Decay heat model and initial value in percentage of the rated power level This discussion should include rationale to show that the value of each of the above parameters used in the SGTR steam release analysis is conservative, resulting in a maximum steam release. In addition, provide a basis for the target cooldown temperature used in the analysis.
Response: St. Lucie Unit 1 EPU LAR Attachment 5, LR Section 2.8.5.6.2, Steam Generator Tube Rupture, provides an analysis of the steam releases for SGTR dose analyses (identified herein as the Reference Case). Steam releases from the ruptured SG considered all the steam released through the MSSVs on the ruptured SG steam line, although significant portion of this steam was from the unaffected SG (no credit for the reverse flow check valves). As a result, 182705 Ibm of contaminated steam was released from the ruptured SG. Conservative steam release from the ruptured SG resulted in a conservative calculation of dose.
Table 8 provides a discussion relative to the biasing of parameters for the steam release analyses. Key parameters were biased to maximize the environmental steam release. To
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 33 demonstrate the conservative nature of the steam release analysis, several supporting evaluations were performed to evaluate initial pressurizer pressure and level, AFW delay time, SI temperature, charging system actuation, charging flow temperature and RPS trip time.
Table 6 summarizes the parameter biasing used in each of the supporting evaluations. Key results are provided in Table 7. Table 7 provides the total integrated break flow and integrated steam releases from the time of trip to 45 minutes. Prior to trip, steam is assumed to flow through the turbine to the condenser. The key difference between the Reference Case and the supporting cases relative to dose is the difference in the steam releases assumed from the ruptured SG. In the Reference Case, 182705 Ibm of steam was assumed to be released from the ruptured SG, although significant portion of the steam released from the ruptured SG MSSVs was from the unaffected SG. That effluent would be treated (in the dose calculations) as if it all were at the ruptured SG activity level. In the supporting cases, roughly one-third of the total mass release was through the intact SG MSSVs; that flow would be at a much lower activity level. In the supporting cases, only approximately two-thirds of the total steam release would thus be at a high activity level and approximately one-third would be treated at a lower activity level. The maximum total steam release through the ruptured SG of [ ] Ibm (Case E) was much less than that for the Reference Case. These results indicate that the Reference Case with a higher ruptured SG steam release would remain conservative for dose consequences.
Once the ruptured SG was isolated at 45 minutes, the cooldown of the RCS initiated with the ADV in the intact SG. From 45 minutes to SDC, cooldown rates of 20°F/hr, 25 0 F/hr, 30°F/hr, 38°F/hr and 100°F/hr were assumed. The SDC entry conditions are defined as 325 0 F +/- 25 0 F and 267 psia. For the purposes of calculating conservative steam releases, the analysis assumed cooldown to a temperature of 212 0 F.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 34 Table 6 Supporting Evaluations Case Definitions K
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube RuDture Paqe 35 Table 7 Summary of Results for Supporting Evaluations of Input Parameter Biasing
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 36 Table 8 Input Parameter Biasing for the SGTR Steam Release Thermal-Hydraulic Analysis
(
I
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 37 Table 8 Input Parameter Biasing for the SGTR Steam Release Thermal-Hydraulic Analysis (Continued)
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rur)ture Paqe 38 Table 8 Input Parameter Biasing for the SGTR Steam Release Thermal-Hydraulic Analysis (Continued)
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'I
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 39 Table 8 Input Parameter Biasing for the SGTR Steam Release Thermal-Hydraulic Analysis (Continued)
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K 2
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 40 Table 9 Maximum HPSI Flow Rates for Steam Release Thermal-Hydraulic Analysis RCS Loop 1A Loop lB Loop 2A Loop 2B Pressure Flow Rate Flow Rate Flow Rate Flow Rate (psia) (gpm) (g (gpm) (pm 15 296 395 395 395 324 259 346 346 346 633 216 288 288 288 839 182 243 243 243 1045 140 187 187 187 1148 114 153 153 153 1158 112 149 149 149 1162 110 147 147 147 1251 80 107 107 107 1303 55 74 74 74
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 41 SRXB-STM-3: Identify operator actions and associated action times credited in the analysis.
Where an operator action is credited, confirm that such action is consistent with station procedure and action times are conservative, resulting in a maximum steam release.
Response: The analysis did not model specific operator actions prior to 45 minutes. Steam releases were assumed to occur via the ruptured SG MSSVs. It was assumed that the operators would initiate EOP actions to isolate the ruptured SG by 45 minutes after which plant cooldown would commence. In accordance with the plant EOPs, the primary system cooldown was accomplished by the ADV in the intact SG.
Table 10 contains an assessment of the SGTR EOP (1-EOP-04) actions relative to the SGTR steam releases. If the operators followed the EOPs, the results would be less limiting compared to the analysis where no operator action was assumed for 45 minutes.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Paqe 42 Table 10 Assessment of EOP Actions for SGTR Steam Releases EOP Action Disposition Ensure SI actuation SI is modeled to automatically actuate at time of reactor trip with no time delay in the analysis.
Maximize SI flow Maximum HPSI and charging flow are modeled in the analysis.
Ensure all charging pumps are running Cooldown to THOT < 510°F using ADVs The analysis modeled steam releases with no operator action to locally from both SGs. reduce the pressure difference between the RCS and the ruptured SG. If cooldown was initiated using the ADVs from both SGs, the steam release would be approx. split equally between the two SGs.
As the ADVs are operated to cooldown the RCS temperature, the operators depressurize the RCS as necessary to minimize the break flow as the ruptured SG pressure decreases with ADV operation. In the analysis, the conservative combination of steam releases from ruptured SG MSSVs with no operator action to reduce the pressure difference between the RCS and the ruptured SG is judged to bound cooldown using the ADVs for both SGs with RCS depressurization.
Depressurize the RCS The analysis does not model RCS depressurization since the effect
- Maintain RCS pressure within would be beneficial in reducing break flow.
pressure-temperature (PT) limits
- Maintain pressure less than 930 psia
- Maintain minimum pressure above value for RCP operation
- Maintain pressure within 50 psi of affected SG
- Operate main or aux. spray
- Throttle HPSI, if criteria met Protect main condenser on LOOP LOOP assumed in analysis. Releases are modeled to the atmosphere and not to the condenser.
Restore instrument air on LOOP ADVs operated locally until instrument air is restored. Analysis assumes ADVs don't operate prior to 45 minutes.
Isolate most affected SG if RCS hot leg Ruptured SG is assumed to be isolated at 45 minutes. Earlier temperature is less than 510'F isolation decreases the steam releases from the ruptured SG.
Maintain ruptured SG < 930 psia. The analysis did not model maintenance of the ruptured SG pressure
< 930 psia since the operators would also depressurize the RCS to <
930 psia and maintain RCS pressure within 50 psi of ruptured SG.
These actions would be beneficial in reducing break flow.
- Unisolated SG ADV used Analysis used ADV from intact SG for RCS cooldown
- Maximum cooldown is 30*F in any Analysis assumed various cooldown rates to SDC.
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period I
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube RuPture Paqe 43 Table 10 Assessment of EOP Actions for SGTR Steam Request (Continued)
EOP Action Disposition Maintain ruptured (isolated) SG Level < 90% The ruptured SG level does not reach 90% by 45 minutes in the NR analysis. Minimizing SG inventory maximizes the steam releases to
- Lower RCS pressure (most the atmosphere and increases the concentration of the radioactive preferred method) releases.
- Steam to atmosphere (least preferred method)
RCP restart, if criteria is met Analysis assumes natural circulation to increase the time to SDC entry conditions.
Cool and depressurize the isolated SG (in Multiple options are available to cool and depressurize the ruptured order listed) SG. The least preferred means from a radiological standpoint is
- If at least one RCP is running, then steaming to the atmosphere using the ADV or alternate steaming drain to 40% NR and feed to 90% paths. The analysis assumed that the cooldown to SDC entry NR conditions is not by steaming the ruptured SG to the atmosphere.
This is consistent with the EOP actions to cool and depressurize the
- If at least one RCP is running, then ruptured SG by means other than steaming to the atmosphere.
drain to 10% NR and control level at -10% NR
- Steam to condenser using SBCS
- Blowdown to 40% NR and feed to
-90% NR
- Cool by ambient losses
- Steam to atmosphere using ADV or turbine-driven AFW pump and alternate steaming paths Enter to SDC Operation SDC entry conditions assumed to be RCS P = 267 psia and RCS T =
212°F
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 44 SRXB-STM-4: Under the assumed LOOP conditions, address the functionality of each ADV.
Discuss what, if any, mitigating function of the ADV provides, and its capability to perform that function under assumed LOOP conditions. If the valve's actuation must be manual, provide information to show that the operator is capable of actuating the valve within the analytical assumed time.
Response: If LOOP occurs, instrument air is lost to both ADVs and the ADVs fail closed. The analysis assumes that steam releases occur solely from the SG MSSVs to 45 minutes at which time the operators isolate the ruptured SG. RCS cooldown is then modeled using the ADV on the intact SG. Once the ruptured SG is isolated at 45 minutes, it is assumed that the operators will have restored instrument air per the EOPs. If instrument air cannot be restored, the ADVs can be locally operated.
Scenarios run on the simulator will show that the local operation of ADV during a SGTR is achieved well within 45 minutes. The current Final Safety Analysis Report (FSAR) analysis supports an operator action time of 30 minutes. No changes to EOP actions result from the EPU analyses.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 45 SRXB-STM-5: List systems, components and instruments that are credited for consequence mitigation of the SGTR steam release analysis in accordance with the St Lucie 1 SGTR EOP.
Response: Up to 45 minutes, the systems actuated during the event analysis were the Reactor Protection System, ESFAS (HPSI, AFW, and Charging) and steam line MSSVs. The Reactor Protection System, ESFAS and steam line MSSVs are safety grade components and/or systems. No operator action was assumed for the first 45 minutes after which the ruptured SG is isolated in accordance with the EOPs. From 45 minutes to the time of SDC entry, it was assumed that the operators would cool the plant down to SDC entry conditions. During cooldown to SDC, the analysis assumed that energy removal would occur by way of atmospheric steam releases from the intact SG ADV.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 46 SRXB-STM-6: List the single failure events considered in the SGTR steam release analysis and identify the worst single failure used in the analysis that resulted in a maximum steam release. Provide justification if single failure event is not considered in the analysis.
Response: The steam release analysis considered a single failure in a mitigating system as a failure in the AFW system. The MD AFW pump associated with the ruptured SG was assumed to fail such that no AFW flow from the motor-driven pump was delivered to the ruptured SG.
Minimum AFW flow from the MD AFW pump associated with the intact SG was modeled. In addition, the TD AFW pump was not credited. Minimizing AFW flow increases the steam release through the MSSVs. Further, the analysis did not model the reverse flow check valves and considered all the steam release through the MSSVs on the ruptured SG steam line to be from the ruptured SG, maximizing the release of radioactivity from the ruptured SG.
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St. Lucie Unit 1 EPU - Information to Support NRC Review of Steam Generator Revision 0 Tube Rupture Page 47 4.0 References
- 1. EMF-2310(P)(A) Revision 1, SRP Chapter 15 Non-LOCA Methodology for Pressurized Water Reactors, Framatome ANP, May 2004.
St. Lucie Unit 1 L-2011-311 Docket No. 5-335 Attachment 3 ATTACHMENT 3 Response to NRC Reactor Systems Branch Request for Additional Information Regarding Extended Power Uprate License Amendment Request AREVA NP Application for Withholding Proprietary Information from Public Disclosure (Cover page plus 3 pages)
AFFIDAVIT COMMONWEALTH OF VIRGINIA )
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Kathleen Ann Bennett NOTARY PUBLIC, COMMONWEALTH OF VIRGINIA MY COMMISSION EXPIRES: 8/31/15 Reg. # 110864 KAU NIW TT~
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